0000004904 aep:PublicServiceCoOfOklahomaMember us-gaap:AccumulatedOtherComprehensiveIncomeMember 2017-12-31 0000004904 us-gaap:ElectricTransmissionMember aep:TransmissionOperationsMember 2019-01-01 2019-09-30 0000004904 us-gaap:PortionAtOtherThanFairValueFairValueDisclosureMember us-gaap:FixedIncomeFundsMember 2019-09-30 0000004904 aep:WholesaleTransmissionMember aep:VerticallyIntegratedUtilitiesMember 2019-01-01 2019-09-300000004904aep:RegulatoryAssetsPendingFinalRegulatoryApprovalMemberaep:VirginiaJurisdictionalAMRMetersMember2020-09-300000004904us-gaap:PortionAtOtherThanFairValueFairValueDisclosureMemberaep:IndianaMichiganPowerCoMember2019-12-310000004904aep:WholesaleGenerationMemberaep:AppalachianPowerCoMember2020-01-012020-09-30
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
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, 20192020
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 | | | | Delaware | | 51-0007707 |
333-217143 | | AEP TRANSMISSION COMPANY, LLC | | Delaware | | | | Delaware | | 46-1125168 |
1-3457 | | APPALACHIAN POWER COMPANY | | Virginia | | | | Virginia | | 54-0124790 |
1-3570 | | INDIANA MICHIGAN POWER COMPANY | | Indiana | | | | Indiana | | 35-0410455 |
1-6543 | | OHIO POWER COMPANY | | Ohio | | | | Ohio | | 31-4271000 |
0-343 | | PUBLIC SERVICE COMPANY OF OKLAHOMA | | Oklahoma | | | | Oklahoma | | 73-0410895 |
1-3146 | | SOUTHWESTERN ELECTRIC POWER COMPANY | | Delaware | | | | Delaware | | 72-0323455 |
| | 1 Riverside Plaza, | Columbus, | OhioColumbus, | 43215-2373Ohio | 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 | | New YorkThe NASDAQ Stock ExchangeMarket LLC |
American Electric Power Company Inc. | | 6.125% Corporate Units | | AEP PR BAEPPL | | New YorkThe NASDAQ Stock ExchangeMarket 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 | ☐ | | | | |
|
| | | | | |
| | | | | | | |
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 24, 2019 |
| |
American Electric Power Company, Inc. | 493,951,812 |
|
| ($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 | 7,536,640 |
|
| ($18 par value) |
|
| |
(a) | 100% interest is held by AEP Transmission Holding Company, LLC, a wholly-owned subsidiary of American Electric Power Company, Inc. |
|
| | | | |
| Number of shares of common stock outstanding of the Registrants as of |
| October 22, 2020 |
| |
American Electric Power Company, Inc. | 496,386,252 | |
| ($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, 20192020 | | | | |
| | | | |
| | | | 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. Each registrant makes no representation as to information relating to the other registrants. | | | | |
GLOSSARY OF TERMS
When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below.
|
| | | | | | | |
Term | | Meaning |
| | |
AEGCo | | AEP Generating Company, an AEP electric utility subsidiary. |
AEP | | American Electric Power Company, Inc., an investor-owned electric public utility holding company which includes American Electric Power Company, Inc. (Parent) and majority owned consolidated subsidiaries and consolidated affiliates. |
AEP Credit | | AEP Credit, Inc., a consolidated VIE of AEP which securitizes accounts receivable and accrued utility revenues for affiliated electric utility companies. |
AEP System | | American Electric Power System, an electric system, owned and operated by AEP subsidiaries. |
AEP Texas | | AEP Texas Inc., an AEP electric utility subsidiary. |
AEP Transmission Holdco | | AEP Transmission Holding Company, LLC, a wholly-owned subsidiary of AEP. |
AEP Wind Holdings LLC | | Acquired in April 2019 as Sempra Renewables LLC, develops, owns and operates, or holds interests in, wind generation facilities in the United States. |
AEPEP | | AEP Energy Partners, Inc., a subsidiary of AEP dedicated to wholesale marketing and trading, hedging activities, asset management and commercial and industrial sales in deregulated markets. |
AEPRO | | AEP River Operations, LLC, a commercial barge operation sold in November 2015. |
AEPSC | | American Electric Power Service Corporation, an AEP service subsidiary providing management and professional services to AEP and its subsidiaries. |
AEPTCo | | AEP Transmission Company, LLC, a wholly-owned subsidiary of AEP Transmission Holdco, is an intermediate holding company that owns the State Transcos. |
AEPTCo Parent | | AEP Transmission Company, LLC, the holding company of the State Transcos within the AEPTCo consolidation. |
AFUDC | | Allowance for Equity Funds Used During Construction. |
AGR | | AEP Generation Resources Inc., a competitive AEP subsidiary in the Generation & Marketing segment. |
ALJAMI | | Administrative Law Judge.Advanced Metering Infrastructure. |
AOCI | | Accumulated Other Comprehensive Income. |
APCo | | Appalachian Power Company, an AEP electric utility subsidiary. |
Appalachian Consumer Rate Relief Funding | | Appalachian Consumer Rate Relief Funding LLC, a wholly-owned subsidiary of APCo and a consolidated VIE formed for the purpose of issuing and servicing securitization bonds related to the under-recovered ENEC deferral balance. |
APSC | | Arkansas Public Service Commission. |
ARAM | | Average Rate Assumption Method, an IRS approved method used to calculate the reversal of Excess ADIT for rate-making purposes. |
ARO | | Asset Retirement Obligations. |
| | |
ASU | | Accounting Standards Update. |
CAA | | Clean Air Act. |
CLECO | | Central Louisiana Electric Company, a nonaffiliated utility company. |
Cardinal Operating Company | | A jointly-owned organization between AGR and a nonaffiliate. The nonaffiliate operates the three unit Cardinal Plant and wholly-owns Units 2 and 3. |
CARES Act | | Coronavirus Aid, Relief, and Economic Security Act signed into law in March 2020. |
CLECO | | Central Louisiana Electric Company, a nonaffiliated utility company. |
CO2 | | Carbon dioxide and other greenhouse gases. |
Conesville Plant | | A generation plant consisting of three coal-fired generating units totaling 1,695 MW located in Conesville, Ohio. The plant is jointly-owned by AGR and a nonaffiliate. |
Cook Plant | | Donald C. Cook Nuclear Plant, a two-unit, 2,2782,288 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. |
CWA | | Clean Water Act. |
CWIP | | Construction Work in Progress. |
| | | | | | | | |
Term | | Meaning |
| | |
DCC Fuel | | DCC Fuel VIII, DCC Fuel IX, DCC Fuel X, DCC Fuel XI, DCC Fuel XII, DCC Fuel XIII, DCC Fuel XIV and DCC Fuel XIII,XV, consolidated VIEs formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M. |
|
Desert Sky | | |
Term | | Meaning |
| | 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. |
ENEC | | Expanded Net Energy Cost. |
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. |
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. |
Global Settlement | | In February 2017, the PUCO approved a settlement agreement filed by OPCo in December 2016 which resolved all remaining open issues on remand from the Supreme Court of Ohio in OPCo’s 2009 - 2011 and June 2012 - May 2015 ESP filings. It also resolved all open issues in OPCo’s 2009, 2014 and 2015 SEET filings and 2009, 2012 and 2013 Fuel Adjustment Clause Audits. |
I&M | | Indiana Michigan Power Company, an AEP electric utility subsidiary. |
IRS | | Internal Revenue Service. |
IURC | | Indiana Utility Regulatory Commission. |
KGPCo | | Kingsport Power Company, an AEP electric utility subsidiary. |
KPCo | | Kentucky Power Company, an AEP electric utility subsidiary. |
| | |
KPSC | | Kentucky Public Service Commission. |
KWh | | Kilowatt-hour. |
LPSC | | Louisiana Public Service Commission. |
MATS | | Mercury and Air Toxic Standards. |
MISO | | Midcontinent Independent System Operator. |
MMBtu | | Million British Thermal Units. |
MPSC | | Michigan Public Service Commission. |
MTM | | Mark-to-Market. |
MW | | Megawatt. |
MWh | | Megawatt-hour. |
NAAQS | | National Ambient Air Quality Standards. |
Nonutility Money Pool | | Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain nonutility subsidiaries. |
North Central Wind Energy Facilities | | A proposed joint PSO and SWEPCo project, which includes three Oklahoma wind facilities totaling approximately 1,485 MWs of wind generation. |
NO2
| | Nitrogen dioxide. |
NOx
| | Nitrogen oxide. |
NPDES | | National Pollutant Discharge Elimination System. |
NSR | | New Source Review. |
|
| | | | | | | |
Term | | Meaning |
| | |
OATTNO2 | | Nitrogen dioxide. |
NOx | | Nitrogen oxide. |
NPDES | | National Pollutant Discharge Elimination System. |
NSR | | Open Access Transmission Tariff.New Source Review. |
OCC | | Corporation Commission of the State of Oklahoma. |
Ohio Phase-in-Recovery Funding | | Ohio Phase-in-Recovery Funding LLC, a wholly-owned subsidiary of OPCo and a consolidated VIE formed for the purpose of issuing and servicing securitization bonds related to phase-in recovery property. |
Oklaunion Power Station | | A single unit coal-fired generation plant totaling 650 MW located in Vernon, Texas. The plant is jointly-owned by AEP Texas, PSO and certain nonaffiliated entities. |
OPCo | | Ohio Power Company, an AEP electric utility subsidiary. |
OPEB | | Other Postretirement Benefits. |
OSS | | Off-system Sales. |
OTC | | Over-the-counter. |
OVEC | | Ohio Valley Electric Corporation, which is 43.47% owned by AEP. |
Parent | | American Electric Power Company, Inc., the equity owner of AEP subsidiaries within the AEP consolidation. |
PATH-WV | | PATH West Virginia Transmission Company, LLC, a joint venture owned 50% by FirstEnergy and 50% by AEP. |
PJM | | Pennsylvania – New Jersey – Maryland regional transmission organization. |
PM | | Particulate Matter. |
PPA | | Purchase Power and Sale Agreement. |
PSO | | Public Service Company of Oklahoma, an AEP electric utility subsidiary. |
PTC | | Production Tax Credits. |
PUCO | | Public Utilities Commission of Ohio. |
PUCT | | Public Utility Commission of Texas. |
Racine | | A generation plant consisting of two hydroelectric generating units totaling 47.548 MWs located in Racine, Ohio and owned by AGR. |
Reference Rate Reform | | The global transition away from referencing the London Interbank Offered Rate and other interbank offered rates, and toward new reference rates that are more reliable and robust. |
Registrant Subsidiaries | | AEP subsidiaries which are SEC registrants: AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo. |
Registrants | | SEC registrants: AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo. |
Restoration Funding | | AEP Texas Restoration Funding LLC, a wholly-owned subsidiary of AEP Texas and a consolidated VIE formed for the purpose of issuing and servicing securitization bonds related to storm restoration in Texas primarily caused by Hurricane Harvey. |
Risk Management Contracts | | Trading and non-trading derivatives, including those derivatives designated as cash flow and fair value hedges. |
Rockport Plant | | A generation plant, consisting of two 1,310 MW coal-fired generating units near Rockport, Indiana. AEGCo and I&M jointly-own Unit 1. In 1989, AEGCo and I&M entered into a sale-and-leaseback transaction with Wilmington Trust Company, an unrelated, unconsolidated trustee for Rockport Plant, Unit 2. |
ROE | | Return on Equity. |
RPM | | Reliability Pricing Model. |
RSR | | Retail Stability Rider. |
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. |
Santa Rita East | | Santa Rita East Wind Holdings, LLC, a consolidated VIE whose sole purpose is to own and operate a 302.4 MW wind generation facility in west Texas in which AEP owns a 75% interest. |
SCRSEC | | Selective Catalytic Reduction, NOx reduction technology at Rockport Plant.
|
SEC | | U.S.United States Securities and Exchange Commission. |
SEET | | Significantly Excessive Earnings Test. |
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. |
| | | | | | | | |
Term | | Meaning |
| | |
SNF | | Spent Nuclear Fuel. |
SO2 | | Sulfur dioxide. |
SPP | | Southwest Power Pool regional transmission organization. |
|
| | |
Term | | Meaning |
| | |
SSO | | Standard service offer. |
State Transcos | | AEPTCo’s seven wholly-owned, FERC regulated, transmission only electric utilities, which are geographically aligned with AEP’s existing utility operating companies. |
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. |
TCC | | Formerly AEP Texas Central Company, now a division of AEP Texas. |
Texas Restructuring Legislation | | Legislation enacted in 1999 to restructure the electric utility industry in Texas. |
Transition Funding | | AEP Texas Central Transition Funding II LLC and AEP Texas Central Transition Funding III LLC, wholly-owned subsidiaries of TCC and consolidated VIEs formed for the purpose of issuing and servicing securitization bonds related to Texas Restructuring Legislation. |
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. |
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 600 MW coal-fired plant in Arkansas that is 73% owned by SWEPCo. |
UPA | | Unit Power Agreement. |
Utility Money Pool | | Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain utility subsidiaries. |
VIE | | Variable Interest Entity. |
Virginia SCC | | Virginia State Corporation Commission. |
Wind Catcher Project | | Wind Catcher Energy Connection Project, a joint PSO and SWEPCo project that was cancelled in July 2018. The project included the acquisition of a wind generation facility, totaling approximately 2,000 MW of wind generation, and the construction of a generation interconnection tie-line totaling approximately 350 miles. |
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 “Item 7“Part 1 – Item 2 Management’s Discussion and Analysis of Financial Condition and Results of Operations” of the 2018 Annual Report,this quarterly report, but there are others throughout this document which may be identified by words such as “expect,” “anticipate,” “intend,” “plan,” “believe,” “will,” “should,” “could,” “would,” “project,” “continue” and similar expressions, and include statements reflecting future results or guidance and statements of outlook. These matters are subject to risks and uncertainties that could cause actual results to differ materially from those projected. Forward-looking statements in this document are presented as of the date of this document. Except to the extent required by applicable law, management undertakes no obligation to update or revise any forward-looking statement. Among the factors that could cause actual results to differ materially from those in the forward-looking statements are:
|
| | | | |
• | Changes in economic conditions, electric market demand and demographic patterns in AEP service territories. |
• | The impact of pandemics, including COVID-19, and any associated disruption of AEP’s business operations due to impacts on economic or market conditions, electricity usage, employees, customers, service providers, vendors and suppliers. |
• | Inflationary or deflationary interest rate trends. |
• | Volatility in the financial markets, particularly developments affecting the availability or cost of capital to finance new capital projects and refinance existing debt. |
• | The availability and cost of funds to finance working capital and capital needs, particularly during periods when the time lag between incurring costs and recovery is long and the costs are material. |
• | Decreased demand for electricity. |
• | Weather conditions, including storms and drought conditions, and the ability to recover significant storm restoration costs. |
• | The cost of fuel and its transportation, the creditworthiness and performance of fuel suppliers and transporters and the cost of storing and disposing of used fuel, including coal ash and SNF. |
• | The availability of fuel and necessary generation capacity and the performance of generation plants. |
• | The ability to recover fuel and other energy costs through regulated or competitive electric rates. |
• | The ability to build or acquire renewable generation, transmission lines and facilities (including the ability to obtain any necessary regulatory approvals and permits) when needed at acceptable prices and terms and to recover those costs. |
• | New legislation, litigation and government regulation, including oversight of nuclear generation, energy commodity trading and new or heightened requirements for reduced emissions of sulfur, nitrogen, mercury, carbon, soot or PM and other substances that could impact the continued operation, cost recovery and/or profitability of generation plants and related assets. |
• | Evolving public perception of the risks associated with fuels used before, during and after the generation of electricity, including coal ash and nuclear fuel. |
• | Timing and resolution of pending and future rate cases, negotiations and other regulatory decisions, including rate or other recovery of new investments in generation, distribution and transmission service and environmental compliance. |
• | Resolution of litigation. |
• | The ability to constrain operation and maintenance costs. |
• | Prices and demand for power generated and sold at wholesale. |
• | Changes in technology, particularly with respect to energy storage and new, developing, alternative or distributed sources of generation. |
• | The ability to recover through rates any remaining unrecovered investment in generation units that may be retired before the end of their previously projected useful lives. |
• | Volatility and changes in markets for coal and other energy-related commodities, particularly changes in the price of natural gas. |
• | Changes in utility regulation and the allocation of costs within RTOs including ERCOT, PJM and SPP. |
• | Changes in the creditworthiness of the counterparties with contractual arrangements, including participants in the energy trading market. |
• | Actions of rating agencies, including changes in the ratings of debt. |
• | The impact of volatility in the capital markets on the value of the investments held by the pension, OPEB, captive insurance entity and nuclear decommissioning trust and the impact of such volatility on future funding requirements. |
| | | | | |
• | Accounting standards periodically issued by accounting standard-setting bodies. |
|
• | |
• | Other risks and unforeseen events, including wars, the effects of terrorism (including increased security costs), embargoes, naturally occurring and human-caused fires, cyber security threats and other catastrophic events. |
• | The ability to attract and retain the requisite work force and key personnel. |
The forward-looking statements of the Registrants speak only as of the date of this report or as of the date they are made. The Registrants expressly disclaim any obligation to update any forward-looking information. For a more detailed discussion of these factors, see “Risk Factors” in Part I of the 20182019 Annual Report and in Part II of this report.
Investors should note that the Registrants announce material financial information in SEC filings, press releases and public conference calls. Based on guidance from the SEC, the Registrants may use the Investors section of AEP’s website (www.aep.com) to communicate with investors about the Registrants. It is possible that the financial and other information posted there could be deemed to be material information. The information on AEP’s website is not part of this report.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
EXECUTIVE OVERVIEW
COVID-19
In March 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 could reduce future demand for energy, particularly from commercial and industrial customers. Although AEP cannot predict the severity or duration of the impact of the COVID-19 pandemic, AEP currently anticipates a 2.7% reduction in weather-normalized retail sales volume in 2020 as compared to the prior year. For the nine months ended September 30, 2020, AEP experienced a reduction in weather-normalized retail sales volume of 3.0% as compared to the same period in the prior year primarily driven by a 7.0% decrease in the industrial customer class and a 4.9% decrease in the commercial customer class offset by an increase in demand of 2.6% from the residential customer class. The reduction in weather-normalized retail sales volume of 3.0% did not result in a significant decrease in the corresponding retail margins for the nine months ended 2020 as the increase in higher margin residential sales volumes partially offset the decreases in the industrial and commercial sales volumes. Furthermore, the rate design for certain industrial customers includes demand provisions designed to cover the fixed portion of utility costs minimizing the impact of the fluctuations in usage on revenues. AEP’s load forecast is highly dependent on many factors including, but not limited to, the speed and strength of economic recovery and the extent and duration of the next wave of COVID-19 infection. If the severity of the economic disruption increases, AEP’s future results of operations, financial condition, and cash flows could be further adversely impacted. See Customer Demand for additional information.
During the first quarter of 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. During the third and the fourth quarter of 2020, certain state regulators began to lift restrictions on disconnects. As of September 30, 2020, AEP resumed disconnections in its regulated jurisdictions with the exception of Virginia, West Virginia, Kentucky, Arkansas, Louisiana and Tennessee. AEP’s electric operating companies continue to work with regulators and stakeholders in these states and management currently anticipates resuming customary disconnection practices in the fourth quarter of 2020. However, this timing could change if there is new legislation or other regulatory directives issued in the future. 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. During the third quarter of 2020, the Registrants reviewed current collections experience with historical trends, specifically reviewing metrics such as cash collections, days sales outstanding, daily customer deposits, and aging summaries. In addition, the Registrants reviewed historical loss information generally comprised of a rolling 12-month average, in conjunction with a qualitative assessment of elements that impact the collectability of receivables, such as changes in economic factors, regulatory matters, industry trends, customer credit factors, payment plan options and other programs available to customers. Based on this review, the Registrants’ accounts receivable aging was negatively impacted primarily due to the suspension of customer disconnects. However, as disconnect moratoriums ended or are approaching their end dates, AEP is proactively engaging with customers to collect payments or establish payment arrangements for outstanding balances. As of September 30, 2020, AEP currently does not expect the deterioration in 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 affecting suspensions of disconnections and its impact on customer collections. Further deterioration in AEP’s ability to collect from its customers could significantly impact AEP’s future results of operations, financial conditions, and cash flows.
In May 2020, AEP Credit amended its receivables securitization agreement to increase the eligibility criteria related to aged receivable requirements for the participating affiliated utility subsidiaries in response to the COVID-19 pandemic. As of September 30, 2020, the affiliated utility subsidiaries are in compliance with all requirements under the agreement. To the extent that an affiliated utility subsidiary is deemed ineligible under the agreement, receivables would no longer be purchased by the bank conduits and the Registrants would need to rely on additional sources of funding for operation and working capital, which may adversely impact liquidity.
The Registrants have worked with their state commissions to achieve deferral authority for incremental expenses incurred due to COVID-19. All of AEP’s regulated jurisdictions have issued initial COVID-19 orders with the exception of Tennessee. If any costs related to COVID-19 are not recoverable, it could reduce future net income and cash flows and impact financial condition.
The effects of the continued COVID-19 pandemic and related government responses could also include extended disruptions to supply chains, reduced labor availability, reduced dispatch for certain generation assets and a prolonged reduction in economic activity. These effects could have a variety of adverse impacts to the Registrants, including their ability to operate their facilities. As of September 30, 2020, there were no material adverse impacts to the Registrants’ operations and supplier contracts due to COVID-19. AEP will continue to monitor developments affecting facility operations and will take additional actions necessary in order to mitigate adverse impacts to the Registrants’ future results of operations, financial condition, and cash flows.
In addition, the economic disruptions caused by COVID-19 could also adversely impact the impairment risks for certain long-lived assets, equity method investments and goodwill. AEP evaluated these impairment considerations and determined that no such impairments existed as of September 30, 2020.
Market volatility and reduction in collections coupled with longer collection periods due to the expansion of customer payment arrangements could reduce cash from operations and cause an adverse impact to liquidity. During the first nine months of 2020, AEP increased its liquidity position to mitigate the market risk and the collections risk due to COVID-19. During the first quarter of 2020, AEP entered into a $1 billion 364–day term loan to reduce reliance on commercial paper and help mitigate potential future liquidity risks. In addition, during the first nine months of 2020, AEP issued approximately $4.0 billion in long-term debt. As of September 30, 2020, AEP’s available liquidity was $3.8 billion. Management believes the Registrants have adequate liquidity under existing credit facilities. In the first quarter of 2020, AEP shifted capital expenditures of $500 million out of 2020 into future periods to further mitigate adverse liquidity impacts. In the second quarter of 2020, AEP reinstated $100 million of capital expenditures back into 2020 that had previously been deferred. To the extent that future access to the capital markets or the cost of funding is adversely affected by COVID-19, future results of operations, financial condition, and cash flows may be adversely impacted.
In March 2020, the CARES Act was signed into law. The CARES Act includes tax relief provisions such as: (a) an Alternative Minimum Tax (AMT) Credit Refund, (b) a 5-year net operating losses (NOL) carryback from years 2018-2020 and (c) delayed payment of employer payroll taxes. In May 2020, the House passed the "Health and Economic Recovery Omnibus Emergency Solutions Act" (HEROES Act) pending decision by the Senate. If enacted, the HEROES Act would disallow NOL carrybacks to any tax year beginning before January 1, 2018. Pursuant to the CARES Act, AEP, APCo and OPCo requested and in July received a $20 million, $7 million and $9 million, respectively, refund of AMT credit. In the third quarter of 2020, AEP also requested a $95 million refund of taxes paid in 2014 under the 5-year NOL carryback provision of the CARES Act. AEP carried back an NOL generated on the 2019 Federal income 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 change in the corporate income tax rates between the two periods, AEP realized a tax benefit of $52 million, recorded discretely, primarily at the Generation & Marketing segment. On October 1, 2020, after AEP filed its request with the IRS, the House passed a revised version of the HEROES Act; which similar to the original legislation would disallow NOL carryback to years prior to 2018. Management will continue to monitor the potential impact of this legislation. The Registrants are currently deferring payments of the employer share of payroll taxes for the period March 27, 2020 through December 31, 2020 and will pay 50% of the obligation by December 31, 2021 and the remaining 50% by December 31, 2022. As of September 30, 2020, the Registrants have deferred $32 million of the employer share of payroll taxes and anticipate to defer approximately $50 million by December 31, 2020.
The Registrants are taking steps to mitigate the potential risks to customers, suppliers and employees posed by the spread of COVID-19. The Registrants have updated and implemented a company-wide pandemic plan to address specific aspects of COVID-19. This plan guides emergency response, business continuity, and the precautionary measures AEP is taking on behalf of its employees and the public. The Registrants have taken extra precautions for employees who work in the field and for employees who work in their facilities, and have work from home policies where appropriate. The Registrants will continue to monitor developments affecting both their workforce and customers, and will take additional precautions that management determines are necessary in order to mitigate the impacts. AEP continues to focus on providing safe, uninterrupted service to its customers, which includes the implementation of strong physical and cyber-security measures to ensure that its systems remain functional with a partially remote workforce. As of September 30, 2020, there has been no material adverse impact to the Registrants’ business operations and customer service due to remote work. Management will continue to review and modify plans as conditions change. Despite efforts to manage these impacts to the Registrants, the ultimate impact of COVID-19 also depends on factors beyond management’s knowledge or control, including the duration and severity of this outbreak as well as third-party actions taken to contain its spread and mitigate its public health effects. Therefore, management cannot estimate the potential future impact to financial position, results of operations and cash flows, but the impacts could be material.
Customer Demand
AEP’s weather-normalized retail sales volumes for the third quarter of 2019 were flat2020 decreased by 2.6% from the third quarter of 2019. Weather-normalized residential sales increased by 3.8% in the third quarter of 2020 from the third quarter of 2019. AEP’s third quarter 2020 industrial sales volumes decreased by 7.8% compared to the third quarter of 2018. AEP’s third quarter 2019 industrial sales decreased by 1.1% compared to the third quarter of 2018.2019. The decline in industrial sales was spread across most operating companies and most industries outside of the oil and gas sector.many industries. Weather-normalized residential sales increased 0.7% while weather-normalized commercial sales increased by 0.4%decreased 4.6% in the third quarter of 2019 compared to2020 from the third quarter of 2018.2019.
AEP’s weather-normalized retail sales volumes for the nine months ended September 30, 20192020 decreased by 0.6%3.0% compared to the nine months ended September 30, 2018.2019. Weather-normalized residential sales increased by 2.6% for the nine months ended September 30, 2020 compared to the nine months ended September 30, 2019. AEP’s industrial sales volumes for the nine months ended September 30, 20192020 decreased 1.4%7.0% compared to the nine months ended September 30, 2018.2019. The decline in industrial sales was spread across most operating companies and most industries outside of the oil and gas sector.many industries. Weather-normalized commercial sales decreased 0.7%4.9% for the nine months ended September 30, 20192020 compared to the nine months ended September 30, 2018,2019.
As a result of the impact of COVID-19, AEP revised its forecast for 2020 weather-normalized retail sales volumes in April 2020 and September 2020 from the forecast presented in the 2019 10-K. In 2020, AEP currently anticipates weather-normalized retail sales volumes will decrease by 2.7%. AEP expects industrial class sales volumes to decrease by 6.5% in 2020, while weather-normalized residential sales increasedvolumes are projected to increase by 0.2%3.1%. Finally, AEP currently projects weather-normalized commercial sales volumes to decrease by 4.8%.
(a)Percentage change for the year ended December 31, 2019 as compared to the year ended December 31, 2018.
(b)As presented in the 2019 AEP 10-K: Forecasted percentage change for the year ending December 31, 2020 compared to the year ended December 31, 2019.
(c)Revised for the impact of COVID-19 in April 2020: Forecasted percentage change for the year ending December 31, 2020 compared to the year ended December 31, 2019.
(d)Revised for the impact of COVID-19 in September 2020: Forecasted percentage change for the year ending December 31, 2020 compared to the year ended December 31, 2019.
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 MayMarch 2020, APCo submitted its 2017-2019 Virginia triennial earnings review filing and base rate case with the Virginia SCC as required by state law. APCo requested a $65 million annual increase in base rates based upon a proposed 9.9% ROE. Triennial reviews are subject to an earnings test, which provides that 70% of any earnings in excess of 70 basis points above APCo’s Virginia SCC authorized ROE would be refunded to customers. In such case, the Virginia SCC could also lower APCo’s Virginia retail base rates on a prospective basis. Virginia law provides that costs associated with asset impairments of retired coal generation assets, or automated meters, or both, which a utility records as an expense, shall be attributed to the test periods under review in a triennial review proceeding, and be deemed recovered. In 2015, APCo retired the Sporn Plant, the Kanawha River Plant, the Glen Lyn Plant, Clinch River Unit 3 and the coal portions of Clinch River Units 1 and 2 (collectively, the retired coal-fired generation assets). The net book value of the Virginia jurisdictional share of these plants was $93 million before cost of removal, including materials and supplies inventory and ARO balances. Based on management’s interpretation of Virginia law and more certainty regarding APCo’s triennial revenues, expenses and resulting earnings upon reaching the end of the three-year review period, APCo recorded a pretax expense of $93 million related to its previously retired coal-fired generation assets in December 2019. As a result, management deems these costs to be substantially recovered by APCo during the triennial review period. Inclusive of the Virginia jurisdictional share of the $93 million expense associated with APCo’s retired coal-fired generation assets, APCo calculated its 2017-2019 Virginia earnings for the triennial period to be below the authorized ROE range. In July 2020, a certain intervenor filed testimony asserting that APCo had a revenue surplus of $23 million for its filed rate year based upon the intervenor’s recommended ROE of 8.75%. In addition, this intervenor submitted corrected testimony contending APCo’s earned return for the Triennial period was 11.12%, which equates to a potential refund to customers of $34 million. See “2017-2019 Virginia Triennial Review” section of Note 4 for a full listing of proposed adjustments and disallowances by intervenors. In August and September 2020, the Virginia staff filed testimony supporting an annual APCo Virginia jurisdictional revenue deficiency of $17 million based upon an ROE of 8.73%. However, Virginia staff contends APCo’s earned return for the triennial period was 9.55%, which is above the 9.42% midpoint of APCo’s authorized ROE range. Based on Virginia law, a Virginia SCC order finding an earned ROE above the midpoint would prevent APCo from receiving a prospective increase in Virginia retail rates. In addition, the staff recommended that APCo: (a) reverse the pretax Virginia jurisdictional share of the $93 million expense recorded in December 2019 AEPfor its retired coal-fired generation assets and instead amortize the retired assets over a 10-year period beginning in 2015, (b) implement 2017 depreciation study rates effective January 2018 which would increase depreciation expense by $13 million and $15 million in 2018 and 2019, respectively, (c) implement 2019 depreciation study rates effective January 2020 which would increase depreciation expense by $18 million annually starting January 1, 2020 and (d) remove $9 million of major storm expenses and $12 million of coal combustion by-product expenses from the requested annual increase in base rates. APCo expects to receive an order in November 2020.
•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 September 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. SWEPCo is currently evaluating recovery options for the storm damage in its Arkansas jurisdiction. As of September 30, 2020, management estimates that SWEPCo has incurred incremental other operation and maintenance expenses of $69 million ($67 million of which has been
deferred as a regulatory asset related to the Louisiana jurisdiction) and incremental capital expenditures of $31 million ($30 million related to the Louisiana jurisdiction).
•2012 Texas Base Rate Case - In 2012, SWEPCo filed a request with the PUCT for a $56 millionto increase annual increase inbase rates based upon a proposed 10.5% return on common equity.primarily due to the completion of the Turk Plant. In 2013, the PUCT issued an order affirming the prudence of the Turk Plant. In July 2018, the Texas Third Court of Appeals reversed the PUCT’s judgment affirming the prudence of the Turk Plant and Augustremanded the issue back to the PUCT. In January 2019, SWEPCo and the PUCT Stafffiled petitions for review with the Texas Supreme Court. In the fourth quarter of 2019 and first quarter of 2020, SWEPCo and various intervenors filed testimony that includes recommended disallowances that could potentially result in write-offs exceeding $450 million. The PUCT staff's recommended disallowances primarily consisted of $85 million in capital incentives and $26 million for capitalized vegetation management expenses. The intervenors recommended disallowances primarily consisted of (a) $173 million for a newly constructed transmission operations center and other service centers, (b) $94 million for Hurricane Harvey costs, (c) $36 million for capitalized cross arms and (d) $21 million for capitalized plant costs related to unreimbursed damages to assets caused by third-parties. In addition, one intervenor recommended AEP Texas refund $115 million of Excess ADIT, which includes $2 million in interest, related to previously owned deregulated generation assets. AEP Texas recorded $113 million as a favorable adjustment to income tax expense in 2017 as a result of Tax Reform. The PUCT is expected to issue an order on the case by the first quarter of 2020.
In May 2019, I&M filed a requestbriefs with the IURC for a $172 million annual increase. The requested increase in Indiana rates would be phased in through January 2021 and is based upon a proposed 10.5% return on common equity.Texas Supreme Court. In August 2019, various intervenors filed testimony that includes recommended disallowances that could potentially result in write-offs2020, the Texas Supreme Court granted SWEPCo’s petition for review and oral arguments were scheduled for December 2020. As of $41 million related toSeptember 30, 2020, the remainingnet book value of existing IndianaTurk Plant was $1.4 billion, before cost of removal, including materials and supplies inventory and CWIP. SWEPCo’s Texas jurisdictional meters and $11 million associated with certain Cookshare of the Turk Plant study costs. The IURCinvestment is expected to issue an order on the case by the first quarter of 2020.approximately 33%.
| |
• | Virginia Legislation Affecting Earnings Reviews - In March 2018, Virginia enacted legislation requiring APCo to file its next generation and distribution base rate case by March 31, 2020 using 2017, 2018 and 2019 test years (triennial review). Triennial reviews are subject to an earnings test which provides that 70% of any earnings exceeding 70 basis points over the Virginia SCC authorized return on common equity would be refunded to customers or be used to lower APCo’s Virginia retail base rates on a prospective basis. The Virginia legislation also states that, under certain circumstances, costs associated with asset impairments related to early retirement determinations made by a utility for generation facilities fueled by coal, natural gas or oil or for automated meters be considered fully recovered in the period recorded. Management has reviewed APCo’s actual and forecasted earnings for the triennial period and concluded that it is not probable, but is reasonably possible, that APCo will over-earn in Virginia during the 2017-2019 triennial period. Due to various uncertainties, including weather, storm restoration, weather-normalized demand and potential customer shopping during 2019, management cannot estimate a range of potential APCo Virginia over-earnings during the 2017-2019 triennial period.
|
| |
• | Virginia Staff Depreciation Study Request - In November 2018, Virginia staff recommended that APCo implement new Virginia jurisdictional depreciation rates effective January 1, 2018 based on APCo’s depreciation study that was prepared at Virginia staff’s request using December 31, 2017 APCo property balances. Implementation of those depreciation rates would result in a $21 million pretax increase in annual depreciation expense with no corresponding increase in retail base rates. In December 2018, APCo submitted a response to the Virginia Staff stating that it was inappropriate for APCo to change Virginia depreciation rates in advance of APCo’s triennial review, citing the Virginia SCC’s November 2014 order to not change APCo’s Virginia depreciation rates until APCo’s next base rate case/review.
|
| |
• | 2020 Increase in West Virginia Retail Rates for WPCo 17.5% Merchant Share of Mitchell Plant - In January 2015, the WVPSC approved a settlement agreement in which 82.5% of the costs associated with WPCo’s acquired interest were prospectively reflected in retail rates with the remaining 17.5% of costs associated with the acquired interest to be included in rates starting January 2020. APCo and WPCo file joint retail rates in West Virginia. In June 2019, APCo and WPCo filed with the WVPSC to increase each company’s retail rates (through a surcharge) starting January 1, 2020 to reflect the recovery of WPCo’s remaining 17.5% interest in the Mitchell Plant. The joint filing will increase APCo’s and WPCo’s combined West Virginia retail rates by approximately $21 million annually.
|
| |
• | 2012 Texas Base Rate Case - In 2012, SWEPCo filed a request with the PUCT to increase annual base rates primarily due to the completion of the Turk Plant. In 2013, the PUCT issued an order affirming the prudence of the Turk Plant. In July 2018, the Texas Third Court of Appeals reversed the PUCT’s judgment affirming the prudence of the Turk Plant and remanded the issue back to the PUCT. In August 2018, SWEPCo filed a Motion for Reconsideration at the Court of Appeals, which was denied. In January 2019, SWEPCo and the PUCT filed petitions for review with the Texas Supreme Court. In May 2019, various intervenors filed replies to the petition. In July 2019, SWEPCo filed its response to these briefs. The Texas Supreme Court has requested full briefing by the parties. SWEPCo’s initial brief is due in October 2019. Response briefs are due in November 2019 and SWEPCo’s reply brief is due in December 2019. As of September 30, 2019, the net book value of Turk Plant was $1.5 billion, before cost of removal, including materials and supplies inventory and CWIP. SWEPCo’s Texas jurisdictional share of the Turk Plant investment is approximately 33%.
|
In July 2019, clean energy legislation (HB 6) which offers incentives for power-generating facilities with zero or reduced carbon emissions was signed into law by the Ohio Governor. The clean energy legislation phasesHB 6 phased out current energy efficiency including lost shared savings revenues of $26 million annually and renewable mandates no later than 2020 and after 2026, respectively. The bill providesHB 6 also provided for the recovery of existing renewable energy contracts on a bypassable basis through 2032. The clean energy legislation also includes2032 and included a provision for recovery of OVEC costs through 2030 which will be allocated to all electric distribution utilities on a non-bypassable basis. OPCo’s Inter-Company Power Agreement for OVEC terminates in June 2040. In July 2020, an investigation led by the U.S. Attorney’s Office resulted in a federal grand jury indictment of the Speaker of the Ohio House of Representatives, Larry Householder, four other individuals, and Generation Now, an entity registered as a 501(c)(4) social welfare organization, in connection with a racketeering conspiracy involving the adoption of HB 6. In light of the allegations in the indictment, proposed legislation has been introduced that would repeal HB 6. The outcome of the U.S. Attorney’s Office investigation and its impact on HB 6 is not known. If the provisions of HB 6 were to be eliminated, it is unclear whether and in what form the Ohio General Assembly would pass new legislation addressing similar issues. In August 2020, an AEP shareholder filed a putative class action lawsuit against AEP and certain of its officers for alleged violations of securities laws. See Litigation Related to Ohio House Bill 6 section of Litigation below for additional information. To the extent that OPCo is unable to recover the costs of renewable energy contracts on a bypassable basis by the end of 2032, recover costs of OVEC after 2030, or fully recover energy efficiency costs through 2020 or incurs significant costs defending against the class action lawsuit, it could reduce future net income and cash flows and impact financial condition.
•In April 2020, the Virginia Clean Economy Act was signed into law by the Virginia Governor and became effective in July 2020. The law includes the following requirements: (a) Virginia electric utilities to retire no later than 2045 all electric generating units located in Virginia that emit carbon as a by-product, (b) APCo to produce 100% of the company’s power to serve Virginia customers from renewable sources by 2050 with increasing percentages of mandatory renewable energy sources each year and (c) Virginia electric utilities to achieve increasing annual energy efficiency savings from 2022-2025 using 2019 as the base year. This law also provides that if the Virginia SCC finds in any triennial review that revenue reductions related to energy efficiency programs approved and deployed since the utility's previous triennial review have caused the utility to earn more than 70 basis points below its authorized rate of return, the Virginia SCC shall order increases to the utility's ratesnecessary to recover such revenue reductions. If any of these costs are not recoverable, 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 2019.2020. See Note 4 - Rate Matters for additional information.
Completed Base Rate Case Proceedings
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Approved Revenue | | | Approved | | New Rates |
Company | | Jurisdiction | | Requirement Increase (Decrease) | | | ROE | | Effective |
| | | | (in millions) | | | | | |
I&M | | Michigan | | $ | 36.4 | | (a) | | 9.86% | | February 2020 |
I&M | | Indiana | | 77.4 | | (b) | | 9.7% | | March 2020 |
AEP Texas | | Texas | | (40.0) | | | | 9.4% | | June 2020 |
|
| | | | | | | | | | |
| | | | Approved Revenue | | Approved | | New Rates |
Company | | Jurisdiction | | Requirement Increase | | ROE | | Effective |
| | | | (in millions) | | | | |
APCo | | West Virginia | | $ | 35.8 |
| | 9.75% | | March 2019 |
WPCo | | West Virginia | | 8.4 |
| | 9.75% | | March 2019 |
PSO | | Oklahoma | | 46.0 |
| | 9.4% | | April 2019 |
(a)In January 2020, the MPSC issued an order approving a stipulation and settlement agreement. See “2019 Michigan Base Rate Case” section of Note 4 Rate Matters in the 2019 Annual Report for additional information.
(b)Will be phased-in through an increase in base rates which includes: (a) an annual increase in base rates of $44 million effective March 2020 and (b) an annual increase in base rates of up to $77 million effective January 2021 based on the IURC-approved forecast of December 31, 2020 Indiana jurisdictional electric plant in service. A compliance filing will be made in January 2021 to adjust the final rate increase to reflect the lower of I&Ms actual or IURC-approved Indiana jurisdictional electric plant in service balance as of December 31, 2020. The order rejected I&M’s proposed re-allocation of capacity costs related to the loss of a significant FERC wholesale contract, which will negatively impact I&M’s annual pretax earnings by approximately $20 million starting June 2020.
Pending Base Rate Case Proceedings
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Commission Staff/ |
| | | | Filing | | Requested Revenue | | | Requested | | Intervenor Range of |
Company | | Jurisdiction | | Date | | Requirement Increase | | | ROE | | Recommended ROE |
| | | | | | (in millions) | | | | | |
APCo | | Virginia | | March 2020 | | $ | 64.9 | | | | 9.9% | | 8.73% - 8.75% |
OPCo | | Ohio | | June 2020 | | 42.3 | | | | 10.15% | | (a) |
KPCo | | Kentucky | | June 2020 | | 65.0 | | | | 10% | | 8.93% - 9.25% |
SWEPCo | | Texas | | October 2020 | | 105.0 | | (b) | | 10.35% | | (a) |
|
| | | | | | | | | | | | |
| | | | | | | | | | Commission Staff/ |
| | | | Filing | | Requested Revenue | | Requested | | Intervenor Range of |
Company | | Jurisdiction | | Date | | Requirement Increase | | ROE | | Recommended ROE |
| | | | | | (in millions) | | | | |
SWEPCo (a) | | Arkansas | | February 2019 | | $ | 67.0 |
| | 10.5% | | 9% - 9.5% |
AEP Texas | | Texas | | May 2019 | | 56.0 |
| | 10.5% | | 9% - 9.35% |
I&M | | Indiana | | May 2019 | | 172.0 |
| | 10.5% | | 9% - 9.73% |
I&M | | Michigan | | June 2019 | | 58.4 |
| | 10.5% | | 9.1% - 9.75% |
(a)Awaiting procedural schedule.
(b)The request would move transmission and distribution interim revenues recovered through riders into base rates.Eliminating these riders would result in a net annual requested base rate increase of $90 million primarily due to increased investments.
| |
(a) | In October 2019, SWEPCo, the APSC staff and various intervenors filed a stipulation and settlement agreement with the APSC that included a base rate increase of $24 million based upon a 9.45% return on common equity. See “2019 Arkansas Base Rate Case” section of Note 4 for additional information. |
Renewable Generation
The growth of AEP’s renewable generation portfolio reflects the company’s strategy to diversify generation resources to provide clean energy options to customers that meet both their energy and capacity needs.
Contracted Renewable Generation Facilities
AEP continues to develop its renewable portfolio within the Generation & Marketing segment. Activities include working directly with wholesale and large retail customers to provide tailored solutions based upon market knowledge, technology innovations and deal structuring which may include distributed solar, wind, combined heat and power, energy storage, waste heat recovery, energy efficiency, peaking generation and other forms of cost reducing energy technologies. The Generation & Marketing segment also develops and/or acquires large scale renewable generation projects that are backed with long-term contracts with creditworthy counterparties.
In April 2019, AEP acquired Sempra Renewables LLC and its ownership interests in 724 MWs of wind generation and battery assets valued at approximately $1.1 billion. AEP paid $583 million in cash and acquired a 50% ownership interest in five non-consolidated joint ventures with net assets valued at $406 million as of the acquisition date (which includes $364 million of existing debt obligations). Additionally, the transaction included the acquisition of two tax equity partnerships and the associated recognition of noncontrolling tax equity interest of $135 million. The wind generation portfolio includes seven wind farms with long-term PPAs for 100% of their energy production. Five of the wind farms are jointly-owned with BP Wind Energy and two wind farms are consolidated by AEP and are tax equity partnerships with nonaffiliated noncontrolling interests. See “Acquisitions” section of Note 6 for additional information.
In July 2019, AEP acquired a 75% interest, or 227 MWs, in Santa Rita East for approximately $356 million. The project is located in west Texas and was placed in-service in July 2019. Long-term virtual power purchase agreements are in place with nonaffiliates for the project’s generation. See “Acquisitions” section of Note 6 for additional information.
As of September 30, 2019,2020, subsidiaries within AEP’s Generation & Marketing segment had approximately 1,3961,520 MWs of contracted renewable generation projects in-service. In addition, as of September 30, 2019,2020, these subsidiaries had approximately 54140 MWs of renewable generation projects under construction with total estimated capital costs of $67$243 million related to these projects.
Regulated Renewable Generation Facilities
In September 2018, OPCo, consistent with its commitment in the previously approved PPA application, submitted a filing with the PUCO demonstrating a need for up to 900 MWs of economically beneficial renewable resources in Ohio. This filing was followed by a separate filing for two solar Renewable Energy Purchase Agreements totaling 400 MWs. In January 2019, PUCO staff recommended that the PUCO reject OPCo’s request. If approved, the solar generation facilities are expected to be operational by the end of 2021.
In July 2019, PSO and SWEPCo submitted filings before their respective commissions for the approval to acquire the North Central Wind Energy Facilities, comprised of three Oklahoma wind facilities totaling 1,485 MWs, on a fixed cost turn-key basis at completion. Subject to regulatory approval, PSO will own 45.5% and SWEPCo will own 55.5%54.5% of the project, which will cost approximately $2 billion. TwoIn May 2020, the IRS issued a notice extending the “Continuity Safe Harbor” deadlines for qualifying renewable energy projects that began construction in 2016 and 2017 by one year as many projects are facing supply chain and other project development delays caused by COVID-19. Under the May 2020 IRS notice, qualifying renewable energy projects that began construction in 2016 and 2017 and which are placed in-service by the end of 2021 and 2022, respectively, will satisfy the Continuity Safe Harbor. Provided that each facility satisfies the Continuity Safe Harbor, under the current IRS guidance, the 199 MW wind facility will qualify for 100% of the federal PTC, and the remaining two wind facilities, totaling 1,286 MWs, wouldwill qualify for 80% of the federal PTC with year-end 2021 in-service dates.PTC. The third199 MW wind facility (199 MWs) would qualify for 100%is targeted to be placed in-service and acquired in March 2021. The 287 MW wind facility is targeted to be placed in-service and acquired in December 2021 and the 999 MW wind facility is targeted to be placed in-service and acquired between December 2021 and April 2022. All three wind facilities are expected to satisfy the Continuity Safe Harbor.
In February 2020, the OCC approved PSO’s settlement agreement. In May 2020, the APSC approved the settlement agreement as filed, with the exception that SWEPCo use its formula rate rider to recover its costs rather than the requested rider. Also in May 2020, the LPSC approved the settlement agreement as filed. Both the APSC and LPSC approved the flex-up option, agreeing to acquire the Texas portion, which the PUCT denied in July 2020. Having regulatory approval and the IRS extension of the PTC with a year-end 2020 in-service date. The acquisition can be scaled, subject to commercial limitation, to align with individual state resource needs and approvals. Hearings are scheduled for the first quarter of 2020.“Continuity Safe Harbor,” PSO and SWEPCo are seeking regulatory approvalsproceeding with the full 1,485 MW development of these three projects.
Hydroelectric Generation
Evaluating Sale of Hydroelectric Generation
In March 2020, management placed 10 hydroelectric generation plants under study for a potential sale. In April 2020, the Virginia Clean Economy Act was signed into law by July 2020.
Racine
A projectthe Virginia Governor. The new law will provide renewable credits to reconstructAPCo for its existing hydroelectric generation plants. As a defective dam structure at Racine beganresult of the new law, management removed the three APCo hydroelectric generation plants (London, Marmet and Winfield) from the list of plants identified for potential sale. The table below shows the net book value of each plant, including CWIP and materials and supplies, before cost of removal of the remaining plants included in the first quarterstudy.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Owner | | Plant Name | | Units | | State | | Net Book Value as of September 30, 2020 | | Net Maximum Capacity (MWs) | | Year Plant or First Unit Commissioned |
| | | | | | | | (in millions) | | | | |
AGR | | Racine | | 2 | | OH | | $ | 44.7 | | | 48 | | | 1982 |
I&M | | Berrien Springs | | 12 | | MI | | 6.2 | | | 6 | | | 1908 |
I&M | | Buchanan | | 10 | | MI | | 4.3 | | | 3 | | | 1919 |
I&M | | Constantine | | 4 | | MI | | 2.3 | | | 1 | | | 1921 |
I&M | | Elkhart | | 3 | | IN | | 5.2 | | | 3 | | | 1913 |
I&M | | Mottville | | 4 | | MI | | 2.7 | | | 2 | | | 1923 |
I&M | | Twin Branch Hydro | | 8 | | IN | | 5.7 | | | 5 | | | 1904 |
| | Total | | | | | | $ | 71.1 | | | 68 | | | |
If management decides to proceed with the sale of 2017. Duethese plants, FERC approval would be required. In addition, for all plants, except for Racine, state commission approval would be required. Management currently estimates that any potential sale agreements for these plants would not be entered into until late 2020 at the earliest. There is no assurance that management will be able to a significant increase in estimated costs to completesell any of these plants.
Dolet Hills Power Station and Related Fuel Operations
During the reconstruction project, AEP recorded impairments in 2017 and 2018. See Note 7 - Dispositions and Impairments in the 2018 Annual Report for additional information.
Due to weather-related delays in the firstsecond quarter of 2019, reconstruction activitiesthe Dolet Hills Power Station initiated a seasonal operating schedule. In January 2020, in accordance with the terms of SWEPCo’s settlement of its base rate review filed with the APSC, management announced that SWEPCo will seek regulatory approval to retire the Dolet Hills Power Station by the end of 2026. DHLC provides 100% of the fuel supply to Dolet Hills Power Station. After careful consideration of current economic conditions, and particularly for the benefit of their customers, 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 Racine are nowthe mine in May 2020. Based on these actions, management revised the estimated useful life of DHLC’s and Oxbow’s assets to be completedcoincide with the date at which extraction was discontinued in the first halfsecond quarter of 2020. AEP expects to incur additional capital expenditures to complete2020 and the reconstruction project,date at which point the fair valuedelivery of Racine, as fully operational,lignite is expected to approximatecease in September 2021. Management also revised the book value once complete. Future revisionsuseful life of the Dolet Hills Power Station to 2021 based on the remaining estimated fuel supply available for continued seasonal operation. In March 2020, primarily due to the revision in the useful life of DHLC, SWEPCo recorded a revision to increase estimated ARO liabilities by $21 million. 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 costs are recoverable by SWEPCo through base rates. SWEPCo’s share of the net investment in the Dolet Hills Power Station is $153 million, including CWIP and materials and supplies, before cost estimates or delaysof removal.
Fuel costs incurred by the Dolet Hills Power Station are recoverable by SWEPCo through active fuel clauses. Under the Lignite Mining Agreement, DHLC bills SWEPCo its proportionate share of incurred lignite extraction and associated mining-related costs as fuel is delivered. As of September 30, 2020, DHLC has unbilled lignite inventory and fixed costs of $36 million that will be billed to SWEPCo prior to the closure of the Dolet Hills Power Station. In 2009, SWEPCo acquired interests in completion could resultOxbow, which owns mineral rights and leases land. Under a Joint Operating Agreement pertaining to the Oxbow mineral rights and land leases, Oxbow bills SWEPCo its proportionate share of incurred costs. As of September 30, 2020, Oxbow has unbilled fixed costs of $10 million that will be billed to SWEPCo prior to the closure of the Dolet Hills Power Station. DHLC and Oxbow have billed SWEPCo $111 million for lignite deliveries from April 2020 through September 2020, which primarily includes accelerated depreciation and amortization of fixed costs. Additional operational and land-related costs are expected to be incurred by DHLC and Oxbow and billed to SWEPCo prior to the closure of the Dolet Hills Power Station and recovered through fuel clauses.
In October 2020, SWEPCo filed a request with the LPSC for recovery of the Louisiana share of these additional fuel costs. SWEPCo’s filing proposes to defer $36 million of fuel costs in additional losses which2021 and recover the deferral plus carrying costs over five years beginning in 2022.
If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
Dolet Hills Lignite Company OperationsFERC Transmission ROE Methodology
DuringManagement continues to monitor FERC’s 2019 Notice of Inquiry regarding base ROE policy, FERC’s 2020 Notice of Proposed Rulemaking regarding transmission incentives policy, and various other matters pending before FERC with the potential to affect FERC transmission ROE methodology.
In the second quarter of 2019, Dolet Hills Power Station switched to a seasonal operational strategy. DHLC’s mining operation will continue year-round but will reduce its lignite output. SWEPCo’s shareFERC 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 the second quarter of 2020, FERC Order 569A determined the base ROE for MISO’s transmission owning members, including AEP’s MISO transmission-owning subsidiaries, should be 10.02% (10.52% inclusive of the RTO incentive adder of 0.5%).
If FERC makes any changes to its ROE and incentive policies, they would be applied, as applicable, to AEP’s PJM, SPP and MISO transmission owning subsidiaries on a prospective basis, and could affect future net investment in the Dolet Hills Power Station is $129 millionincome and the maximum exposure of SWEPCo’s total investment in DHLC is $153 million. Management will continue to monitor the economic viability of the Dolet Hills Power Stationcash flows and DHLC.impact financial condition.
LITIGATION
In the ordinary course of business, AEP is involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty. Management assesses the probability of loss for each contingency and accrues a liability for cases that have a probable likelihood of loss if the loss can be estimated. Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition. See Note 4 – Rate Matters and Note 5 – Commitments, Guarantees and Contingencies for additional information.
Rockport Plant Litigation
In 2013, the Wilmington Trust Company filed a complaint in the U.S. District Court for the Southern District of New York against AEGCo and I&M alleging that it would be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration in December 2022. The terms of the consent decree allow the installation of environmental emission control equipment, repowering, refueling or retirement of the unit. The plaintiffs seek a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiffs. The New York court granted a motion to transfer this case to the U.S. District Court for the Southern District of Ohio.
AEGCo and I&M sought and were granted dismissal by the U.S. District Court for the Southern District of Ohio of certain of the plaintiffs’ claims, including claims for compensatory damages, breach of contract, breach of the implied covenant of good faith and fair dealing and indemnification of costs. Plaintiffs voluntarily dismissed the surviving claims that AEGCo and I&M failed to exercise prudent utility practices with prejudice, and the court issued a final judgment. The plaintiffs subsequently filed an appeal in the U.S. Court of Appeals for the Sixth Circuit.
In 2017, the U.S. Court of Appeals for the Sixth Circuit issued an opinion and judgment affirming the district court’s dismissal of the owners’ breach of good faith and fair dealing claim as duplicative of the breach of contract claims, reversing the district court’s dismissal of the breach of contract claims and remanding the case for further proceedings.
Thereafter, AEP filed a motion with the U.S. District Court for the Southern District of Ohio in the original NSR litigation, seeking to modify the consent decree. The district court granted the owners’ unopposed motion to stay the lease litigation to afford time for resolution of AEP’s motion to modify the consent decree. The consent decree was modified based on an agreement among the parties in July 2019. The district court entered a stipulated order tocourt’s stay of the lease litigation to afford timeexpired in August 2020. Upon expiration of the stay, plaintiffs filed a motion for partial summary judgment, arguing that the consent decree violates the facility lease and the participation agreement and requesting that the district court enter a judgment for the partiesplaintiffs on their breach of contract claim. AEP’s memorandum in opposition was filed in October 2020. All deadlines, including discovery, are stayed, pending resolution of the lease litigation to engage in settlement discussions.motion. See “Modification of the NSR Litigation Consent Decree” section below for additional information.
Management will continue to defend against the claims. Given that the district court dismissed plaintiffs’ claims seeking compensatory relief as premature, and that plaintiffs have yet to present a methodology for determining or any analysis supporting any alleged damages, management cannot determine a range of potential losses that areis reasonably possible of occurring.
Patent Infringement Complaint
In July 2019, Midwest Energy Emissions Corporation and MES Inc. (collectively, the plaintiffs) filed a patent infringement complaint against various parties, including AEP Texas, AGR, Cardinal Operating Company and SWEPCo (collectively, the AEP Defendants). The complaint alleges that the AEP Defendants infringed two patents owned by the plaintiffs by using specific processes for mercury control at certain coal-fired generating stations. In July 2020, plaintiffs amended the complaint to add three new patents. The amended complaint seeks injunctive relief and damages. The case is scheduled for trial in January 2023. Management will continue to defend against the claims. Management is unable to determine a range of potential losslosses that is reasonably possible of occurring.
Claims Challenging Transition of American Electric Power System Retirement Plan to Cash Balance Formula
The American Electric Power System Retirement Plan (the Plan) has received a letter written on behalf of four participants (the Claimants) making a claim for additional plan benefits and purporting to advance such claims on behalf of a class. When the Plan’s benefit formula was changed in the year 2000, AEP provided a special provision for employees hired before January 1, 2001, allowing them to continue benefit accruals under the then benefit formula for a full 10 years alongside of the new cash balance benefit formula then being implemented. Employees who were hired on or after January 1, 2001 accrued benefits only under the new cash balance benefit formula. The Claimants have asserted claims that (a) the Plan violates the requirements under the Employee Retirement Income Security Act (ERISA) intended to preclude back-loading the accrual of benefits to the end of a participant’s career; (b) the Plan violates the age discrimination prohibitions of ERISA and the Age Discrimination in Employment Act; and (c) the company failed to provide required notice regarding the changes to the Plan. AEP has responded to the Claimants providing a reasoned explanation for why each of their claims have been denied. The denial of those claims was appealed to the AEP System Retirement Plan Appeal Committee and the Committee upheld the denial of claims. Management will continue to defend against the claims. Management is unable to determine a range of potential losses that are reasonably possible of occurring.
Litigation Related to Ohio House Bill 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 complaint alleges misrepresentations or omissions by AEP regarding: (a) its alleged participation in public corruption with respect to the passage of Ohio House Bill 6, (b) its regulatory, legislative and lobbying activities in Ohio and (c) its clean energy strategy. The complaint seeks monetary damages among other forms of relief. Management is unable to determine a range of potential losses that is reasonably possible of occurring.
ENVIRONMENTAL ISSUES
AEP has a substantial capital investment program and incurs additional operational costs to comply with environmental control requirements. Additional investments and operational changes will be made in response to existing and anticipated requirements to reduce emissions from fossil generation and in response to rules governing the beneficial use and disposal of coal combustion by-products, clean water rules 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. AEP, along with other parties, challenged some of the Federal EPA requirements. 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, 2019,2020, the AEP System had generating capacity of approximately 25,50024,300 MWs, of which approximately 13,20012,100 MWs were coal-fired. Management continues to refine the cost estimates of complying with these rules and other impacts of the environmental proposals on fossil generation. Based upon management estimates, AEP’s future investment to meet these existing and proposed requirements ranges from approximately $550$500 million to $1.1$1 billion through 2026.
The cost estimates will change depending on the timing of implementation and whether the Federal EPA provides flexibility in finalizing proposed rules or revising certain existing requirements. The cost estimates will also change based on: (a) potential state rules that impose more stringent standards, (b) additional rulemaking activities in response to court decisions, (c) actual performance of the pollution control technologies installed, (d) changes in costs for new pollution controls, (e) new generating technology developments, (f) total MWs of capacity retired and replaced, including the type and amount of such replacement capacity and (g) other factors. In addition, management continues to evaluate the economic feasibility of environmental investments on regulated and competitive plants.
The table below represents the net book value before cost of removal, including related materials and supplies inventory, of plants or units of plants previously retired that have a remaining net book value as of September 30, 2019.
|
| | | | | | | | | |
| | | | Generating | | Amounts Pending |
Company | | Plant Name and Unit | | Capacity | | Regulatory Approval |
| | | | (in MWs) | | (in millions) |
APCo | | Kanawha River Plant | | 400 |
| | $ | 43.8 |
|
APCo | | Clinch River Plant, Unit 3 | | 235 |
| | 31.8 |
|
APCo (a) | | Clinch River Plant, Units 1 and 2 | | 470 |
| | 29.2 |
|
APCo | | Sporn Plant, Units 1 and 3 | | 300 |
| | 15.6 |
|
APCo | | Glen Lyn Plant | | 335 |
| | 13.5 |
|
SWEPCo (b) | | Welsh Plant, Unit 2 | | 528 |
| | 50.6 |
|
Total | | | | 2,268 |
| | $ | 184.5 |
|
| |
(a) | APCo obtained permits following the Virginia SCC’s and WVPSC’s approval to convert Clinch River Plant, Units 1 and 2 to natural gas. In 2015, APCo retired the coal-related assets of Clinch River Plant, Units 1 and 2. Clinch River Plant, Units 1 and 2 began operations as natural gas units in 2016. |
| |
(b) | In October 2019, SWEPCo filed a stipulation and settlement agreement with the APSC, which includes recovery of the remaining $15 million Arkansas jurisdictional share of the net book value of Welsh Plant, Unit 2. An order from the APSC is expected in the fourth quarter of 2019. |
Management is seeking or will seek recovery of the remaining net book value in future rate proceedings. To the extent the net book value of these generation assets is not recoverable, it could materially reduce future net income and cash flows and impact financial condition.
Modification of 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.
In 2017, AEP filed a motion with the district court seeking to modify the consent decree to eliminate an obligation to install future controls at Rockport Plant, Unit 2 if AEP does not acquire ownership of that unit, and to modify the consent decree in other respects to preserve the environmental benefits of the consent decree. The other parties to the consent decree opposed AEP’s motion. The district court granted AEP’s request to delay the deadline to install SCRSelective Catalytic Reduction (SCR) technology at Rockport Plant, Unit 2 until June 2020. Construction of the SCR technology was completed by June 1, 2020, testing was conducted, and the unit was released for dispatch on June 5, 2020.
In May 2019, the parties filed a proposed order to modify the consent decree. The proposed order requires AEP to enhance the dry sorbent injection (DSI) system on both units at the Rockport Plant by the end of 2020, and meet 30-day rolling average emission rates for SO2 and NOx at the combined stack for the Rockport Plant beginning in 2021. Total SO2 emissions from the Rockport Plant are limited to 10,000 tons per year beginning in 2021 and reduce to 5,000 tons per year when Rockport Plant, Unit 1 retires in 2028. The proposed modification was approved by the district court and became effective in July 2019. As part of the modification to the consent decree, I&M agreed to provide an additional $7.5 million to citizens’ groups and the states for environmental mitigation projects. As joint owners in the Rockport Plant, the $7.5 million payment was shared between AEGCo and I&M based on the joint ownership agreement.
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 issued new, more stringent NAAQS for PM in 2012 and ozone in 2015. Thereviewed the existing standards for NO2 and SO2were retained after review by the Federal EPA in 2018 and 2019, respectively.respectively, and decided to retain the standards without change. Implementation of these standards is underway.
In 2016, the The Federal EPA completed an integrated review plan for the 2012 PM standard. Work is currently underway on scientific, riskreviewing the existing standards for PM, last revised in 2012, and policy assessments necessary to develop aozone, last revised in 2015. A proposed rule which is anticipatedto retain the existing PM standards was released in 2021.April 2020. A proposed rule to retain the existing standards for ozone was released in August 2020.
The Federal EPA finalized non-attainment designations for the 2015 ozone standard in 2018. The Federal EPA has confirmed that for states included in the CSAPR program, there are no additional interstate transport obligations, as all areas of the country are expected to attain the 2008 ozone standard before 2023. Challenges to the 2015 ozone standard and the Federal EPA’s determination that CSAPR satisfies certain states’ interstate transport obligations are pendingwere filed in the U.S. Court of Appeals for the District of Columbia Circuit. In 2018,August 2019, the court upheld the 2015 primary ozone standard, but remanded the secondary welfare-based standard for further review. The court vacated the Federal EPA proposed final requirementsEPA’s determination that CSAPR fulfilled the states’ interstate transport obligations, because the Federal EPA’s modeling analysis did not demonstrate that all significant contributions would be eliminated by the attainment deadlines for implementing the 2015 ozone standard, which have been challenged in the U.S. Court of Appeals for the District of Columbia Circuit.downwind states. Any further changes will require additional rulemaking. Management cannot currently predict the nature, stringency or timing of additional requirements for AEP’s facilities based on the outcome of these activities.
Regional Haze
The Federal EPA issued a Clean Air Visibility Rule (CAVR), detailing how the CAA’s requirement that certain facilities install best available retrofit technology (BART) would address regional haze in federal parks and other protected areas. BART requirements apply to certain power plants. CAVR will be implemented through SIPs or FIPs. In 2017, the Federal EPA revised the rules governing submission of SIPs to implement the visibility programs, including a provision that postpones the due date for the next comprehensive SIP revisions until 2021. Petitions for review of the final rule revisions have been filed in the U.S. Court of Appeals for the District of Columbia Circuit.
In 2012, theThe Federal EPA proposed disapprovalinitially disapproved portions of a portion of the Arkansas regional haze SIP, in Arkansasbut has approved a revised SIP and finalized a FIP in 2016. In 2017, Arkansas issued a proposed SIP revision to allow sources to participate in the CSAPR ozone season program in lieuall of the source-specific NOx BART requirements in the FIP, and in 2018, the Federal EPA approved the
revision. Arkansas finalized a separate action in 2017 to revise the SO2 BART determinations and in September 2019, the Federal EPA approved the Arkansas SO2 BART determinations. SWEPCo’s Flint Creek Plant is alreadySWEPCo's affected units are in compliance with the applicablerelevant requirements.
The Federal EPA also disapproved portions of the Texas regional haze SIP. In 2017, the Federal EPA 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. A challenge to the FIP was filed in the U.S. Court of Appeals for the Fifth Circuit by various intervenors and the case is pending the Federal EPA’s reconsideration of the final rule. In August 2018, the Federal EPA proposed to affirm its 2017 FIP approval. In November 2019, in response to comment, the Federal EPA proposed revisions to the intrastate trading program. The Federal EPA finalized the intrastate trading program in July 2020. Management supports the intrastate trading program contained in the FIP as a compliance alternative to source-specific controls.
Cross-State Air Pollution Rule
In 2011, the Federal EPA issued CSAPR as a replacement for the Clean Air Interstate Rule, 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.
Petitions to review the CSAPR were filed in the U.S. Court of Appeals for the District of Columbia Circuit. In 2015, the court found that the Federal EPA over-controlled the SO2 and/or NOx budgets of 14 states. The court remanded the rule to the Federal EPA for revision consistent with the court’s opinion while CSAPR remained in place.
In 2016, the Federal EPA issued a final rule, the CSAPR Update, to address the remand and to incorporate additional changes necessary to address the 2008 ozone standard. The CSAPR Update significantly reduced ozone season budgets in many states and discounted the value of banked CSAPR ozone season allowances beginning with the 2017 ozone season. In 2019, the appeals court remanded the CSAPR Update to the Federal EPA because it determined the Federal EPA had not properly considered the attainment dates for downwind areas in establishing its partial remedy, and should have considered whether there were available measures to control emissions from sources other than generating units. Management has complied withAny further changes to the more stringent ozone season budgets while these petitions were pending.CSAPR rule will require additional rulemaking.
Mercury and Other Hazardous Air Pollutants (HAPs) Regulation
In 2012, the Federal EPA issued a rule addressing a broad range of HAPs from coal and oil-fired power plants. The rule established unit-specific emission rates for units burning coal on a 30-day rolling average basis for mercury, PM (as a surrogate for particles of non-mercury metals) and hydrogen chloride (as a surrogate for acid gases). In addition, the rule proposed work practice standards for controlling emissions of organic HAPs and dioxin/furans, with compliance required within three years. Management obtained administrative extensions for up to one year at several units to facilitate the installation of controls or to avoid a serious reliability problem.
In 2014, the U.S. Court of Appeals for the District of Columbia Circuit denied all of the petitions for review of the 2012 final rule. Various intervenors filed petitions for further review in the U.S. Supreme Court.
In 2015, the U.S. Supreme Court reversed the decision of the U.S. Court of Appeals for the District of Columbia Circuit. The court remanded the MATS rule to the Federal EPA to consider costs in determining whether to regulate emissions of HAPs from power plants. In 2016, the Federal EPA issued a supplemental finding concluding that, after considering the costs of compliance, it was appropriate and necessary to regulate HAP emissions from coal and oil-fired units. Petitions for review of the Federal EPA’s determination were filed in the U.S. Court of Appeals for the District of Columbia Circuit. In 2018, the Federal EPA released a revised finding that the costs of reducing HAP emissions to the level in the current rule exceed the benefits of those HAP emission reductions. The Federal EPA also determined that there are no significant changes in control technologies and the remaining risks associated with HAP emissions do not justify any more stringent standards. Therefore, the Federal EPA proposed to retain the current MATS standards without change. In April 2020, the Federal EPA released a final rule adopting the conclusions set forth in the proposal and retaining the existing MATS standards. The comment period on this proposal endedrule has been challenged in April 2019.the U.S. Court of Appeals for the District of Columbia Circuit.
Climate Change, CO2 Regulation and Energy Policy
In 2015, the Federal EPA published the final CO2 emissions standards for new, modified and reconstructed fossil generating units, and final guidelines for the development of state plans to regulate CO2 emissions from existing sources, known as the Clean Power Plan (CPP).
In 2016, the U.S. Supreme Court issued a stay onof the final CPP, including all of the deadlines for submission of initial or final state plans until a final decision is issued by the U.S. Court of Appeals for the District of Columbia Circuit and the U.S. Supreme Court considers any petition for review. In 2017, the President issued an Executive Order directing the Federal EPA to reconsider the CPP and the associated standards for new sources. The Federal EPA filed a motion to hold the challenges to the CPP in abeyance pending reconsideration. In September 2019, following the Federal EPA’s finalization of rescissionrepeal of the CPP and promulgation of thea replacement rule, the Court of Appeals for the District of Columbia Circuit dismissed the challenges.
In July 2019, the Federal EPA finalized the Affordable Clean Energy (ACE) rule to replace the CPP with new emission guidelines for regulating CO2 from existing sources. ACE establishes a framework for states to adopt standards of performance for utility boilers based on heat rate improvements for such boilers. The final rule applies to generating units that commenced construction prior to January 2014, generate greater than 25 MWs, have a baseload rating above 250 MMBtu per hour and burn coal for more than 10% of the annual average heat input over the preceding three calendar years, with certain exceptions. States must establish standards of performance for each affected facility in terms of pounds of CO2 emitted per MWh, based on certain heat rate improvement measures and the degree of emission reduction achievable through each applicable measure, together with consideration of certain site-specific factors and the unit’s remaining useful life. Information collection and rulemaking activities are underway in several states. State plans are required to be submitted within three years,in 2022, and the Federal EPA has up to two years to review and approve a plan or disapprove the planit and adopt a federal plan. The final ACE rule has been challenged in the courts.
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. Management continues to actively monitor these rulemaking activities.
AEP has taken action to reduce and offset CO2 emissions from its generating fleet andfleet. 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 September 2019, 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 a 70% reduction from 2000 CO2 emission levels from AEP generating facilities by 2030; the long-term goal is to surpass an 80% reduction of CO2 emissions from AEP generating facilities from 2000 levels by 2050. AEP’s total estimated CO2 emissions in 20182019 were approximately 6958 million metric tons, a 59%65% reduction from AEP’s 2000 CO2 emissions. AEP has made significant progress in reducing CO2 emissions from its power generation fleet and expectexpects its emissions to continue to decline. AEP’s aspirational emissions goal is zero CO2 emissions by 2050. Technological advances, including energy storage, will determine how quickly AEP can achieve zero emissions while continuing to provide reliable, affordable power for customers.
Federal and state legislation or regulations that mandate limits on the emission of CO2 could result in significant increases in capital expenditures and operating costs, which in turn, could lead to increased liquidity needs and higher financing costs. Excessive costs to comply with future legislation or regulations might force AEP to close some coal-fired facilities, which could possibly lead to impairment of assets.
Coal Combustion Residual (CCR) Rule
In 2015, the Federal EPA published a final rule to regulate 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 CCR landfills and surface impoundments at operating electric utility or independent generation facilities. The rule imposes construction and operating obligations, including location restrictions, liner criteria, structural integrity requirements for impoundments, operating criteria and additional groundwater monitoring requirements to be implemented on a schedule spanning an approximate four-year implementation period. In 2018, some of AEP’s facilities were required to begin monitoring programs to determine if unacceptable groundwater impacts will trigger future corrective measures. Based on additional groundwater data, further studies to design and assess appropriate corrective measures have been undertaken at four facilities. Alternative source demonstrations have been prepared in accordance with the rule at four othertwo facilities.
In a challenge to the final 2015 rule, the parties initially agreed to settle some of the issues. In 2018, the U.S. Court of Appeals for the District of Columbia Circuit addressed or dismissed the remaining issues in its decision vacating and remanding certain provisions of the 2015 rule. The provisions addressed by the court’s decision, including changes to the provisions for unlined impoundments and legacy sites, will be the subject of further rulemaking consistent with the court’s decision.
Prior to the court’s decision, the Federal EPA issued the July 2018 rule that modifies certain compliance deadlines and other requirements in the 2015 rule. In December 2018, challengers filed a motion for partial stay or vacatur of the July 2018 rule. On the same day, the Federal EPA filed a motion for partial remand of the July 2018 rule. The court granted the Federal EPA’s motion, and further rulemakingmotion. In November 2019, the Federal EPA proposed revisions to addressimplement the court’s decisions is expected to be completed neardecision regarding the endtiming for closure of 2019.unlined surface impoundments along with impoundments not meeting the required distance from an aquifer. The final rule was published in August 2020. In December 2019, the Federal EPA proposed a federal permit program, implementing the Water Infrastructure Improvements for the Nation Act that would apply in states that do not have an approved CCR program.
Other utilities and industrial sources have been engaged in litigation with environmental advocacy groups who claim that releases of contaminants from wells, CCR units, pipelines and other facilities to groundwaters that have a hydrologic connection to a surface water body represent an “unpermitted discharge” under the CWA. Two cases were accepted by the U.S. Supreme Court for further review of the scope of CWA jurisdiction. In April 2020, the Supreme Court issued an opinion remanding one of these cases to the Ninth Circuit based on its determination that discharges from an injection well that make their way to the Pacific Ocean through ground water may require a permit if the distance traveled through ground water, length of time to reach the surface water and other factors make it “functionally equivalent” to a direct discharge from a point source. The second case was also remanded to the lower court. Prior to the Supreme Court’s decision, the Federal EPA opened a rulemaking docket to solicit information to determine whether it should provide additional clarification of the scope of CWA permitting requirements for discharges to groundwater, and issued an interpretive statement finding that discharges to groundwater are not subject to NPDES permitting requirements under the CWA. Management is unable to predict the impact of this guidance or the outcome of these casesdevelopments on AEP’s facilities.
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 deadline for seeking an extension under either option is November 30, 2020.
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.
The second option is a retirement option, which provides a generating facility an extended operating time without developing alternative CCR disposal. Under the retirement option, a generating facility would have until October 17, 2023 to cease operation and to close CCR storage ponds 40 acres or less in size, or through October 17, 2028 for facilities with CCR storage ponds greater than 40 acres in size.
Because AEP currently uses surface impoundments and landfills to manage CCR materials at generating facilities, significant costs willmay be incurred to upgrade or close and replace these existing facilities and conduct any required remedial actions. Management is evaluating various compliance options. Under the retirement option above, AEP may need to recover remaining depreciation and estimated closure costs associated with retiring plants over a shorter period. If AEP cannot ultimately recover the costs of environmental compliance and/or the remaining depreciation and estimated closure costs associated with retiring plants in a timely manner, it would reduce future net income and cash flows and impact financial condition.
Closure and post-closure costs have been included in ARO in accordance with the requirements in the final rule. This estimate does notAdditional 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.
In March 2020, Virginia’s Governor signed House Bill 443 (HB 443), effective July 2020, requiring APCo to close certain ash disposal units at the retired Glen Lyn Station by removal of groundwater remediation, where required.all coal combustion material. As a result, in June 2020, APCo recorded a $199 million revision to increase estimated Glen Lyn Station ash disposal ARO liabilities. The closure is required to be completed within 15 years from the start of the excavation process. HB 443 provides for the recovery of all costs associated with closure by removal through the Virginia environmental rate adjustment clause (E-RAC). APCo may begin recovering these costs through the E-RAC beginning July 1, 2022. APCo is permitted to record carrying costs on the unrecovered balance of closure costs at a weighted average cost of capital approved by the Virginia SCC. HB 443 also allows any closure costs allocated to non-Virginia jurisdictional customers, but not collected from such non-Virginia jurisdictional customers, to be recovered from Virginia jurisdictional customers through the E-RAC.
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 already have been closed in place in accordance with state law programs. Management will continue to evaluate the rule’s impactparticipate in rulemaking activities and make adjustments based on operations.new federal and state requirements affecting its ash disposal units.
Clean Water Act Regulations
In 2014, the Federal EPA issued a final rule setting forth standards for existing power plants that is intended to reduce mortality of aquatic organisms impinged or entrained in the cooling water. The rule was upheld on review by the U.S. Court of Appeals for the Second Circuit. Compliance timeframes are established by the permit agency through each facility’s NPDES permit as those permits are renewed and have been incorporated into permits at several AEP facilities. Additional AEP facilities are reviewing these requirements asthat have had their wastewater discharge permits are renewed and making appropriate adjustmentshave been asked to theirmonitor intake structures.flows or to enhance monitoring practices to assure the current technology is being properly managed to ensure compliance with this rule.
In 2015, the Federal EPA issued a final rule revising effluent limitation guidelines for generating facilities. The rule established limits on FGD wastewater, fly ash and bottom ash transport water and flue gas mercury control wastewater to be imposed as soon as possible after November 2018 and no later than December 2023. These
requirements would be implemented through each facility’s wastewater discharge permit. The rule was challenged in the U.S. Court of Appeals for the Fifth Circuit. In 2017, the Federal EPA announced its intent to reconsider and potentially revise the standards for FGD wastewater and bottom ash transport water. The Federal EPA postponed the compliance deadlines
for those wastewater categories to be no earlier than 2020, to allow for reconsideration. A revised rule could be proposed later in 2019. In April 2019, the Fifth Circuit vacated the standards for landfill leachate and legacy wastewater, and remanded them to the Federal EPA for reconsideration. In November 2019, the Federal EPA proposed revisions to the guidelines for existing generation facilities. A final rule was signed by the Federal EPA in August 2020 and was published in October 2020. The final rule 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 is assessing technology additions and retrofits to comply with the rule and the impacts of the Federal EPA’s recent actions on facilities’ wastewater discharge permitting.permitting for FGD wastewater and bottom ash transport water.
In 2015, the Federal EPA and the U.S. Army Corps of Engineers jointly issued a final rule to clarify the scope of the regulatory definition of “waters of the United States” in light of recent U.S. Supreme Court cases. Various parties challenged the 2015 rule in different U.S. District Courts, which resulted in a patchwork of applicability of the 2015 rule and its predecessor. In December 2018, the Federal EPA and the U.S. Army Corps of Engineers releasedproposed a proposed rule to replace the definition in the 2015replacement rule. The comment period for this proposal ended in April 2019. In September 2019, the Federal EPA announcedrepealed the 2015 rule. The final replacement rule was published in the Federal Register in April 2020 and became effective in June 2020. The final rule limits the scope of CWA jurisdiction to four categories of waters, and clarifies exclusions for ground water, ephemeral streams, artificial ponds and waste treatment systems. Challenges to the final repealrule and requests for a preliminary injunction have been brought by states and other groups in multiple U.S. District Courts. At this time, none of the 2015 definitionjurisdictions in which AEP operates are impacted by a stay. Management is monitoring these various proceedings but is unable to predict the actions of “watersthe various courts.
In April 2020, the U.S. District Court for the District of Montana issued a decision vacating the U.S. Army Corps of Engineers’ (Corps) General Nationwide Permit 12 (NWP 12), which provides standard conditions governing linear utility projects in streams, wetlands and other waters of the United States” and recodificationStates having minimal adverse environmental impacts. The Court found that in reissuing NWP 12 in 2017, the Corps failed to comply with Section 7 of the regulatory definition that was in place priorEndangered Species Act (ESA), which requires the Corps to consult with the U.S. Fish and Wildlife Service regarding potential impacts on endangered species. The Court remanded the permit back to the 2015 rule.Corps to complete its ESA consultation, and also enjoined the Corps from authorizing any dredge or fill activities under NWP 12 pending completion of the consultation process. The Department of Justice filed a motion to stay the injunction and tailor the remedy imposed by the Court. In May 2020, the Court revised its order lifting the injunction for non-oil and gas pipeline construction activities and routine maintenance, inspection and repair activities on existing NWP 12 projects. The Department of Justice appealed the Court’s decision to the Court of Appeals for the Ninth Circuit and moved for stay pending appeal, which was denied. In June 2020, the Department of Justice submitted an application to the U.S. Supreme Court requesting a stay of the District Court’s Order, and the Court granted the request with respect to all oil and gas pipelines except the Keystone Pipeline. Management is monitoring the litigation and evaluating other permitting alternatives, but is currently unable to predict the impact of future proceedings on current and planned projects.
In September 2020, the Corps issued for public comment the proposed renewal of all General Nationwide Permits. As part of that proposal the Corps has narrowed the focus of NWP 12 to only oil and natural gas pipeline activities. The Corps is proposing two new Nationwide Permits governing electric utility line and telecommunications activities, and other utility lines (e.g., conveyance of potable water, sewage, other substances), respectively. Management is currently assessing impacts of the proposal on current and planned projects.
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 SSOstandard 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 returns on equity.
•Development, construction and operation of transmission facilities through investments in AEP’s transmission-only joint ventures. These investments have PUCT-approved or FERC-approved returns on equity.
Generation & Marketing
•Competitive generation in ERCOT and PJM.
•Contracted renewable energy investments and management services.
•Marketing, risk management and retail activities in ERCOT, MISO, PJM SPP and MISO.SPP.
Contracted renewable energy investments and management services.
The remainder of AEP’s activities are presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs.
The following discussion of AEP’s results of operations by operating segment includes an analysis of Gross Margin, which is a non-GAAP financial measure. Gross Margin includes Total Revenues less the costs of Fuel and Other Consumables Used for Electric Generation as well as Purchased Electricity for Resale and Amortization of Generation Deferrals as presented in the Registrants statements of income as applicable. Under the various state utility rate making processes, these expenses are generally reimbursable directly from and billed to customers. As a result, they do not typically impact Operating Income or Earnings Attributable to AEP Common Shareholders. Management believes that Gross Margin provides a useful measure for investors and other financial statement users to analyze AEP’s financial performance in that it excludes the effect on Total Revenues caused by volatility in these expenses. Operating Income, which is presented in accordance with GAAP in AEP’s statements of income, is the most directly comparable GAAP financial measure to the presentation of Gross Margin. AEP’s definition of Gross Margin may not be directly comparable to similarly titled financial measures used by other companies.
The following table presents Earnings (Loss) Attributable to AEP Common Shareholders by segment:
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended | | | | Nine Months Ended | | |
| September 30, | | | | September 30, | | |
| 2020 | | 2019 | | 2020 | | 2019 |
| (in millions) | | | | | | |
Vertically Integrated Utilities | $ | 393.5 | | | $ | 437.6 | | | $ | 894.7 | | | $ | 917.7 | |
Transmission and Distribution Utilities | 147.4 | | | 133.7 | | | 403.1 | | | 421.6 | |
AEP Transmission Holdco | 138.3 | | | 126.1 | | | 370.4 | | | 404.8 | |
Generation & Marketing | 116.7 | | | 90.0 | | | 211.0 | | | 139.5 | |
Corporate and Other | (47.3) | | | (53.9) | | | (114.6) | | | (116.0) | |
Earnings Attributable to AEP Common Shareholders | $ | 748.6 | | | $ | 733.5 | | | $ | 1,764.6 | | | $ | 1,767.6 | |
|
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2019 | | 2018 | | 2019 | | 2018 |
| (in millions) |
Vertically Integrated Utilities | $ | 437.6 |
| | $ | 344.2 |
| | $ | 917.7 |
| | $ | 852.2 |
|
Transmission and Distribution Utilities | 133.7 |
| | 145.2 |
| | 421.6 |
| | 384.6 |
|
AEP Transmission Holdco | 126.1 |
| | 73.3 |
| | 404.8 |
| | 278.4 |
|
Generation & Marketing | 90.0 |
| | 5.3 |
| | 139.5 |
| | 62.3 |
|
Corporate and Other | (53.9 | ) | | 9.6 |
| | (116.0 | ) | | (17.1 | ) |
Earnings Attributable to AEP Common Shareholders | $ | 733.5 |
| | $ | 577.6 |
| | $ | 1,767.6 |
| | $ | 1,560.4 |
|
AEP CONSOLIDATED
Third Quarter of 20192020 Compared to Third Quarter of 20182019
Earnings Attributable to AEP Common Shareholders increased from $578 million in 2018 to $734 million in 2019 to $749 million in 2020 to primarily due to:
•Favorable rate proceedings in AEP’s various jurisdictions.
An increase•A planned decrease in Other Operation and Maintenance expenses.
•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.
These increases were partially offset by:
•A decrease in weather-related usage.
An increase•A one-time reversal of a regulatory provision in transmission investment, which resulted in higher revenues and income.2019.
Nine Months Ended September 30, 20192020 Compared to Nine Months Ended September 30, 20182019
Earnings Attributable to AEP Common Shareholders increaseddecreased from $1.6 billion$1,768 million in 20182019 to $1.8 billion$1,765 million in 20192020 primarily due to:
•A decrease in weather-related usage.
•A one-time reversal of a regulatory provision in 2019.
These decreases were partially offset by:
•Favorable rate proceedings in AEP’s various jurisdictions.
An increase in transmission investment, which resulted in higher revenues and income.
These increases were partially offset by:
•A planned decrease in weather-related usage.Other Operation and Maintenance expenses.
•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.
AEP’s results of operations by operating segment are discussed below.
VERTICALLY INTEGRATED UTILITIES
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | | | Nine Months Ended | | |
| | September 30, | | | | September 30, | | |
Vertically Integrated Utilities | | 2020 | | 2019 | | 2020 | | 2019 |
| | (in millions) | | | | | | |
Revenues | | $ | 2,434.8 | | | $ | 2,645.5 | | | $ | 6,753.5 | | | $ | 7,172.6 | |
Fuel and Purchased Electricity | | 693.7 | | | 874.2 | | | 1,947.0 | | | 2,430.2 | |
| | | | | | | | |
Gross Margin | | 1,741.1 | | | 1,771.3 | | | 4,806.5 | | | 4,742.4 | |
Other Operation and Maintenance | | 715.9 | | | 742.9 | | | 2,031.8 | | | 2,117.1 | |
| | | | | | | | |
| | | | | | | | |
Depreciation and Amortization | | 398.8 | | | 364.3 | | | 1,173.8 | | | 1,079.6 | |
Taxes Other Than Income Taxes | | 121.0 | | | 117.9 | | | 355.6 | | | 347.1 | |
Operating Income | | 505.4 | | | 546.2 | | | 1,245.3 | | | 1,198.6 | |
| | | | | | | | |
| | | | | | | | |
Other Income (Expense) | | (0.7) | | | 0.9 | | | 2.3 | | | 4.4 | |
Allowance for Equity Funds Used During Construction | | 15.9 | | | 12.2 | | | 33.1 | | | 38.9 | |
Non-Service Cost Components of Net Periodic Benefit Cost | | 16.9 | | | 17.0 | | | 50.9 | | | 50.8 | |
Interest Expense | | (140.2) | | | (140.6) | | | (426.5) | | | (422.6) | |
Income Before Income Tax Expense (Benefit) and Equity Earnings | | 397.3 | | | 435.7 | | | 905.1 | | | 870.1 | |
Income Tax Expense (Benefit) | | 3.8 | | | (1.9) | | | 10.5 | | | (48.4) | |
Equity Earnings of Unconsolidated Subsidiary | | 0.7 | | | 0.8 | | | 2.2 | | | 2.3 | |
Net Income | | 394.2 | | | 438.4 | | | 896.8 | | | 920.8 | |
Net Income Attributable to Noncontrolling Interests | | 0.7 | | | 0.8 | | | 2.1 | | | 3.1 | |
Earnings Attributable to AEP Common Shareholders | | $ | 393.5 | | | $ | 437.6 | | | $ | 894.7 | | | $ | 917.7 | |
|
| | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
Vertically Integrated Utilities | | 2019 | | 2018 | | 2019 | | 2018 |
| | (in millions) |
Revenues | | $ | 2,645.5 |
| | $ | 2,636.7 |
| | $ | 7,172.6 |
| | $ | 7,393.7 |
|
Fuel and Purchased Electricity | | 874.2 |
| | 1,034.6 |
| | 2,430.2 |
| | 2,700.4 |
|
Gross Margin | | 1,771.3 |
| | 1,602.1 |
| | 4,742.4 |
| | 4,693.3 |
|
Other Operation and Maintenance | | 742.9 |
| | 753.7 |
| | 2,117.1 |
| | 2,197.5 |
|
Depreciation and Amortization | | 364.3 |
| | 340.1 |
| | 1,079.6 |
| | 966.1 |
|
Taxes Other Than Income Taxes | | 117.9 |
| | 108.8 |
| | 347.1 |
| | 326.4 |
|
Operating Income | | 546.2 |
| | 399.5 |
| | 1,198.6 |
| | 1,203.3 |
|
Other Income | | 0.9 |
| | 4.1 |
| | 4.4 |
| | 14.2 |
|
Allowance for Equity Funds Used During Construction | | 12.2 |
| | 9.3 |
| | 38.9 |
| | 24.0 |
|
Non-Service Cost Components of Net Periodic Benefit Cost | | 17.0 |
| | 18.0 |
| | 50.8 |
| | 53.7 |
|
Interest Expense | | (140.6 | ) | | (149.2 | ) | | (422.6 | ) | | (428.0 | ) |
Income Before Income Tax Expense (Benefit) and Equity Earnings | | 435.7 |
| | 281.7 |
| | 870.1 |
| | 867.2 |
|
Income Tax Expense (Benefit) | | (1.9 | ) | | (63.1 | ) | | (48.4 | ) | | 12.9 |
|
Equity Earnings of Unconsolidated Subsidiary | | 0.8 |
| | 0.8 |
| | 2.3 |
| | 2.0 |
|
Net Income | | 438.4 |
| | 345.6 |
| | 920.8 |
| | 856.3 |
|
Net Income Attributable to Noncontrolling Interests | | 0.8 |
| | 1.4 |
| | 3.1 |
| | 4.1 |
|
Earnings Attributable to AEP Common Shareholders | | $ | 437.6 |
| | $ | 344.2 |
| | $ | 917.7 |
| | $ | 852.2 |
|
Summary of KWh Energy Sales for Vertically Integrated Utilities
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | | | Nine Months Ended September 30, | | |
| | 2020 | | 2019 | | 2020 | | 2019 |
| | (in millions of KWhs) | | | | | | |
Retail: | | | | | | | | |
Residential | | 9,066 | | | 9,254 | | | 24,304 | | | 24,785 | |
Commercial | | 6,257 | | | 6,840 | | | 16,773 | | | 18,183 | |
Industrial | | 8,161 | | | 9,123 | | | 24,335 | | | 26,533 | |
Miscellaneous | | 595 | | | 641 | | | 1,636 | | | 1,734 | |
Total Retail | | 24,079 | | | 25,858 | | | 67,048 | | | 71,235 | |
| | | | | | | | |
Wholesale (a) | | 4,574 | | | 5,864 | | | 13,116 | | | 16,494 | |
| | | | | | | | |
Total KWhs | | 28,653 | | | 31,722 | | | 80,164 | | | 87,729 | |
(a)Includes Off-system Sales, municipalities and cooperatives, unit power and other wholesale customers.
|
| | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2019 | | 2018 | | 2019 | | 2018 |
| (in millions of KWhs) |
Retail: | |
| | |
| | |
| | |
|
Residential | 9,254 |
| | 8,988 |
| | 24,785 |
| | 26,105 |
|
Commercial | 6,840 |
| | 6,723 |
| | 18,183 |
| | 18,699 |
|
Industrial | 9,123 |
| | 9,107 |
| | 26,533 |
| | 26,757 |
|
Miscellaneous | 641 |
| | 621 |
| | 1,734 |
| | 1,762 |
|
Total Retail (a) | 25,858 |
| | 25,439 |
| | 71,235 |
| | 73,323 |
|
| | | | | | | |
Wholesale (b) | 5,864 |
| | 6,432 |
| | 16,494 |
| | 17,156 |
|
| | | | | | | |
Total KWhs | 31,722 |
| | 31,871 |
| | 87,729 |
| | 90,479 |
|
| |
(a) | 2018 KWhs have been revised to reflect the reclassification of certain customer accounts between Retail classes. This reclassification did not impact previously reported Total Retail KWhs. Management concluded that these prior period disclosure only errors were immaterial individually and in the aggregate. |
| |
(b) | 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 September 30, | | | | Nine Months Ended September 30, | | |
| | 2020 | | 2019 | | 2020 | | 2019 |
| | (in degree days) | | | | | | |
Eastern Region | | | | | | | | |
Actual – Heating (a) | | 3 | | | — | | | 1,456 | | | 1,670 | |
Normal – Heating (b) | | 4 | | | 5 | | | 1,752 | | | 1,742 | |
| | | | | | | | |
Actual – Cooling (c) | | 867 | | | 937 | | | 1,204 | | | 1,316 | |
Normal – Cooling (b) | | 739 | | | 732 | | | 1,081 | | | 1,070 | |
| | | | | | | | |
Western Region | | | | | | | | |
Actual – Heating (a) | | 1 | | | — | | | 699 | | | 967 | |
Normal – Heating (b) | | 1 | | | 1 | | | 902 | | | 902 | |
| | | | | | | | |
Actual – Cooling (c) | | 1,291 | | | 1,572 | | | 2,015 | | | 2,234 | |
Normal – Cooling (b) | | 1,416 | | | 1,402 | | | 2,144 | | | 2,129 | |
(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.
|
| | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2019 | | 2018 | | 2019 | | 2018 |
| (in degree days) |
Eastern Region | |
| | |
| | |
| | |
|
Actual – Heating (a) | — |
| | — |
| | 1,670 |
| | 1,844 |
|
Normal – Heating (b) | 5 |
| | 5 |
| | 1,742 |
| | 1,745 |
|
| | | | | | | |
Actual – Cooling (c) | 937 |
| | 878 |
| | 1,316 |
| | 1,364 |
|
Normal – Cooling (b) | 732 |
| | 730 |
| | 1,070 |
| | 1,063 |
|
| | | | | | | |
Western Region | |
| | |
| | |
| | |
|
Actual – Heating (a) | — |
| | — |
| | 967 |
| | 974 |
|
Normal – Heating (b) | 1 |
| | 1 |
| | 902 |
| | 908 |
|
| | | | | | | |
Actual – Cooling (c) | 1,572 |
| | 1,443 |
| | 2,234 |
| | 2,380 |
|
Normal – Cooling (b) | 1,402 |
| | 1,402 |
| | 2,129 |
| | 2,121 |
|
| |
(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 20192020 Compared to Third Quarter of 20182019
| | | | | | | | |
Reconciliation of Third Quarter of 2019 to Third Quarter of 2020 | | |
Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities | | |
(in millions) | | |
| | |
Third Quarter of 2019 | | $ | 437.6 | |
| | |
Changes in Gross Margin: | | |
Retail Margins | | (14.3) | |
Margins from Off-system Sales | | (5.5) | |
Transmission Revenues | | (3.1) | |
Other Revenues | | (7.3) | |
Total Change in Gross Margin | | (30.2) | |
| | |
Changes in Expenses and Other: | | |
Other Operation and Maintenance | | 27.0 | |
| | |
Depreciation and Amortization | | (34.5) | |
Taxes Other Than Income Taxes | | (3.1) | |
| | |
| | |
Other Income | | (1.6) | |
Allowance for Equity Funds Used During Construction | | 3.7 | |
Non-Service Cost Components of Net Periodic Pension Cost | | (0.1) | |
Interest Expense | | 0.4 | |
Total Change in Expenses and Other | | (8.2) | |
| | |
Income Tax Expense | | (5.7) | |
Equity Earnings of Unconsolidated Subsidiary | | (0.1) | |
Net Income Attributable to Noncontrolling Interests | | 0.1 | |
| | |
Third Quarter of 2020 | | $ | 393.5 | |
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, and purchased electricity were as follows:
•Retail Margins decreased $14 million primarily due to the following:
•A $50 million decrease in weather-related usage primarily in the western region and primarily in the residential class.
•A $24 million decrease in weather-normalized margins for wholesale customers, including the loss of a significant wholesale contract at I&M.
•A $4 million decrease in revenue from rate riders at PSO. This decrease was partially offset in other expense items below.
•A $3 million decrease in weather-normalized retail margins driven by a $42 million decrease in the commercial and industrial customer classes partially offset by a $41 million increase in the residential customer class.
These decreases were partially offset by:
•The effect of rate proceedings in AEP’s service territories which included:
•A $38 million increase at I&M primarily due to the Indiana and Michigan base rate cases and an overall increase in revenue from rate riders. This increase was partially offset in other expense items below.
•A $14 million increase at SWEPCo primarily due to a base rate revenue increase in Arkansas.
•A $10 million increase in deferred fuel at APCo and WPCo primarily due to the timing of recoverable PJM expenses. This increase was offset in other expense items below.
•A $5 million increase at APCo and WPCo due to the WVPSC’s approval of the Mitchell Plant surcharge effective January 2020.
|
| | | | |
Reconciliation of Third Quarter of 2018 to Third Quarter of 2019 |
Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities |
(in millions) |
| | |
Third Quarter of 2018 | | $ | 344.2 |
|
| | |
|
Changes in Gross Margin: | | |
|
Retail Margins | | 145.1 |
|
Margins from Off-system Sales | | (0.9 | ) |
Transmission Revenues | | 23.8 |
|
Other Revenues | | 1.2 |
|
Total Change in Gross Margin | | 169.2 |
|
| | |
|
Changes in Expenses and Other: | | |
|
Other Operation and Maintenance | | 10.8 |
|
Depreciation and Amortization | | (24.2 | ) |
Taxes Other Than Income Taxes | | (9.1 | ) |
Other Income | | (3.2 | ) |
Allowance for Equity Funds Used During Construction | | 2.9 |
|
Non-Service Cost Components of Net Periodic Pension Cost | | (1.0 | ) |
Interest Expense | | 8.6 |
|
Total Change in Expenses and Other | | (15.2 | ) |
| | |
|
Income Tax Expense (Benefit) | | (61.2 | ) |
Net Income Attributable to Noncontrolling Interests | | 0.6 |
|
| | |
Third Quarter of 2019 | | $ | 437.6 |
|
•Margins from Off-system Sales decreased$6 million due to weaker market prices for energy in the RTOs which caused a decrease in sales volume and margins and the historical merchant portion of WPCo’s Mitchell Plant moving to retail rates beginning in January 2020.•Other Revenues decreased $7 million primarily due to a decrease at I&M in barging revenues by River Transportation Division (RTD). This decrease was partially offset in Other Operation and Maintenance expenses below.
Expenses and Other and Income Tax Expensechanged between years as follows:
•Other Operation and Maintenance expenses decreased $27 million primarily due to the following:
•A $23 million decrease in distribution expenses primarily related to vegetation management, storms and other distribution expenses.
•A $13 million decrease in plant outage and maintenance expenses primarily at I&M, SWEPCo, PSO and KPCo.
•An $8 million decrease due to the modification of the NSR consent decree impacting I&M and AEGCo in 2019.
•A $4 million decrease in transmission expenses primarily related to RTO fees, NERC activities and station/line inspections.
•A $4 million decrease in customer-related expenses.
These decreases were partially offset by:
•A $30 million increase in employee-related expenses.
•Depreciation and Amortization expenses increased $35 millionprimarily due to a higher depreciable base and increased depreciation rates approved at I&M and SWEPCo. This increase was partially offset in Retail Margins above.
•Income TaxExpense increased $6 million primarily due to a decrease in amortization of Excess ADIT, partially offset by a decrease in pretax book income and an increase in favorable flow-through tax benefits. The decrease in amortization of Excess ADIT is partially offset above in Gross Margin and Other Operation and Maintenance expenses.
Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019
| | | | | | | | |
Reconciliation of Nine Months Ended September 30, 2019 to Nine Months Ended September 30, 2020 | | |
Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities | | |
(in millions) | | |
| | |
Nine Months Ended September 30, 2019 | | $ | 917.7 | |
| | |
Changes in Gross Margin: | | |
Retail Margins | | 38.5 | |
Margins from Off-system Sales | | (14.2) | |
Transmission Revenues | | 48.7 | |
Other Revenues | | (8.9) | |
Total Change in Gross Margin | | 64.1 | |
| | |
Changes in Expenses and Other: | | |
Other Operation and Maintenance | | 85.3 | |
| | |
Depreciation and Amortization | | (94.2) | |
Taxes Other Than Income Taxes | | (8.5) | |
| | |
| | |
Other Income | | (2.1) | |
Allowance for Equity Funds Used During Construction | | (5.8) | |
Non-Service Cost Components of Net Periodic Pension Cost | | 0.1 | |
Interest Expense | | (3.9) | |
Total Change in Expenses and Other | | (29.1) | |
| | |
Income Tax Expense | | (58.9) | |
Equity Earnings of Unconsolidated Subsidiary | | (0.1) | |
Net Income Attributable to Noncontrolling Interests | | 1.0 | |
| | |
Nine Months Ended September 30, 2020 | | $ | 894.7 | |
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 $39 million primarily due to the following: • increased $145 million primarily due to the following: |
A $91$35 million increase in deferred fuel at APCo and WPCo primarily due to the timing of recoverable PJM expenses.
•A $16 million increase due to a 2018 reductiondecrease in the deferred fuel under recovery balance as a result of the 2018 West Virginiacustomer refunds related to Tax Reform settlement.Reform. This increase was partially offset in Income Tax Expense (Benefit) below.
A $23 million increase in weather-related usage primarily in the residential class.
•A $15 million increase at APCo and WPCo due to the WVPSC approval of the Mitchell Plant surcharge effective January 1, 2020. Pursuant to the WVPSC approval of the surcharge, this increase was partially offset by the amortization of Excess ADIT not subject to normalization requirements in deferred fuel related to recoverable PJM expenses that were offsetIncome Tax Expense below.
•A $10$14 million increase due to 2018 Virginia legislationthe impact of the 2019 WVPSC order which increased non-recoverablerequired APCo and WPCo to offset Excess ADIT not subject to normalization requirements against the deferred fuel expense at APCounder-recovery balance in the prior year.2019.
A $4 million increase in weather-normalized retail margins across all classes.
•The effect of rate proceedings in AEP’s service territories which included:
•A $19$72 million increase at I&M primarily due to the Indiana and Michigan base rate cases and an overall increase in revenue from rate proceedings at I&M.riders. This increase was partially offset in other expense items below.
•A $14$35 million increase at SWEPCo primarily due to rider increases in all jurisdictions and a base rate revenue increase in Arkansas. This increase was partially offset in other expense items below.
•A $10 million increase at PSO due to new base rates implemented in April 2019.
•A $10 million increase at APCo and WPCo due to revenue primarily froma base rate ridersincrease in West Virginia. This increase was partially offset in Depreciation and Amortization expenses below.
•A $6 million increase in municipal and cooperative revenues at SWEPCo primarily due to formula rate true-ups.
These increases were partially offset by:
•A $95 million decrease in weather-related usage primarily in the residential class.
•A $47 million decrease in weather-normalized margins for wholesale contracts, including the loss of a significant wholesale contract at I&M.
•A $12 million decrease in weather-normalized retail margins driven by a $93 million decrease in the commercial and industrial classes partially offset by an $85 million increase in the residential customer class.
•A $10 million decrease in revenue from rate riders at PSO. This decrease was partially offset in other expense items below.
An $8•Margins from Off-system Sales decreased $14 million due to weaker market prices for energy in the RTOs which caused a decrease in sales volume and margins and the historical merchant portion of WPCo’s Mitchell Plant moving to retail rates beginning in January 2020.
•Transmission Revenues increased $49 million primarily due to the following:
•A $26 million increase relateddue to rider revenuescontinued investment in transmission projects primarily at SWEPCo.
•A $23 million increase as a result of the annual transmission formula rate true-up primarily at SWEPCo. This increase was partially offset by an increase in transmission expenses in SPP.
•Other Revenues decreased $9 million primarily due to the following:
•A decrease of $14 million at I&M primarily due to the timing of the Indiana PJM/OSS rider recovery.a decrease in barging revenues by RTD. This decrease was partially offset in Other Operation and Maintenance expenses below.
This decrease was partially offset by:
•A $3 million increase at PSO primarily due to business development revenue. This increase was partially offset in other expense items below.
A $7 million increase at APCo and WPCo due to base rate increases in West Virginia implemented in March 2019.
These increases were partially offset by:
A $74 million decrease due to customer refunds related to Tax Reform. This decrease was partially offset in Income Tax Expense (Benefit) below.
| |
• | Transmission Revenues increased $24 million primarily due to the following:
|
A $16 million increase due to SPP provisions for refund recorded in 2018.
| |
• | A $16 million increase primarily due to 2018 PJM provisions for refunds mainly at APCo.
|
These increases were partially offset by:
| |
• | An $8 million decrease primarily due to a reduction in SPP Base Plan Funding revenues and a decrease in nonaffiliated transmission services.
|
Expenses and Other and Income Tax Expense (Benefit)changed between years as follows:
| |
• | Other Operation and Maintenance expenses decreased $11•Other Operation and Maintenance expenses decreased $85 million primarily due to the following:
|
A $40 million decrease at APCo and WPCo due to the extinguishment of certain regulatory asset balances as agreed to within the 2018 West Virginia Tax Reform settlement.following:
•A $12$53 million decrease in planned plant outage and maintenance expenses primarily at APCo, I&M, WPCo, KPCo and I&M.PSO.
•A $9$22 million decrease in distribution expenses primarily vegetation management and other distribution expenses.
•A $12 million decrease due to the capitalization of previously expensed North Central Wind Catcher Project expenses incurred in 2018 forEnergy Facilities costs at SWEPCo and PSO.
•A $3$10 million decrease in recoverabletransmission expenses primarily associated with Energy Efficiency/Demand Responserelated to RTO fees, NERC activities and storm expenses fully recovered in rate riders/trackers within Gross Margin above.station/line inspections.
These decreases were partially offset by:
A $45 million increase due to PJM transmission services including the annual formula rate true-up.
•An $8 million increasedecrease due to the modification of the NSR consent decree impacting I&M and AEGCo.AEGCo in 2019.
•A $2$7 million increase due to North Central Wind Energy Facilities expenses for SWEPCo and PSO.decrease in PJM transmission services including the annual formula rate true-up.
| |
• | Depreciation and Amortization expenses increased $24 millionprimarily due to a higher depreciable base and increased depreciation rates approved at APCo, I&M and SWEPCo.
|
| |
• | Taxes Other Than Income Taxes increased $9 million primarily due to the following:
|
A $5 million increase in property taxes driven by an increase in utility plant.
A $5 million increase in West Virginia business and occupational taxes at APCo and WPCo.
| |
• | Interest Expense decreased $9 million primarily due to lower interest rates on outstanding long-term debt at I&M and SWEPCo.
|
| |
• | Income TaxExpense (Benefit) increased $61 million primarily due to the one time recognition of $86 million of additional amortization of Excess ADIT as a result of the West Virginia Tax Reform order received in the third quarter of 2018. The additional excess amortization from the West Virginia Tax Reform order was partially offset in Retail Margins and Other Operation and Maintenance expenses above.
|
Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018
|
| | | | |
Reconciliation of Nine Months Ended September 30, 2018 to Nine Months Ended September 30, 2019 |
Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities |
(in millions) |
| | |
Nine Months Ended September 30, 2018 | | $ | 852.2 |
|
| | |
|
Changes in Gross Margin: | | |
|
Retail Margins | | 75.4 |
|
Margins from Off-system Sales | | (10.4 | ) |
Transmission Revenues | | (16.4 | ) |
Other Revenues | | 0.5 |
|
Total Change in Gross Margin | | 49.1 |
|
| | |
|
Changes in Expenses and Other: | | |
|
Other Operation and Maintenance | | 80.4 |
|
Depreciation and Amortization | | (113.5 | ) |
Taxes Other Than Income Taxes | | (20.7 | ) |
Other Income | | (9.8 | ) |
Allowance for Equity Funds Used During Construction | | 14.9 |
|
Non-Service Cost Components of Net Periodic Pension Cost | | (2.9 | ) |
Interest Expense | | 5.4 |
|
Total Change in Expenses and Other | | (46.2 | ) |
| | |
|
Income Tax Expense (Benefit) | | 61.3 |
|
Equity Earnings of Unconsolidated Subsidiary | | 0.3 |
|
Net Income Attributable to Noncontrolling Interests | | 1.0 |
|
| | |
Nine Months Ended September 30, 2019 | | $ | 917.7 |
|
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 $75 million primarily due to the following:
|
A $91 million increase at APCo and WPCo due to a 2018 reduction in the deferred fuel under recovery balance as a result of the 2018 West Virginia Tax Reform settlement. This increase was partially offset in Income Tax Expense (Benefit) below.
A $12 million increase at APCo in deferred fuel related to recoverable PJM expenses that were offset below.
A $10 million increase due to 2018 Virginia legislation which increased non-recoverable fuel expense at APCo in the prior year.
A $6$7 million decrease at I&M in fuel-related expenses due to timing of recovery for fuel and other variable production costs related to wholesale contracts.
The effect of rate proceedingsan increased Nuclear Electric Insurance Limited distribution in AEP’s service territories which included:
A $94 million increase from rate proceedings at I&M, inclusive of a $30 million decrease due to the impact of Tax Reform. This increase was partially offset in other expense items below.
A $35 million increase at PSO due to new base rates implemented in April 2019 and March 2018.
A $21 million increase related to rider revenues at I&M, primarily due to the timing of the Indiana PJM/OSS rider recovery. This increase was partially offset in other expense items below.
| |
• | A $17 million increase at APCo and WPCo primarily due to revenue from rate riders in West Virginia. 2020.This increase was offset in other expense items below.
|
A $14 million increase at APCo and WPCo due to base rate increases in West Virginia implemented in March 2019.
A $7 million increase at SWEPCo primarily due to rider and base rate revenue increases in Louisiana. The increase in rider rates had increases in other expense items below.
A $4 million increase in rider revenues at KPCo offset in other expense items below.
These increases were partially offset by:
A $117 million decrease due to customer refunds related to Tax Reform. This decrease was partially offset in Income Tax Expense (Benefit) below.
A $73 million decrease in weather-related usage across all regions primarily in the residential class.
A $67 million decrease in weather-normalized retail margins across all classes.
| |
• | Margins from Off-system Sales decreased $10 million primarily due to mid-year 2018 changes in the OSS sharing mechanism at I&M.
|
| |
• | Transmission Revenues decreased $16 million primarily due to the following:
|
A $40 million decrease in SWEPCo’s annual SPP Transmission formula rate true-up.
A $12 million decrease primarily due to I&M’s annual PJM Transmission formula rate true-up.
An $11 million decrease primarily due to a reduction in SPP Base Plan Funding revenues.
These decreases were partially offset by:
•A $36$39 million increase primarily due to 2018 PJM provisions for refund mainly at APCo.
A $16 million increase due to a provision for refund recorded at PSO and SWEPCo in 2018 related to certain transmission assets that management believes should not have been included in the SPP formula rate.
Expenses and Other and Income Tax Expense (Benefit) changed between years as follows:
| |
• | Other Operation and Maintenance expenses decreased $80 million primarily due to the following:
|
A $56 million decrease due to SPP transmission services including the annual formula rate true-up.
A $47 million decrease in planned plant outage and maintenance expenses primarily for I&M, APCo, SWEPCo and KPCo.
A $40 million decrease due to Wind Catcher Project expenses incurred in 2018 for SWEPCo and PSO.
A $40 million decrease at APCo and WPCo due to the extinguishment of certain regulatory asset balances as agreed to within the 2018 West Virginia Tax Reform settlement.
A $25 million decrease in recoverable expenses primarily associated with Energy Efficiency/Demand Response and storm expenses fully recovered in rate riders/trackers within Gross Margin above.
•A $10 million decrease in expense at APCo due to lower current year amortization of certain regulatory assets that were extinguished in August 2018 as agreed to within the 2018 West Virginia Tax Reform settlement.
A $9 million decrease in estimated expense for claims related to asbestos exposure.
These decreases were partially offset by:
A $92 million increase due to PJM transmission services including the annual formula rate true-up.storms primarily at KPCo and PSO.
•A $23$3 million increase in employee-related expenses.
A $13•Depreciation and Amortization expenses increased $94 million increase at APCoprimarily due to 2019 contributions to benefit low income West Virginia residential customers as a result of the 2018 West Virginia Tax Reform settlement.higher depreciable base and increased depreciation rates approved at I&M, APCo and SWEPCo. This increase was partially offset in Retail Margins above.
•Taxes Other Than Income Tax Expense (Benefit) below.
An $8Taxes increased $9 million increase in storm-related expenses primarily at SWEPCo.
An $8 million increase due to the modification of the NSR consent decree impacting I&M and AEGCo.following:
•A $5 million increase due to North Central Wind Energy Facilities expenses for SWEPCo and PSO.
| |
• | Depreciation and Amortization expenses increased $114 millionprimarily due to a higher depreciable base and increased depreciation rates approved at I&M, APCo, SWEPCo and PSO.
|
| |
• | Taxes Other Than Income Taxes increased $21 million primarily due to the following:
|
A $14$6 million increase in property taxes driven by an increasedue to additional investments in utility plant.
A $9 million increase at APCo and WPCo in West Virginia business and occupational taxes.
| |
• | Other Income decreased $10 million primarily due to a decrease in carrying charges for certain riders at I&M.
|
| |
• | Allowance for Equity Funds Used During Construction increased $15 million primarily due to the following:
|
A $10 million increase primarily due to various increases in equity rates at I&M, APCo and PSO and increased projects at I&M.
A $3 million increase due to recent FERC audit findings.
A $2 million increasein state business and occupation taxes at APCo due to the FERC’s approvalreduction of a settlement agreement.the revitalization tax credit.
| |
• | Interest Expense decreased $5•Allowance for Equity Funds Used During Construction decreased $6 million primarily due to the following:
|
A $16 million decrease due to lower interest rates on outstanding long-term debta decrease in the AFUDC base at I&M and SWEPCo.the favorable impact of a FERC settlement agreement recorded in 2019.
This decrease was partially offset by:
An $11•Interest Expense increased $4 million increase primarily due to higher long-term debt balances mainly at APCoAPCo.
•Income TaxExpense increased $59 million primarily due to a decrease in amortization of Excess ADIT and PSO.
| |
• | Income Taxan increase in pretax book income. The decrease in amortization of Excess ADIT is partially offset above in Gross Margin and Other Operation and Maintenance expenses.Expense (Benefit) decreased $61 million primarily due to additional amortization of Excess ADIT as a result of finalized rate orders. The excess amortization is partially offset within Gross Margin and Other Operation and Maintenance above.
|
TRANSMISSION AND DISTRIBUTION UTILITIES
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | | | Nine Months Ended | | |
| | September 30, | | | | September 30, | | |
Transmission and Distribution Utilities | | 2020 | | 2019 | | 2020 | | 2019 |
| | (in millions) | | | | | | |
Revenues | | $ | 1,165.3 | | | $ | 1,186.6 | | | $ | 3,306.7 | | | $ | 3,454.3 | |
Purchased Electricity | | 183.8 | | | 210.1 | | | 522.7 | | | 603.5 | |
Amortization of Generation Deferrals | | — | | | 8.8 | | | — | | | 65.3 | |
Gross Margin | | 981.5 | | | 967.7 | | | 2,784.0 | | | 2,785.5 | |
Other Operation and Maintenance | | 439.1 | | | 405.8 | | | 1,158.2 | | | 1,222.1 | |
| | | | | | | | |
| | | | | | | | |
Depreciation and Amortization | | 163.5 | | | 209.3 | | | 585.0 | | | 586.4 | |
Taxes Other Than Income Taxes | | 156.4 | | | 151.8 | | | 444.4 | | | 437.2 | |
Operating Income | | 222.5 | | | 200.8 | | | 596.4 | | | 539.8 | |
Interest and Investment Income | | 0.9 | | | 1.1 | | | 2.0 | | | 4.2 | |
Carrying Costs Income | | 0.3 | | | 0.3 | | | 1.3 | | | 0.7 | |
| | | | | | | | |
Allowance for Equity Funds Used During Construction | | 9.0 | | | 9.8 | | | 23.7 | | | 22.3 | |
Non-Service Cost Components of Net Periodic Benefit Cost | | 7.4 | | | 7.7 | | | 22.1 | | | 22.8 | |
Interest Expense | | (74.0) | | | (63.6) | | | (217.6) | | | (170.8) | |
Income Before Income Tax Expense (Benefit) | | 166.1 | | | 156.1 | | | 427.9 | | | 419.0 | |
Income Tax Expense (Benefit) | | 18.7 | | | 22.4 | | | 24.8 | | | (2.6) | |
Net Income | | 147.4 | | | 133.7 | | | 403.1 | | | 421.6 | |
Net Income Attributable to Noncontrolling Interests | | — | | | — | | | — | | | — | |
Earnings Attributable to AEP Common Shareholders | | $ | 147.4 | | | $ | 133.7 | | | $ | 403.1 | | | $ | 421.6 | |
|
| | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
Transmission and Distribution Utilities | | 2019 | | 2018 | | 2019 | | 2018 |
| | (in millions) |
Revenues | | $ | 1,186.6 |
| | $ | 1,211.5 |
| | $ | 3,454.3 |
| | $ | 3,510.9 |
|
Purchased Electricity | | 210.1 |
| | 218.7 |
| | 603.5 |
| | 660.0 |
|
Amortization of Generation Deferrals | | 8.8 |
| | 56.9 |
| | 65.3 |
| | 171.9 |
|
Gross Margin | | 967.7 |
| | 935.9 |
| | 2,785.5 |
| | 2,679.0 |
|
Other Operation and Maintenance | | 405.8 |
| | 420.4 |
| | 1,222.1 |
| | 1,152.1 |
|
Depreciation and Amortization | | 209.3 |
| | 201.4 |
| | 586.4 |
| | 558.4 |
|
Taxes Other Than Income Taxes | | 151.8 |
| | 143.2 |
| | 437.2 |
| | 413.2 |
|
Operating Income | | 200.8 |
| | 170.9 |
| | 539.8 |
| | 555.3 |
|
Interest and Investment Income | | 1.1 |
| | 1.3 |
| | 4.2 |
| | 2.6 |
|
Carrying Costs Income | | 0.3 |
| | 0.2 |
| | 0.7 |
| | 1.5 |
|
Allowance for Equity Funds Used During Construction | | 9.8 |
| | 7.8 |
| | 22.3 |
| | 23.0 |
|
Non-Service Cost Components of Net Periodic Benefit Cost | | 7.7 |
| | 8.3 |
| | 22.8 |
| | 24.6 |
|
Interest Expense | | (63.6 | ) | | (63.5 | ) | | (170.8 | ) | | (185.6 | ) |
Income Before Income Tax Expense (Benefit) | | 156.1 |
| | 125.0 |
| | 419.0 |
| | 421.4 |
|
Income Tax Expense (Benefit) | | 22.4 |
| | (20.2 | ) | | (2.6 | ) | | 36.8 |
|
Net Income | | 133.7 |
| | 145.2 |
| | 421.6 |
| | 384.6 |
|
Net Income Attributable to Noncontrolling Interests | | — |
| | — |
| | — |
| | — |
|
Earnings Attributable to AEP Common Shareholders | | $ | 133.7 |
| | $ | 145.2 |
| | $ | 421.6 |
| | $ | 384.6 |
|
Summary of KWh Energy Sales for Transmission and Distribution Utilities
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | | | Nine Months Ended September 30, | | |
| | 2020 | | 2019 | | 2020 | | 2019 |
| | (in millions of KWhs) | | | | | | |
Retail: | | | | | | | | |
Residential | | 8,277 | | | 8,268 | | | 20,876 | | | 20,614 | |
Commercial | | 6,722 | | | 7,219 | | | 18,154 | | | 19,069 | |
Industrial | | 5,417 | | | 5,857 | | | 16,473 | | | 17,492 | |
Miscellaneous | | 206 | | | 223 | | | 568 | | | 595 | |
Total Retail (a) | | 20,622 | | | 21,567 | | | 56,071 | | | 57,770 | |
| | | | | | | | |
Wholesale (b) | | 502 | | | 453 | | | 1,347 | | | 1,531 | |
| | | | | | | | |
Total KWhs | | 21,124 | | | 22,020 | | | 57,418 | | | 59,301 | |
(a)Represents energy delivered to distribution customers.
(b)Primarily Ohio’s contractually obligated purchases of OVEC power sold to PJM.
|
| | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2019 | | 2018 | | 2019 | | 2018 |
| (in millions of KWhs) |
Retail: | |
| | |
| | |
| | |
|
Residential | 8,268 |
| | 7,948 |
| | 20,614 |
| | 21,154 |
|
Commercial | 7,219 |
| | 6,958 |
| | 19,069 |
| | 19,061 |
|
Industrial | 5,857 |
| | 5,904 |
| | 17,492 |
| | 17,772 |
|
Miscellaneous | 223 |
| | 209 |
| | 595 |
| | 574 |
|
Total Retail (a)(b) | 21,567 |
| | 21,019 |
| | 57,770 |
| | 58,561 |
|
| | | | | | | |
Wholesale (c) | 453 |
| | 634 |
| | 1,531 |
| | 1,835 |
|
| | | | | | | |
Total KWhs | 22,020 |
| | 21,653 |
| | 59,301 |
| | 60,396 |
|
| |
(a) | 2018 KWhs have been revised to reflect the reclassification of certain customer accounts between Retail classes. This reclassification did not impact previously reported Total Retail KWhs. Management concluded that these prior period disclosure only errors were immaterial individually and in the aggregate. |
| |
(b) | Represents energy delivered to distribution customers. |
| |
(c) | 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 September 30, | | | | Nine Months Ended September 30, | | |
| | 2020 | | 2019 | | 2020 | | 2019 |
| | (in degree days) | | | | | | |
Eastern Region | | | | | | | | |
Actual – Heating (a) | | 2 | | | — | | | 1,767 | | | 2,006 | |
Normal – Heating (b) | | 6 | | | 6 | | | 2,086 | | | 2,072 | |
| | | | | | | | |
Actual – Cooling (c) | | 809 | | | 872 | | | 1,126 | | | 1,176 | |
Normal – Cooling (b) | | 682 | | | 672 | | | 986 | | | 973 | |
| | | | | | | | |
Western Region | | | | | | | | |
Actual – Heating (a) | | 1 | | | — | | | 98 | | | 180 | |
Normal – Heating (b) | | — | | | — | | | 188 | | | 190 | |
| | | | | | | | |
Actual – Cooling (d) | | 1,357 | | | 1,587 | | | 2,524 | | | 2,679 | |
Normal – Cooling (b) | | 1,378 | | | 1,368 | | | 2,436 | | | 2,425 | |
(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.
|
| | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2019 | | 2018 | | 2019 | | 2018 |
| (in degree days) |
Eastern Region | |
| | |
| | |
| | |
|
Actual – Heating (a) | — |
| | — |
| | 2,006 |
| | 2,158 |
|
Normal – Heating (b) | 6 |
| | 6 |
| | 2,072 |
| | 2,076 |
|
| | | | | | | |
Actual – Cooling (c) | 872 |
| | 864 |
| | 1,176 |
| | 1,322 |
|
Normal – Cooling (b) | 672 |
| | 670 |
| | 973 |
| | 964 |
|
| | | | | | | |
Western Region | |
| | |
| | |
| | |
|
Actual – Heating (a) | — |
| | — |
| | 180 |
| | 234 |
|
Normal – Heating (b) | — |
| | — |
| | 190 |
| | 194 |
|
| | | | | | | |
Actual – Cooling (d) | 1,587 |
| | 1,424 |
| | 2,679 |
| | 2,612 |
|
Normal – Cooling (b) | 1,368 |
| | 1,367 |
| | 2,425 |
| | 2,413 |
|
| |
(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 20192020 Compared to Third Quarter of 20182019
| | | | | | | | |
Reconciliation of Third Quarter of 2019 to Third Quarter of 2020 | | |
Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities | | |
(in millions) | | |
| | |
Third Quarter of 2019 | | $ | 133.7 | |
| | |
Changes in Gross Margin: | | |
Retail Margins | | 54.8 | |
Margins from Off-system Sales | | (1.4) | |
Transmission Revenues | | 15.8 | |
Other Revenues | | (55.4) | |
Total Change in Gross Margin | | 13.8 | |
| | |
Changes in Expenses and Other: | | |
Other Operation and Maintenance | | (33.3) | |
Depreciation and Amortization | | 45.8 | |
Taxes Other Than Income Taxes | | (4.6) | |
Interest and Investment Income | | (0.2) | |
| | |
Allowance for Equity Funds Used During Construction | | (0.8) | |
Non-Service Cost Components of Net Periodic Benefit Cost | | (0.3) | |
Interest Expense | | (10.4) | |
Total Change in Expenses and Other | | (3.8) | |
| | |
Income Tax Expense | | 3.7 | |
| | |
Third Quarter of 2020 | | $ | 147.4 | |
|
| | | | |
Reconciliation of Third Quarter of 2018 to Third Quarter of 2019 |
Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities |
(in millions) |
| | |
Third Quarter of 2018 | | $ | 145.2 |
|
| | |
|
Changes in Gross Margin: | | |
|
Retail Margins | | 2.2 |
|
Margins from Off-system Sales | | 4.6 |
|
Transmission Revenues | | 17.3 |
|
Other Revenues | | 7.7 |
|
Total Change in Gross Margin | | 31.8 |
|
| | |
|
Changes in Expenses and Other: | | |
|
Other Operation and Maintenance | | 14.6 |
|
Depreciation and Amortization | | (7.9 | ) |
Taxes Other Than Income Taxes | | (8.6 | ) |
Interest and Investment Income | | (0.2 | ) |
Carrying Costs Income | | 0.1 |
|
Allowance for Equity Funds Used During Construction | | 2.0 |
|
Non-Service Cost Components of Net Periodic Benefit Cost | | (0.6 | ) |
Interest Expense | | (0.1 | ) |
Total Change in Expenses and Other | | (0.7 | ) |
| | |
|
Income Tax Expense (Benefit) | | (42.6 | ) |
| | |
|
Third Quarter of 2019 | | $ | 133.7 |
|
The major components of the increase in Gross Margin, defined as revenues less the related direct cost of purchased electricity and amortization of generation deferrals were as follows:
| |
• | •Retail Margins increased $55 million primarily due to the following: • increased $2 million primarily due to the following: |
A $27$52 million net increase primarily due to 2018 adjustments to the distribution decoupling under-recovery balance as a result of the 2018in Ohio Tax Reform settlementBasic Transmission Cost Rider revenues and changes in tax riders.recoverable PJM expenses. This increase was partially offset in Income Tax Expense (Benefit)Other Operation and Maintenance expenses below.
A $12•An $18 million increase due toin rider revenues in Ohio associated with the recovery of higher current year lossesDIR. This increase was partially offset in other expense items below.
•A $9 million increase in weather-normalized margins primarily in the residential class and partially offset in the commercial and industrial classes.
•A $6 million increase from a power contractinterim rate increases driven by increased distribution investment in Texas.
•A $5 million increase in revenues in Ohio associated with OVEC in Ohio.the Universal Service Fund (USF). This increase was offset in Margins from Off-system SalesOther Operation and Maintenance expenses below.
•A $9$5 million increase due to new base rates implemented in June 2020 in Texas.
•A $3 million increase in revenues associated with Ohio smart grid riders. This increase was partially offset in other expense items below.
These increases were partially offset by:
•A $19 million decrease due to refunds in Texas of Excess ADIT and excess federal income taxes collected as a result of Tax Reform. This decrease was offset in Income Tax Expense below.
•An $8$11 million increasedecrease in weather-related usage in Texas primarily due to an 11% increasea 14% decrease in cooling degree days.
•A $6 million increasedecrease due to the OVEC PPA Rider which was replaced by the Legacy Generation Resource Rider (LGRR). This decrease was offset in weather-normalized margins primarilyMargins from Off-system Sales and Other Revenues below.
•A $3 million decrease in the residential class.
A $4 million increase in Ohio rider revenues associated with the DIR.a vegetation management rider in Ohio. This decrease was partially offset in other expense items below.
A $3 million increase in Ohio Energy Efficiency/Peak Demand Reduction rider revenues. This increase was offset by a corresponding increase in Other Operation and Maintenance expenses below.
•A $3 million decrease due to refunds to customers associated with the most recent base rate case in Texas. This decrease was offset in Other Revenues below.
•Transmission Revenues increased $16 million primarily due to the following:
•An $11 million increase from interim rate increases driven by increased transmission investment in Texas.
•A $7 million increase in Ohio due to the annual transmission formula rate true-up.
•A $4 million increase primarily due to recovery of increased transmission investment in PJM.
These increases were partially offset by:
•A $28$7 million decrease due to refunds to customers associated with the most recent base rate case in Texas. This decrease was offset in Other Revenues below.
•Other Revenues decreased $55 million primarily due to the following:
•A $68 million decrease in securitization revenues due to the AEP Texas Central Transition Funding II LLC bonds that matured in July 2020. This increase was offset in Depreciation and Amortization expenses and Interest Expense below.
This decrease was partially offset by:
•An $8 million increase in revenues due to the amortization of a provision for refund recorded in December 2019 as part of the most recent base rate case in Texas. This increase was partially offset in Retail Margins and Transmission Revenues above.
Expenses and Other and Income Tax Expense changed between years as follows:
•Other Operation and Maintenance expenses increased $33 million primarily due to the following:
•A $50 million increase in transmission expenses primarily due to an increase in PJM and ERCOT expenses. This increase was offset in Gross Margin above.
•A $5 million increase in remitted USF 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.
These decreases were partially offset by:
•A $16 million decrease in distribution expenses. This decrease was partially offset in Gross Margins above.
•Depreciation and Amortization expenses decreased $46 million primarily due to the following:
•A $63 million decrease in securitization amortizations in Texas due to the AEP Texas Central Transition Funding II LLC bonds that matured in July 2020. This increase was offset in Other Revenues above and Interest Expense below.
This decrease was partially offset by:
•A $9 million increase in Ohio recoverable DIR depreciation expense. This increase was partially offset in Retail Margins above.
•A $5 million increase in depreciation expense due to an increase in the depreciable base of transmission and distribution assets.
•Taxes Other Than Income Taxes increased $5 million primarily due to property taxes driven by additional investments in transmission and distribution assets and higher tax rates.
•Interest Expense increased $10 million primarily due to higher long-term debt balances.
•Income Tax Expense decreased $4 million primarily due to an increase in amortization of Excess ADIT, partially offset by an increase in pretax book income. This decrease was partially offset in Gross Margins and Other Operation and Maintenance Expenses above.
Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019
| | | | | | | | |
Reconciliation of Nine Months Ended September 30, 2019 to Nine Months Ended September 30, 2020 | | |
Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities | | |
(in millions) | | |
| | |
Nine Months Ended September 30, 2019 | | $ | 421.6 | |
| | |
Changes in Gross Margin: | | |
Retail Margins | | 8.7 | |
Margins from Off-system Sales | | (17.3) | |
Transmission Revenues | | 31.7 | |
Other Revenues | | (24.6) | |
Total Change in Gross Margin | | (1.5) | |
| | |
Changes in Expenses and Other: | | |
Other Operation and Maintenance | | 63.9 | |
Depreciation and Amortization | | 1.4 | |
Taxes Other Than Income Taxes | | (7.2) | |
Interest and Investment Income | | (2.2) | |
Carrying Costs Income | | 0.6 | |
Allowance for Equity Funds Used During Construction | | 1.4 | |
Non-Service Cost Components of Net Periodic Benefit Cost | | (0.7) | |
Interest Expense | | (46.8) | |
Total Change in Expenses and Other | | 10.4 | |
| | |
Income Tax Expense | | (27.4) | |
| | |
Nine Months Ended September 30, 2020 | | $ | 403.1 | |
The major components of the decrease in Gross Margin, defined as revenues less the related direct cost of purchased electricity and amortization of generation deferrals were as follows:
•Retail Margins increased $9 million primarily due to the following:
•A $74 million net decreaseincrease in Ohio Basic Transmission Cost Rider revenues and recoverable PJM expenses. This decreaseincrease was partially offset in Other Operation and Maintenance expenses below.
•A $13$48 million increase in rider revenues in Ohio associated with the DIR. This increase was partially offset in other expense items below.
•A $15 million increase in revenues associated with Ohio smart grid riders. This increase was partially offset in other expense items below.
•A $15 million increase in revenues in Ohio associated with the USF. This increase was offset in Other Operation and Maintenance expenses below.
•An $8 million increase in weather-normalized margins primarily in the residential class and partially offset in the industrial and commercial classes.
•A $7 million increase from interim rate increases driven by increased transmission investment in Texas.
•A $7 million increase from interim rate increases driven by increased distribution investment in Texas.
•A $7 million increase due to new base rates implemented in June 2020 in Texas.
•A $5 million increase due to the change in the recording of merger savings as authorized by the PUCT in the most recent base rate case.
These increases were partially offset by:
•A $58 million decrease due to a reversal of a regulatory provision in Ohio in the first quarter of 2019.
•A $25 million decrease due to refunds in Texas of Excess ADIT and excess federal income taxes collected as a result of Tax Reform. This decrease was offset in Income Tax Expense below.
•A $23 million decrease in Ohio Deferred Asset Phase-In-Recovery Rider revenues which ended in the second quarter of 2019. This decrease was offset in Depreciation and Amortization expenses below.
•A $21 million decrease due to the OVEC PPA Rider which was replaced by the LGRR. This decrease was offset in Margins from Off-system Sales and Other Revenues below.
•A $17 million net decrease in margin in Ohio for the Rate Stability Rider including associated amortizations which ended in the third quarter of 2019.
•A $15 million decrease in weather-related usage in Texas primarily due to a 6% decrease in cooling degree days and a 46% decrease in heating degree days.
•A $6$9 million decrease in revenues associated with a vegetation management rider in Ohio. This decrease was offset in Other Operation and Maintenance expenses below.
•A $6 million net decrease in margin in Ohio for the Phase-In-Recovery Rider including associated amortizations which ended in the first quarter of 2019.
A $6$5 million decrease due to a PUCO order to refund unused 2018 major storm reserve collections to customers. This decrease was offset in affiliated PPA capacity revenuesOther Operation and Maintenance expenses below.
•A $4 million decrease due to refunds to customers associated with the most recent base rate case in Texas. This decrease was offset in Other Revenues below.
•Margins from Off-system Sales below.
| |
• | Margins from Off-system Sales increased $5 million primarily due to the following:
|
A decreased $17 million increaseprimarily due to higher affiliatedthe following:
•A $20 million decrease in Texas primarily due to lower Oklaunion Power Station PPA revenues in Texas.revenues. This increasedecrease was partially offset by in Other Operation and Maintenance expenses below.
This increase was partially offset by:
•A $12 million decrease primarilyin sales in Ohio due to higher current year losses from a power contract with OVEClower market prices and lower deferrals as a result of the OVEC PPA riderdecreased sales volumes in Ohio.2020. This decrease was offset in Retail Margins above.
| |
• | Transmission Revenues increased $17 million primarily due to the recovery of increased transmission investment in ERCOT.
|
| |
• | Other Revenues increased $8 million primarily due to securitization revenue related to Transition Funding. This decrease was offset below in Depreciation and Amortization expenses and in Interest Expense.
|
Expenses and Other and Income Tax Expense (Benefit) changed between years as follows:
| |
• | Other Operation and Maintenance expenses decreased $15 million primarily due to the following:
|
A $29 million decrease in transmission expenses that were fully recovered in rate riders/trackers in Gross Margin above.
A $4 million decrease due to higher charitable contributions in 2018 in Ohio.
These decreases were partially offset by:
•An $18 million increase in Ohio due to higher OVEC PPA deferrals. This increase was offset in Retail Margins above.
•Transmission Revenues increased $32 million primarily due to the following:
•A $30 million increase from interim rate increases driven by increased transmission investment in Texas.
•A $16 million increase in affiliated PPAOhio due to the annual transmission formula rate true-up.
•A $6 million increase due to additional investment in transmission assets in Ohio.
These increases were partially offset by:
•A $14 million decrease in Texas due to a one-time credit to transmission customers as a result of Tax Reform and the most recent base rate case. This decrease was offset in Income Tax Expense below.
•A $7 million decrease due to refunds to customers associated with the most recent base rate case in Texas. This decrease is offset in Other Revenues below.
•Other Revenues decreased $25 million primarily due to the following:
•A $49 million decrease in securitization revenue 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 $12 million increase in Ohio primarily due to third-party LGRR revenue related to the recovery of OVEC costs. This increase was offset in Retail Margins above.
•An $11 million increase in revenues due to the amortization of a provision for refund recorded in December 2019 as part of the most recent base rate case in Texas. This increase was offset in Retail Margins and Transmission Revenues above.
Expenses and Other and Income Tax Expense changed between years as follows:
•Other Operation and Maintenance expenses decreased $64 million primarily due to the following:
•A $67 million decrease due to prior year partial amortization of the AEP Texas Storm Restoration Securitization regulatory asset as a result of the AEP Texas Storm Cost Securitization financing order issued by an increasethe PUCT in June 2019. This decrease was offset in Income Tax Expense below.
•A $17 million decrease due to the revision of the Oklaunion Power Station ARO. This decrease was offset in Margins from Off-systemfor Off-System Sales above.
•A $12$15 million decrease in distribution expenses primarily due to vegetation management. This decrease was partially offset in Retail Margins above.
•A $5 million decrease due to a PUCO order to refund unused 2018 major storm reserve collections to customers. This decrease was offset in Retail Margins above.
These decreases were partially offset by:
•A $41 million increase in PJMtransmission expenses primarily due to a $68 million increase in recoverable PJM and ERCOT expenses partially offset by a $28 million decrease related to the annual PJM transmission formula rate true-up. This increase was offset in Gross Margin above.
| |
• | Depreciation and Amortization expenses increased $8 million primarily due to the following:
|
A $15 million increase in remitted USF 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.
•Depreciation and Amortization expenses decreased $1 million primarily due to the following:
•A $43 million decrease in securitization amortizations due to the AEP Texas Central Transition Funding II LLC bonds that matured in July 2020. This decrease was offset in Other Revenues above and Interest Expense below.
•A $24 million decrease in amortizations associated with the Deferred Asset Phase-In-Recovery Rider in Ohio which ended in the second quarter of 2019. This decrease was offset in Retail Margins above.
These decreases were partially offset by:
•A $27 million increase in depreciation expense due to an increase in the depreciable base of transmission and distribution assets.
•A $7$16 million increase in securitization amortizations primarily related to Transition Funding. This increase was offset in Other Revenues above and in Interest Expense below.
These increases were partially offset by:
| |
• | An $8million decrease in amortizations associated with the Deferred Asset Phase-In-Recovery Rider in Ohio which ended in the second quarter of 2019. This decrease was offset in Retail Margins above.
|
A $6 million decrease in Ohio recoverable DIR depreciation expense. This decreaseincrease was partially offset in Retail Margins above.
| |
•An $11 million increase due to lower deferred equity amortizations associated with the Deferred Asset Phase-In-Recovery Rider in Ohio which ended in the second quarter of 2019. • | Taxes Other Than Income Taxes increased $9 million primarily due to an increase in property taxes driven by additional investments in transmission and distribution assets and higher tax rates.
|
| |
• | Interest Expense was unchanged primarily due to the following:
|
A $5$7 million increase in amortizations primarily due to capitalized software.
•A $6 million increase in recoverable smart grid expense in Ohio. This increase was offset in Retail Margins above.
•Taxes Other Than Income Taxes increased $7 million primarily due to the following:
•A $13 million increase in property taxes driven by additional investments in transmission and distribution assets and higher tax rates.
This increase was partially offset by:
•A $4 million decrease in excise taxes due to lower demand in 2020 in Ohio. This decrease was offset in Retail Margins above.
•Interest Expense increased $47 million primarily due to the following:
•A $24 million increase due to the deferral of previously recorded interest expense approved for recovery as a result of the Texas Storm Cost Securitization financing order issued by the PUCT in June 2019.
•A $3 million decrease in expense related to Transition Funding Securitization assets. This decrease was offset in Other Revenues and Depreciation and Amortization expenses above.
These decreases were partially offset by:
A $6$21 million increase due to higher long-term debt balances.
| |
• | Income Tax Expense (Benefit) decreased $43 million primarily due to a one-time recognition of increased amortization of Excess ADIT not subject to normalization requirements as a result of the 2018 Ohio Tax Reform Settlement. This increase was partially offset in Retail Margins above.
|
Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018
|
| | | | |
Reconciliation of Nine Months Ended September 30, 2018 to Nine Months Ended September 30, 2019 |
Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities |
(in millions) |
| | |
Nine Months Ended September 30, 2018 | | $ | 384.6 |
|
| | |
|
Changes in Gross Margin: | | |
|
Retail Margins | | (9.3 | ) |
Margins from Off-system Sales | | 38.5 |
|
Transmission Revenues | | 68.2 |
|
Other Revenues | | 9.1 |
|
Total Change in Gross Margin | | 106.5 |
|
| | |
|
Changes in Expenses and Other: | | |
|
Other Operation and Maintenance | | (70.0 | ) |
Depreciation and Amortization | | (28.0 | ) |
Taxes Other Than Income Taxes | | (24.0 | ) |
Interest and Investment Income | | 1.6 |
|
Carrying Costs Income | | (0.8 | ) |
Allowance for Equity Funds Used During Construction | | (0.7 | ) |
Non-Service Cost Components of Net Periodic Benefit Cost | | (1.8 | ) |
Interest Expense | | 14.8 |
|
Total Change in Expenses and Other | | (108.9 | ) |
| | |
|
Income Tax Expense (Benefit) | | 39.4 |
|
| | |
|
Nine Months Ended September 30, 2019 | | $ | 421.6 |
|
The major components of the increase in Gross Margin, defined as revenues less the related direct cost of purchased electricity and amortization of generation deferrals were as follows:
| |
• | Retail Margins decreased $9 million primarily due to the following:
|
A $71 million net decrease in Ohio Basic Transmission Cost Rider revenues and recoverable PJM expenses. This decrease was partially offset in Other Operation and Maintenance expenses below.
An $18 million decrease in revenues associated with a vegetation management rider in Ohio. This decrease was offset in Other Operation and Maintenance expenses below.
A $17 million decrease in affiliated PPA capacity revenues in Texas. This decrease was offset in Margins from Off-system Sales below.
A $16 million net decrease in margin in Ohio for the Phase-In-Recovery Rider including associated amortizations which ended in the first quarter of 2019.
A $13 million decrease in Ohio Deferred Asset Phase-In-Recovery Rider revenues which ended in the second quarter of 2019. This decrease was offset in Depreciation and Amortization expenses below.
A $12 million net decrease in margin in Ohio for the Rate Stability Rider including associated amortizations which ended in the third quarter of 2019.
A $7 million decrease in Texas revenues associated with the Transmission Cost Recovery Factor revenue rider. This decrease was partially offset in Other Operation and Maintenance expenses below.
A $5 million decrease in weather-related usage in Texas primarily due to a 23% decrease in heating degree days partially offset by a 3% increase in cooling degree days.
A $4 million decrease in Ohio rider revenues associated with the DIR. This decrease was partially offset in other expense items below.
These decreases were partially offset by:
A $58 million increase due to a reversal of a regulatory provision in Ohio.
A $33 million net increase due to 2018 adjustments to the distribution decoupling under-recovery balance as a result of the 2018 Ohio Tax Reform settlement and changes in tax riders. This increase was partially offset in Income Tax Expense (Benefit) below.
A $31 million increase in revenues associated with Ohio smart grid riders. This increase was partially offset in other expense items below.
A $21 million increase due to the recovery of higher current year losses from a power contract with OVEC in Ohio. This increase was offset in Margins from Off-system Sales below.
A $9 million increase in Ohio Energy Efficiency/Peak Demand Reduction rider revenues. This increase was offset in Other Operation and Maintenance expenses below.
| |
• | Margins from Off-system Sales increased $39 million primarily due to the following:
|
A $59 million increase due to higher affiliated PPA revenues in Texas. This increase was partially offset in Other Operation and Maintenance expenses below.
This increase was partially offset by:
A $21 million decrease primarily due to higher current year losses from a power contract with OVEC as a result of the OVEC PPA rider in Ohio. This decrease was offset in Retail Margins above.
| |
• | Transmission Revenues increased $68 million primarily due to the following:
|
A $62 million increase primarily due to recovery of increased transmission investment in ERCOT.
A $6 million increase in Ohio primarily due to 2018 provisions for refunds.
| |
• | Other Revenues increased $9 million primarily due to distribution connection fees and pole attachment revenues.
|
Expenses and Other and Income Tax Expense (Benefit) changed between years as follows:
| |
• | Other Operation and Maintenance expenses increased $70 million primarily due to the following:
|
A $64 million increase in expense due to the partial amortization of the Texas Storm Cost Securitization regulatory asset as a result of the final PUCT order in the Texas Storm Cost Case. This increase was offset in Income Tax Expense (Benefit) below.
A $57 million increase in PJM expenses primarily related to the annual formula rate true-up.
A $49 million increase in affiliated PPA expenses in Texas. This increase was offset in Margins from Off-system Sales above.debt component of AFUDC.
These increases were partially offset by:
•A $93 million decrease in transmission expenses that were fully recovered in rate riders/trackers in Gross Margin above.
| |
• | Depreciation and Amortization expenses increased $28 million primarily due to the following:
|
A $51 million increase in depreciation expense due to an increase in the depreciable base of transmission and distribution assets.
A $9 million increase in securitization amortizations primarily related to Transition Funding. This increase was offset in Other Revenues above and in Interest Expense below.
A $7 million increase in depreciation expense related to the Oklaunion Power Station.
These increases were partially offset by:
A $30 million decrease in Ohio recoverable DIR depreciation expense. This decrease was partially offset in Retail Margins above.
An $11 million decrease in amortizations associated with the Deferred Asset Phase-In-Recovery Rider which ended in the second quarter of 2019. This decrease was offset in Retail Margins above.
| |
• | Taxes Other Than Income Taxes increased $24 million primarily due to an increase in property taxes driven by additional investments in transmission and distribution assets and higher tax rates.
|
| |
• | Interest Expense decreased $15 million primarily due to the following:
|
A $21$5 million decrease due to the deferral of previously recorded interest expense approved for recovery as a result of the Texas Storm Cost Securitization financing order issued by the PUCT in June 2019.lower short-term debt balances.
An $8•Income Tax Expense increased $27 million decrease in expense related to Transition Funding Securitization assets. This decrease was offset in Other Revenues and Depreciation and Amortization expenses above.
These decreases were partially offset by:
A $14 million increaseprimarily due to higher long-term debt balances.
| |
• | Income Tax Expense (Benefit) decreased $39 million primarily due to the following:
|
A $64 million decrease due to the prior year amortization of Excess ADIT not subject to normalization requirements as approved in the Texas Storm Cost Securitization financing order issued by the PUCT in June 2019. This increase was offset in Other Operation and Maintenance expenses above.
This decrease was2019 partially offset by:
A $30 million increase primarily due to a one-time recognition of increasedby current year amortization of Excess ADIT not subject to normalization requirements as a result of the 2018 Ohio Tax Reform Settlement.and an increase in favorable AFUDC Equity tax benefit. This increase was partially offset in RetailGross Margins and Other Operation and Maintenance Expenses above.
AEP TRANSMISSION HOLDCO
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | | | Nine Months Ended | | |
| | September 30, | | | | September 30, | | |
AEP Transmission Holdco | | 2020 | | 2019 | | 2020 | | 2019 |
| | (in millions) | | | | | | |
Transmission Revenues | | $ | 317.9 | | | $ | 273.0 | | | $ | 877.8 | | | $ | 808.3 | |
Other Operation and Maintenance | | 30.1 | | | 31.8 | | | 85.9 | | | 77.0 | |
Depreciation and Amortization | | 63.6 | | | 47.3 | | | 182.8 | | | 133.7 | |
Taxes Other Than Income Taxes | | 53.8 | | | 44.3 | | | 157.5 | | | 130.4 | |
Operating Income | | 170.4 | | | 149.6 | | | 451.6 | | | 467.2 | |
Interest and Investment Income | | 0.2 | | | 0.8 | | | 2.6 | | | 2.3 | |
| | | | | | | | |
| | | | | | | | |
Allowance for Equity Funds Used During Construction | | 20.3 | | | 21.0 | | | 54.9 | | | 61.1 | |
Non-Service Cost Components of Net Periodic Benefit Cost | | 0.5 | | | 0.7 | | | 1.5 | | | 2.0 | |
Interest Expense | | (34.0) | | | (27.8) | | | (99.0) | | | (73.8) | |
Income Before Income Tax Expense and Equity Earnings | | 157.4 | | | 144.3 | | | 411.6 | | | 458.8 | |
Income Tax Expense | | 38.2 | | | 35.4 | | | 101.3 | | | 105.7 | |
Equity Earnings of Unconsolidated Subsidiary | | 20.1 | | | 18.1 | | | 62.8 | | | 54.5 | |
Net Income | | 139.3 | | | 127.0 | | | 373.1 | | | 407.6 | |
Net Income Attributable to Noncontrolling Interests | | 1.0 | | | 0.9 | | | 2.7 | | | 2.8 | |
Earnings Attributable to AEP Common Shareholders | | $ | 138.3 | | | $ | 126.1 | | | $ | 370.4 | | | $ | 404.8 | |
|
| | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
AEP Transmission Holdco | | 2019 | | 2018 | | 2019 | | 2018 |
| | (in millions) |
Transmission Revenues | | $ | 273.0 |
| | $ | 187.2 |
| | $ | 808.3 |
| | $ | 605.2 |
|
Other Operation and Maintenance | | 31.8 |
| | 30.9 |
| | 77.0 |
| | 76.2 |
|
Depreciation and Amortization | | 47.3 |
| | 34.4 |
| | 133.7 |
| | 100.0 |
|
Taxes Other Than Income Taxes | | 44.3 |
| | 36.3 |
| | 130.4 |
| | 106.5 |
|
Operating Income | | 149.6 |
| | 85.6 |
| | 467.2 |
| | 322.5 |
|
Other Income | | 0.8 |
| | 0.4 |
| | 2.3 |
| | 1.1 |
|
Allowance for Equity Funds Used During Construction | | 21.0 |
| | 13.8 |
| | 61.1 |
| | 45.4 |
|
Non-Service Cost Components of Net Periodic Benefit Cost | | 0.7 |
| | 0.7 |
| | 2.0 |
| | 2.1 |
|
Interest Expense | | (27.8 | ) | | (24.2 | ) | | (73.8 | ) | | (66.8 | ) |
Income Before Income Tax Expense and Equity Earnings | | 144.3 |
| | 76.3 |
| | 458.8 |
| | 304.3 |
|
Income Tax Expense | | 35.4 |
| | 19.2 |
| | 105.7 |
| | 75.0 |
|
Equity Earnings of Unconsolidated Subsidiary | | 18.1 |
| | 17.1 |
| | 54.5 |
| | 51.6 |
|
Net Income | | 127.0 |
| | 74.2 |
| | 407.6 |
| | 280.9 |
|
Net Income Attributable to Noncontrolling Interests | | 0.9 |
| | 0.9 |
| | 2.8 |
| | 2.5 |
|
Earnings Attributable to AEP Common Shareholders | | $ | 126.1 |
| | $ | 73.3 |
| | $ | 404.8 |
| | $ | 278.4 |
|
Summary of Investment in Transmission Assets for AEP Transmission Holdco
| | | | | | | | | | | | | | |
| | September 30, | | |
| | 2020 | | 2019 |
| | (in millions) | | |
Plant in Service | | $ | 9,644.6 | | | $ | 7,796.9 | |
Construction Work in Progress | | 1,732.5 | | | 1,903.4 | |
Accumulated Depreciation and Amortization | | 553.1 | | | 383.7 | |
Total Transmission Property, Net | | $ | 10,824.0 | | | $ | 9,316.6 | |
|
| | | | | | | | |
| | September 30, |
| | 2019 | | 2018 |
| | (in millions) |
Plant in Service | | $ | 7,796.9 |
| | $ | 6,307.3 |
|
Construction Work in Progress | | 1,903.4 |
| | 1,823.0 |
|
Accumulated Depreciation and Amortization | | 383.7 |
| | 244.3 |
|
Total Transmission Property, Net | | $ | 9,316.6 |
| | $ | 7,886.0 |
|
Third Quarter of 20192020 Compared to Third Quarter of 20182019
Reconciliation of Third Quarter of 20182019 to Third Quarter of 20192020
Earnings Attributable to AEP Common Shareholders from AEP Transmission Holdco
(in millions)
| | | | | | | | |
Third Quarter of 2019 | | $ | 126.1 | |
| | |
Changes in Transmission Revenues: | | |
Transmission Revenues | | 44.9 | |
Total Change in Transmission Revenues | | 44.9 | |
| | |
Changes in Expenses and Other: | | |
Other Operation and Maintenance | | 1.7 | |
Depreciation and Amortization | | (16.3) | |
Taxes Other Than Income Taxes | | (9.5) | |
Interest and Investment Income | | (0.6) | |
| | |
Allowance for Equity Funds Used During Construction | | (0.7) | |
Non-Service Cost Components of Net Periodic Pension Cost | | (0.2) | |
Interest Expense | | (6.2) | |
Total Change in Expenses and Other | | (31.8) | |
| | |
Income Tax Expense | | (2.8) | |
Equity Earnings of Unconsolidated Subsidiary | | 2.0 | |
Net Income Attributable to Noncontrolling Interests | | (0.1) | |
| | |
Third Quarter of 2020 | | $ | 138.3 | |
|
| | | | |
Third Quarter of 2018 | | $ | 73.3 |
|
| | |
Changes in Transmission Revenues: | | |
Transmission Revenues | | 85.8 |
|
Total Change in Transmission Revenues | | 85.8 |
|
| | |
Changes in Expenses and Other: | | |
Other Operation and Maintenance | | (0.9 | ) |
Depreciation and Amortization | | (12.9 | ) |
Taxes Other Than Income Taxes | | (8.0 | ) |
Other Income | | 0.4 |
|
Allowance for Equity Funds Used During Construction | | 7.2 |
|
Interest Expense | | (3.6 | ) |
Total Change in Expenses and Other | | (17.8 | ) |
| | |
Income Tax Expense | | (16.2 | ) |
Equity Earnings of Unconsolidated Subsidiary | | 1.0 |
|
| | |
Third Quarter of 2019 | | $ | 126.1 |
|
The major components of the increase in transmission revenues, which consists of wholesale sales to affiliates and nonaffiliates, were as follows:
| |
• | Transmission Revenues •Transmission Revenues increased $45 million primarily due to continued investment in transmission assets.
increased $86 million primarily due to continued investment in transmission assets.
|
Expenses and Other and Income Tax Expense changed between years as follows:
| |
• | Depreciation and Amortization expenses increased $13 million primarily due to a higher depreciable base.
|
| |
• | Taxes Other Than Income Taxes increased $8 million primarily due to higher property taxes as a result of increased transmission investment.
|
| |
• | Allowance for Equity Funds Used During Construction increased $7 million primarily due to higher CWIP balances.
|
| |
• | Interest Expense increased $4 million primarily due to higher long-term debt balances.
|
| |
• | Income Tax Expense increased $16 million primarily due to higher pretax book income.
|
•Depreciation and Amortization expenses increased $16 million primarily due to a higher depreciable base.
•Taxes Other Than Income Taxes increased $10 million primarily due to higher property taxes as a result of increased transmission investment.
•Interest Expense increased $6 million primarily due to higher long-term debt balances.
Nine Months Ended September 30, 20192020 Compared to Nine Months Ended September 30, 20182019
Reconciliation of Nine Months Ended September 30, 20182019 to Nine Months Ended September 30, 20192020
Earnings Attributable to AEP Common Shareholders from AEP Transmission Holdco
(in millions)
| | | | | | | | |
Nine Months Ended September 30, 2019 | | $ | 404.8 | |
| | |
Changes in Transmission Revenues: | | |
Transmission Revenues | | 69.5 | |
Total Change in Transmission Revenues | | 69.5 | |
| | |
Changes in Expenses and Other: | | |
Other Operation and Maintenance | | (8.9) | |
Depreciation and Amortization | | (49.1) | |
Taxes Other Than Income Taxes | | (27.1) | |
Interest and Investment Income | | 0.3 | |
| | |
Allowance for Equity Funds Used During Construction | | (6.2) | |
Non-Service Cost Components of Net Periodic Pension Cost | | (0.5) | |
Interest Expense | | (25.2) | |
Total Change in Expenses and Other | | (116.7) | |
| | |
Income Tax Expense | | 4.4 | |
Equity Earnings of Unconsolidated Subsidiary | | 8.3 | |
Net Income Attributable to Noncontrolling Interests | | 0.1 | |
| | |
Nine Months Ended September 30, 2020 | | $ | 370.4 | |
|
| | | | |
Nine Months Ended September 30, 2018 | | $ | 278.4 |
|
| | |
Changes in Transmission Revenues: | | |
Transmission Revenues | | 203.1 |
|
Total Change in Transmission Revenues | | 203.1 |
|
| | |
Changes in Expenses and Other: | | |
Other Operation and Maintenance | | (0.8 | ) |
Depreciation and Amortization | | (33.7 | ) |
Taxes Other Than Income Taxes | | (23.9 | ) |
Other Income | | 1.2 |
|
Allowance for Equity Funds Used During Construction | | 15.7 |
|
Non-Service Cost Components of Net Periodic Pension Cost | | (0.1 | ) |
Interest Expense | | (7.0 | ) |
Total Change in Expenses and Other | | (48.6 | ) |
| | |
Income Tax Expense | | (30.7 | ) |
Equity Earnings of Unconsolidated Subsidiary | | 2.9 |
|
Net Income Attributable to Noncontrolling Interests | | (0.3 | ) |
| | |
Nine Months Ended September 30, 2019 | | $ | 404.8 |
|
The major components of the increase in transmission revenues, which consists of wholesale sales to affiliates and nonaffiliates, were as follows:
| |
• | •Transmission Revenues increased $70 million primarily due to the following: •A $149 million increase due to continued investment in transmission assets. This increase was partially offset by the following: •A $62 million decrease as a result of the affiliated annual transmission formula rate true-up which is offset in Other Operation and Maintenance expense across the other Registrant subsidiaries. •A $17 million decrease as a result of the non-affiliated annual transmission formula rate true-up. Transmission Revenues increased $203 million primarily due to continued investment in transmission assets.
|
Expenses and Other, and Income Tax Expense and Equity Earnings of Unconsolidated Subsidiary changed between years as follows:
| |
•Other Operation and Maintenance expenses increased $9 million primarily due to the following: • | Depreciation and Amortization expenses increased $34 million primarily due to a higher depreciable base.
|
| |
• | Taxes Other Than Income Taxes increased $24 million primarily due to higher property taxes as a result of increased transmission investment.
|
| |
• | Allowance for Equity Funds Used During Construction increased $16 million primarily due to the following:
|
A $13$5 million increase in rent expense.
•A $3 million increase in employee-related expenses.
•Depreciation and Amortization expenses increased $49 million primarily due to a higher depreciable base.
•Taxes Other Than Income Taxes increased $27 million primarily due to higher CWIP balances.property taxes as a result of increased transmission investment.
•Allowance for Equity Funds Used During Construction decreased $6 million primarily due to the following:
•A $12 million increasedecrease driven by the favorable impact of a FERC settlement agreement recorded in 2019.
•An $8 million decrease due to the FERC’s approval of a settlement agreement.lower CWIP.
These increasesdecreases were partially offset by:
•A $13 million decreaseincrease driven by FERC audit findings recorded in 2019.
•Interest Expense increased $25 million primarily due to recent FERC audit findings.higher long-term debt balances.
| |
• | Interest•Income Tax Expense decreased $4 million primarily due to lower pretax book income, partially offset by the recognition of a discrete tax adjustment in 2019. •Equity Earnings of Unconsolidated Subsidiary increased $8 million primarily due to higher pretax equity earnings at PATH-WV and ETT. increased $7 million primarily due to higher long-term debt balances. |
| |
• | Income Tax Expense increased $31 million primarily due to higher pretax book income with a partial offset due to the FERC’s approval of a settlement agreement.
|
GENERATION & MARKETING
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | | | Nine Months Ended | | |
| | September 30, | | | | September 30, | | |
Generation & Marketing | | 2020 | | 2019 | | 2020 | | 2019 |
| | (in millions) | | | | | | |
Revenues | | $ | 490.0 | | | $ | 533.7 | | | $ | 1,305.5 | | | $ | 1,428.2 | |
Fuel, Purchased Electricity and Other | | 391.6 | | | 403.8 | | | 1,050.4 | | | 1,117.8 | |
| | | | | | | | |
Gross Margin | | 98.4 | | | 129.9 | | | 255.1 | | | 310.4 | |
Other Operation and Maintenance | | 27.2 | | | 44.0 | | | 85.1 | | | 158.0 | |
| | | | | | | | |
| | | | | | | | |
Depreciation and Amortization | | 18.5 | | | 20.6 | | | 54.1 | | | 49.1 | |
Taxes Other Than Income Taxes | | 3.3 | | | 4.4 | | | 10.4 | | | 11.8 | |
Operating Income | | 49.4 | | | 60.9 | | | 105.5 | | | 91.5 | |
Interest and Investment Income | | 0.4 | | | 1.9 | | | 2.6 | | | 6.0 | |
| | | | | | | | |
Non-Service Cost Components of Net Periodic Benefit Cost | | 3.9 | | | 3.8 | | | 11.6 | | | 11.2 | |
Interest Expense | | (3.8) | | | (10.5) | | | (20.5) | | | (21.5) | |
Income Before Income Tax Benefit and Equity Earnings (Loss) | | 49.9 | | | 56.1 | | | 99.2 | | | 87.2 | |
Income Tax Benefit | | (70.9) | | | (36.4) | | | (104.3) | | | (51.8) | |
Equity Earnings (Loss) of Unconsolidated Subsidiaries | | (6.2) | | | (3.8) | | | 0.1 | | | (5.9) | |
Net Income | | 114.6 | | | 88.7 | | | 203.6 | | | 133.1 | |
Net Loss Attributable to Noncontrolling Interests | | (2.1) | | | (1.3) | | | (7.4) | | | (6.4) | |
Earnings Attributable to AEP Common Shareholders | | $ | 116.7 | | | $ | 90.0 | | | $ | 211.0 | | | $ | 139.5 | |
|
| | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
Generation & Marketing | | 2019 | | 2018 | | 2019 | | 2018 |
| | (in millions) |
Revenues | | $ | 533.7 |
| | $ | 521.6 |
| | $ | 1,428.2 |
| | $ | 1,487.4 |
|
Fuel, Purchased Electricity and Other | | 403.8 |
| | 405.0 |
| | 1,117.8 |
| | 1,167.8 |
|
Gross Margin | | 129.9 |
| | 116.6 |
| | 310.4 |
| | 319.6 |
|
Other Operation and Maintenance | | 44.0 |
| | 68.2 |
| | 158.0 |
| | 192.6 |
|
Asset Impairments and Other Related Charges | | — |
| | 35.0 |
| | — |
| | 35.0 |
|
Depreciation and Amortization | | 20.6 |
| | 12.0 |
| | 49.1 |
| | 26.4 |
|
Taxes Other Than Income Taxes | | 4.4 |
| | 3.7 |
| | 11.8 |
| | 10.3 |
|
Operating Income (Loss) | | 60.9 |
| | (2.3 | ) | | 91.5 |
| | 55.3 |
|
Interest and Investment Income | | 1.9 |
| | 3.6 |
| | 6.0 |
| | 9.9 |
|
Non-Service Cost Components of Net Periodic Benefit Cost | | 3.8 |
| | 3.8 |
| | 11.2 |
| | 11.5 |
|
Interest Expense | | (10.5 | ) | | (3.8 | ) | | (21.5 | ) | | (11.7 | ) |
Income Before Income Tax Expense (Benefit) and Equity Earnings (Loss) | | 56.1 |
| | 1.3 |
| | 87.2 |
| | 65.0 |
|
Income Tax Expense (Benefit) | | (36.4 | ) | | (3.6 | ) | | (51.8 | ) | | 3.7 |
|
Equity Earnings (Loss) of Unconsolidated Subsidiaries | | (3.8 | ) | | 0.2 |
| | (5.9 | ) | | 0.5 |
|
Net Income | | 88.7 |
| | 5.1 |
| | 133.1 |
| | 61.8 |
|
Net Loss Attributable to Noncontrolling Interests | | (1.3 | ) | | (0.2 | ) | | (6.4 | ) | | (0.5 | ) |
Earnings Attributable to AEP Common Shareholders | | $ | 90.0 |
| | $ | 5.3 |
| | $ | 139.5 |
| | $ | 62.3 |
|
Summary of MWhs Generated for Generation & Marketing
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | | | Nine Months Ended September 30, | | |
| | 2020 | | 2019 | | 2020 | | 2019 |
| | (in millions of MWhs) | | | | | | |
Fuel Type: | | | | | | | | |
Coal | | 1 | | | 2 | | | 3 | | | 4 | |
Renewables | | — | | | 1 | | | 2 | | | 2 | |
| | | | | | | | |
Total MWhs | | 1 | | | 3 | | | 5 | | | 6 | |
|
| | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2019 | | 2018 | | 2019 | | 2018 |
| (in millions of MWhs) |
Fuel Type: | |
| | |
| | |
| | |
|
Coal | 2 |
| | 4 |
| | 4 |
| | 10 |
|
Renewables | 1 |
| | — |
| | 2 |
| | 1 |
|
Total MWhs | 3 |
| | 4 |
| | 6 |
| | 11 |
|
Third Quarter of 20192020 Compared to Third Quarter of 20182019
|
| | | | |
Reconciliation of Third Quarter of 2018 to Third Quarter of 2019 |
Earnings Attributable to AEP Common Shareholders from Generation & Marketing |
(in millions) |
| | |
Third Quarter of 2018 | | $ | 5.3 |
|
| | |
|
Changes in Gross Margin: | | |
|
Generation | | (10.6 | ) |
Retail, Trading and Marketing | | 12.9 |
|
Other Revenues | | 11.0 |
|
Total Change in Gross Margin | | 13.3 |
|
| | |
|
Changes in Expenses and Other: | | |
|
Other Operation and Maintenance | | 24.2 |
|
Asset Impairments and Other Related Charges | | 35.0 |
|
Depreciation and Amortization | | (8.6 | ) |
Taxes Other Than Income Taxes | | (0.7 | ) |
Interest and Investment Income | | (1.7 | ) |
Interest Expense | | (6.7 | ) |
Total Change in Expenses and Other | | 41.5 |
|
| | |
|
Income Tax Expense (Benefit) | | 32.8 |
|
Equity Earnings (Loss) of Unconsolidated Subsidiaries | | (4.0 | ) |
Net Loss Attributable to Noncontrolling Interests | | 1.1 |
|
| | |
|
Third Quarter of 2019 | | $ | 90.0 |
|
The major components of the increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, purchased electricity and certain cost of service for retail operations were as follows:
| | | | | | | | |
• | Generation decreased $11 million primarily dueReconciliation of Third Quarter of 2019 to reduction in capacity revenues in 2019 partially due to the retirementThird Quarter of Conesville Units 5 & 6 in 2019.2020
|
| |
•Earnings Attributable to AEP Common Shareholders from Generation & Marketing | | |
(in millions) | | |
| | |
Third Quarter of 2019 | | $ | 90.0 | |
| | |
Changes in Gross Margin: | | |
Merchant Generation | | (24.3) | |
Renewable Generation | | (4.1) | |
Retail, Trading and Marketing | | increased $13 million due to higher trading and marketing activity in 2019.(3.1) |
| |
•Total Change in Gross Margin | | Other Revenues (31.5)increased $11 million primarily due to the Sempra Renewables LLC acquisition and other renewable projects placed in-service. |
Expenses and Other, Income Tax Expense (Benefit) and Net Loss Attributable to Noncontrolling Interests changed between years as follows:
| |
• | | |
Changes in Expenses and Other: | | |
Other Operation and Maintenance | | expenses decreased $24 million due to the following:16.8 | |
A $20 million decrease due to the retirement of Conesville Units 5 & 6 in 2019.
An $11 million decrease due to the retirement of Stuart Plant in June of 2018.
These decreases were partially offset by:
A $7 million increase due to the acquisitions of Sempra Renewables LLC and Santa Rita East.
| | |
• | Asset Impairment and Other Related Charges decreased $35 million due to the impairment of Racine in the third quarter of 2018.
|
| |
• | Depreciation and Amortization | | expenses increased $9 million due to a higher depreciable base from increased investments in wind farms2.1 | |
Taxes Other Than Income Taxes | | 1.1 | |
Interest and renewable energy sources.Investment Income | | (1.5) | |
| | |
• | Interest Expense increased $7 million primarily due to increased borrowing costs related to the Sempra Renewables LLC acquisition.
|
| |
•Non-Service Cost Components of Net Periodic Benefit Cost | | Income Tax Expense (Benefit)0.1 decreased $33 million primarily due to an increase in projected renewable PTC primarily driven by the Sempra Renewables LLC acquisition partially offset by an increase in pretax book income. |
| |
•Interest Expense | | 6.7 | |
Total Change in Expenses and Other | | 25.3 | |
| | |
Income Tax Benefit | | 34.5 | |
Equity Earnings (Loss) of Unconsolidated Subsidiaries | | decreased $4 million primarily due(2.4) | |
Net Loss Attributable to the Sempra Renewables LLC acquisition.Noncontrolling Interests | | 0.8 | |
| | |
Third Quarter of 2020 | | $ | 116.7 | |
Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018
|
| | | | |
Reconciliation of Nine Months Ended September 30, 2018 to Nine Months Ended September 30, 2019 |
Earnings Attributable to AEP Common Shareholders from Generation & Marketing |
(in millions) |
| | |
Nine Months Ended September 30, 2018 | | $ | 62.3 |
|
| | |
|
Changes in Gross Margin: | | |
|
Generation | | (55.1 | ) |
Retail, Trading and Marketing | | 28.0 |
|
Other Revenues | | 17.9 |
|
Total Change in Gross Margin | | (9.2 | ) |
| | |
|
Changes in Expenses and Other: | | |
|
Other Operation and Maintenance | | 34.6 |
|
Asset Impairments and Other Related Charges | | 35.0 |
|
Depreciation and Amortization | | (22.7 | ) |
Taxes Other Than Income Taxes | | (1.5 | ) |
Interest and Investment Income | | (3.9 | ) |
Non-Service Cost Components of Net Periodic Benefit Cost | | (0.3 | ) |
Interest Expense | | (9.8 | ) |
Total Change in Expenses and Other | | 31.4 |
|
| | |
|
Income Tax Expense (Benefit) | | 55.5 |
|
Equity Earnings (Loss) of Unconsolidated Subsidiaries | | (6.4 | ) |
Net Loss Attributable to Noncontrolling Interests | | 5.9 |
|
| | |
|
Nine Months Ended September 30, 2019 | | $ | 139.5 |
|
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 decreased $24 million primarily due to lower capacity revenues and energy margins in 2020 and the retirement of the Conesville Plant Units 5 and 6 in 2019 and Unit 4 in 2020. •Renewable Generation decreased $4 million primarily due to lower wind production. •Retail, Trading and Marketing decreased $3 million due to lower trading and marketing activity, partially offset by higher retail margins.
decreased $55 million primarily due to the reduction of capacity revenues and energy margins in 2019, a reduction in revenues due to the retirement of the Stuart Plant in 2018 and the retirement of Conesville Units 5 & 6 in 2019.
|
| |
• | Retail, Trading and Marketing increased $28 million primarily due to higher retail margins due to lower market costs and higher delivered volumes and higher marketing activity in 2019.
|
| |
• | Other Revenues increased $18 million primarily due to the Sempra Renewables LLC acquisition and other renewable projects placed in-service.
|
Expenses and Other and Income Tax Expense (Benefit), Equity Earnings (Loss) of Unconsolidated Subsidiaries and Net Loss Attributable to Noncontrolling InterestsBenefit changed between years as follows:
| |
• | Other Operation and Maintenance expenses decreased $35 million due to the following:
|
A $40•Other Operation and Maintenance expenses decreased $17 million primarily due to the following:
•An $11 million decrease due to a gain recorded on the sale of land.
•An $8 million decrease due to the retirement of Conesville Plant Units 5 &and 6 in 2019.2019 and Unit 4 in 2020.
•Interest Expense decreased $7 million due to lower borrowing costs in 2020.
•Income Tax Benefit increased $35 million primarily due to the recognition of a discrete tax adjustment in 2020, which was attributable to the CARES Act offset by a decrease in PTC.
Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019
| | | | | | | | |
Reconciliation of Nine Months Ended September 30, 2019 to Nine Months Ended September 30, 2020 | | |
Earnings Attributable to AEP Common Shareholders from Generation & Marketing | | |
(in millions) | | |
| | |
Nine Months Ended September 30, 2019 | | $ | 139.5 | |
| | |
Changes in Gross Margin: | | |
Merchant Generation | | (78.3) | |
Renewable Generation | | 17.4 | |
Retail, Trading and Marketing | | 5.6 | |
Total Change in Gross Margin | | (55.3) | |
| | |
Changes in Expenses and Other: | | |
Other Operation and Maintenance | | 72.9 | |
| | |
| | |
Depreciation and Amortization | | (5.0) | |
Taxes Other Than Income Taxes | | 1.4 | |
Interest and Investment Income | | (3.4) | |
| | |
Non-Service Cost Components of Net Periodic Benefit Cost | | 0.4 | |
Interest Expense | | 1.0 | |
Total Change in Expenses and Other | | 67.3 | |
| | |
Income Tax Benefit | | 52.5 | |
Equity Earnings (Loss) of Unconsolidated Subsidiaries | | 6.0 | |
Net Loss Attributable to Noncontrolling Interests | | 1.0 | |
| | |
Nine Months Ended September 30, 2020 | | $ | 211.0 | |
The major components of the decrease in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, purchased electricity and certain cost of service for retail operations were as follows:
•Merchant Generation decreased $78 million primarily due to the reduction of capacity revenues and energy margins in 2020 and the retirement of the Conesville Plant Units 5 and 6 in 2019 and Unit 4 in 2020.
•Renewable Generation increased $17 million primarily due to the Sempra Renewables LLC acquisition and other renewable projects placed in-service.
•Retail, Trading and Marketing increased $6 million due to higher trading and marketing activity, partially offset by lower retail margins.
Expenses and Other, Income Tax Benefit and Equity Earnings (Loss) of Unconsolidated Subsidiaries changed between years as follows:
•Other Operation and Maintenance expenses decreased $73 million due to the following:
•A $15$34 million decrease due to the retirement of StuartConesville Plant Units 5 and 6 in June2019 and Unit 4 in 2020.
•A $26 million decrease due to a gain recorded on the sale of 2018.land.
These decreases were partially offset by:•A $16 million decrease related to the Oklaunion PPA with AEP Texas primarily due to an ARO revision.
A $20•Depreciation and Amortization expenses increased $5 million due to a higher depreciable base from increased investments in renewable energy sources.
•Interest and Investment Income decreased $3 million due to lower returns on investments.
•Income Tax Benefit increased $53 million primarily due the recognition of a discrete tax adjustment in 2020, which was attributable to the CARES Act and an increase in PTC.
•Equity Earnings (Loss) of Unconsolidated Subsidiaries increased $6 million primarily due to the acquisitions of Sempra Renewables LLC and Santa Rita East.
| |
• | Asset Impairment and Other Related Charges decreased $35 million due to the impairment of Racine in the third quarter of 2018.
|
| |
• | Depreciation and Amortization expenses increased $23 million due to a higher depreciable base from increased investments in wind farms and renewable energy sources.
|
| |
• | Interest and Investment Income decreased $4 million primarily due to a reduction in Advances to Affiliates which was driven by a dividend payment made to Parent in 2018.
|
| |
• | Interest Expense increased $10 million primarily due to increased borrowing costs related to the Sempra Renewables LLC acquisition.
|
| |
• | Income Tax Expense (Benefit) decreased $56 million primarily due to an increase in projected renewable PTC primarily driven by the Sempra Renewables LLC acquisition partially offset by an increase in pretax book income.
|
| |
• | Equity Earnings (Loss) of Unconsolidated Subsidiaries decreased $6 million primarily due to the Sempra Renewables LLC acquisition.
|
| |
• | Net Loss Attributable to Noncontrolling Interests increased $6 million primarily due to the Sempra Renewables LLC acquisition.
|
CORPORATE AND OTHER
Third Quarter of 20192020 Compared to Third Quarter of 20182019
Earnings Attributable to AEP Common Shareholders from Corporate and Other decreasedincreased from $10 million in 2018 to a loss of $54 million in 2019 to a loss of $47 million in 2020 primarily due to:
•A $40$12 million increasedecrease in income tax expense due to an increasea decrease in consolidating tax adjustments. This increase is offset primarily within the Generation & Marketing segment.
•A $20$6 million increasedecrease in interest expense as a result of increaseda decrease in debt outstanding.
These items were partially offset by:
•A $5 million increase in general corporate expenses.
•A $6 million decrease in interest income.
Nine Months Ended September 30, 20192020 Compared to Nine Months Ended September 30, 20182019
Earnings Attributable to AEP Common Shareholders from Corporate and Other decreasedincreased from a loss of $17 million in 2018 to a loss of $116 million in 2019 to a loss of $115 million in 2020 primarily due to:
•An $11 million decrease in general corporate expenses.
•A $63$5 million increasewrite-off of an equity investment and related assets in 2019.
•A $2 million decrease in income tax expense primarily due to the following:
A $30 million increase due todiscrete items recorded in 2020, partially offset by an increase in consolidating tax adjustments. This increase is
These items were partially offset primarily within the Generation & Marketing segment.by:
•An $18$8 million increase related to the enactment of the Kentucky state tax legislationdecrease in the second quarter of 2018.interest income.
A $10 million increase due to an increase in the allocation of the parent company loss benefit due to the tax sharing agreement with AEP Subsidiaries.
A $5 million increase due to the current year revaluation of AEP’s state deferred tax liability as a result of the state income tax filing requirement in Kansas associated with the Sempra Renewables LLC acquisition.
A $55•An $8 million increase in interest expense as a result of increasedan increase in debt outstanding.
A $5 million impairment of an equity investment and related assets in 2019.
These items were partially offset by:
A $20 million impairment of an equity investment and related assets in 2018.
An $8 million increase in interest income due to a higher return on investments held by EIS.
AEP SYSTEM INCOME TAXES
Third Quarter of 20192020 Compared to Third Quarter of 20182019
Income Tax Expense (Benefit) increased $121decreased $42 million primarily due to the prior year effectsrecognition of a $52 million discrete tax adjustment in 2020, which was attributable to the 5-year net operating loss carryback provision of the discrete impact of $124 million of amortization of Excess ADIT not subject to normalization requirements as a result of the Ohio and West Virginia Tax Reform Orders received in the third quarter of 2018.CARES Act.
Nine Months Ended September 30, 20192020 Compared to Nine Months Ended September 30, 20182019
Income Tax Expense (Benefit) decreased $63increased $27 million primarily due to increaseda decrease in amortization of Excess ADIT, not subjectpartially offset by the recognition of the discrete tax adjustment in 2020, which was attributable to normalization requirements as a resultthe 5-year net operating loss carryback provision of finalized Tax Reform orders and an increase in projected renewable income tax credits.the CARES Act.
FINANCIAL CONDITION
AEP measures financial condition by the strength of its balance sheet and the liquidity provided by its cash flows.
LIQUIDITY AND CAPITAL RESOURCES
Debt and Equity Capitalization
| | | | | | | | | | | | | | | | | | | | | | | |
| September 30, 2020 | | | | December 31, 2019 | | |
| (dollars in millions) | | | | | | |
Long-term Debt, including amounts due within one year | $ | 30,067.1 | | | 56.6 | % | | $ | 26,725.5 | | | 54.1 | % |
Short-term Debt | 2,397.0 | | | 4.5 | | | 2,838.3 | | | 5.7 | |
Total Debt | 32,464.1 | | | 61.1 | | | 29,563.8 | | | 59.8 | |
AEP Common Equity | 20,365.9 | | | 38.4 | | | 19,632.2 | | | 39.6 | |
Noncontrolling Interests | 268.7 | | | 0.5 | | | 281.0 | | | 0.6 | |
Total Debt and Equity Capitalization | $ | 53,098.7 | | | 100.0 | % | | $ | 49,477.0 | | | 100.0 | % |
|
| | | | | | | | | | | | | |
| September 30, 2019 | | December 31, 2018 |
| (dollars in millions) |
Long-term Debt, including amounts due within one year | $ | 25,881.2 |
| | 53.5 | % | | $ | 23,346.7 |
| | 52.7 | % |
Short-term Debt | 2,510.0 |
| | 5.2 |
| | 1,910.0 |
| | 4.3 |
|
Total Debt | 28,391.2 |
| | 58.7 |
| | 25,256.7 |
| | 57.0 |
|
AEP Common Equity | 19,716.4 |
| | 40.7 |
| | 19,028.4 |
| | 42.9 |
|
Noncontrolling Interests | 281.3 |
| | 0.6 |
| | 31.0 |
| | 0.1 |
|
Total Debt and Equity Capitalization | $ | 48,388.9 |
| | 100.0 | % | | $ | 44,316.1 |
| | 100.0 | % |
AEP’s ratio of debt-to-total capital increased from 57%59.8% as of December 31, 20182019 to 58.7%61.1% as of September 30, 20192020 primarily due to an increase in debt to support distribution, transmission and renewable investment growth.
Liquidity
Liquidity, or access to cash, is an important factor in determining AEP’s financial stability. Management believes AEP has adequate liquidity under its existing credit facilities. As of September 30, 2019,2020, AEP had a $4 billion revolving credit facility 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. There was increased volatility in the capital markets during the first quarter of 2020 resulting in higher commercial paper cost and limited access. To address these issues and the uncertainty around COVID-19, in March 2020, AEP entered into a $1 billion 364-day Term Loan and borrowed the full amount.
Net Available Liquidity
AEP manages liquidity by maintaining adequate external financing commitments. As of September 30, 2019,2020, available liquidity was approximately $2.6$3.8 billion as illustrated in the table below:
| | | | | | | | | | | | | | |
| | Amount | | Maturity |
Commercial Paper Backup: | | (in millions) | | |
| Revolving Credit Facility | $ | 4,000.0 | | | June 2022 |
| 364-Day Term Loan | 1,000.0 | | | March 2021 |
Cash and Cash Equivalents | | 409.7 | | | |
Total Liquidity Sources | | 5,409.7 | | | |
Less: | AEP Commercial Paper Outstanding | 650.0 | | | |
| 364-Day Term Loan | 1,000.0 | | | |
| | | | |
Net Available Liquidity | | $ | 3,759.7 | | | |
|
| | | | | | |
| | Amount |
| Maturity |
Commercial Paper Backup: | (in millions) |
|
|
| Revolving Credit Facility | $ | 4,000.0 |
|
| June 2022 |
Cash and Cash Equivalents | 348.8 |
| | |
Total Liquidity Sources | 4,348.8 |
| | |
Less: | AEP Commercial Paper Outstanding | 1,760.0 |
| | |
|
| | | |
Net Available Liquidity | $ | 2,588.8 |
| | |
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 20192020 was $2.2$3 billion. The weighted-average interest rate for AEP’s commercial paper during 20192020 was 2.66%1.56%.
Other Credit Facilities
An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility. AEP issues letters of credit on behalf of subsidiaries under six uncommitted facilities totaling $405 million. The Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities as of September 30, 20192020 was $204$197 million with maturities ranging from October 2019 to October 2020. to August 2021.
Securitized Accounts Receivables
AEP’s receivables securitization agreement provides a commitment of $750 million from bank conduits to purchase receivables and expires in July 2021.September 2022.
In May 2020, AEP Credit amended its receivables securitization agreement to increase the eligibility criteria related to aged receivable requirements for the participating affiliated utility subsidiaries in response to the COVID-19 pandemic. As of September 30, 2020, the affiliated utility subsidiaries are in compliance with all requirements under the agreement. To the extent that an affiliated utility subsidiary is deemed ineligible under the agreement, receivables would no longer be purchased by the bank conduits and the Registrants would need to rely on additional sources of funding for operation and working capital, which may adversely impact liquidity.
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, 2019,2020, this contractually-defined percentage was 55.3%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 facility does not permit the lenders to refuse a draw on any facility if a material adverse change occurs.
Utility Money Pool borrowings and external borrowings may not exceed amounts authorized by regulatory orders and AEP manages its borrowings to stay within those authorized limits.
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 settles after three years in 2022. The proceeds from this issuance were used to support AEP’s overall capital expenditure plans including the recent acquisition of Sempra Renewables LLC.
See Note 1312 - Financing Activities for additional information.
Dividend Policy and Restrictions
The Board of Directors declared a quarterly dividend of $0.70$0.74 per share in October 2019.2020. 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 1312 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, | | |
| 2020 | | 2019 |
| (in millions) | | |
Cash, Cash Equivalents and Restricted Cash at Beginning of Period | $ | 432.6 | | | $ | 444.1 | |
Net Cash Flows from Operating Activities | 2,922.2 | | | 3,349.9 | |
Net Cash Flows Used for Investing Activities | (4,707.3) | | | (5,357.6) | |
Net Cash Flows from Financing Activities | 1,816.3 | | | 2,053.4 | |
| | | |
Net Increase in Cash, Cash Equivalents and Restricted Cash | 31.2 | | | 45.7 | |
Cash, Cash Equivalents and Restricted Cash at End of Period | $ | 463.8 | | | $ | 489.8 | |
|
| | | | | | | |
| Nine Months Ended September 30, |
| 2019 | | 2018 |
| (in millions) |
Cash, Cash Equivalents and Restricted Cash at Beginning of Period | $ | 444.1 |
| | $ | 412.6 |
|
Net Cash Flows from Operating Activities | 3,349.9 |
| | 3,932.6 |
|
Net Cash Flows Used for Investing Activities | (5,357.6 | ) | | (4,688.7 | ) |
Net Cash Flows from Financing Activities | 2,053.4 |
| | 1,281.0 |
|
Net Increase in Cash, Cash Equivalents and Restricted Cash | 45.7 |
| | 524.9 |
|
Cash, Cash Equivalents and Restricted Cash at End of Period | $ | 489.8 |
| | $ | 937.5 |
|
Operating Activities
| | | | | | | | | | | |
| Nine Months Ended September 30, | | |
| 2020 | | 2019 |
| (in millions) | | |
Net Income | $ | 1,762.0 | | | $ | 1,767.1 | |
Non-Cash Adjustments to Net Income (a) | 2,094.3 | | | 1,838.8 | |
Mark-to-Market of Risk Management Contracts | 46.4 | | | (41.6) | |
Pension Contributions to Qualified Plan Trust | (110.3) | | | — | |
Property Taxes | 396.9 | | | 341.7 | |
Deferred Fuel Over/Under-Recovery, Net | 27.4 | | | 93.7 | |
Recovery of Ohio Capacity Costs | — | | | 34.1 | |
Refund of Global Settlement | — | | | (12.4) | |
Change in Other Noncurrent Assets | (219.6) | | | (9.6) | |
Change in Other Noncurrent Liabilities | (25.1) | | | (16.3) | |
Change in Certain Components of Working Capital | (1,049.8) | | | (645.6) | |
Net Cash Flows from Operating Activities | $ | 2,922.2 | | | $ | 3,349.9 | |
|
| | | | | | | |
| Nine Months Ended September 30, |
| 2019 | | 2018 |
| (in millions) |
Net Income | $ | 1,767.1 |
| | $ | 1,566.5 |
|
Non-Cash Adjustments to Net Income (a) | 1,838.8 |
| | 1,728.7 |
|
Mark-to-Market of Risk Management Contracts | (41.6 | ) | | (95.4 | ) |
Property Taxes | 341.7 |
| | 304.8 |
|
Deferred Fuel Over/Under-Recovery, Net | 93.7 |
| | 210.6 |
|
Recovery of Ohio Capacity Costs | 34.1 |
| | 52.7 |
|
Refund of Global Settlement | (12.4 | ) | | (5.5 | ) |
Change in Other Noncurrent Assets | (9.6 | ) | | 161.6 |
|
Change in Other Noncurrent Liabilities | (16.3 | ) | | 141.9 |
|
Change in Certain Components of Working Capital | (645.6 | ) | | (133.3 | ) |
Net Cash Flows from Operating Activities | $ | 3,349.9 |
| | $ | 3,932.6 |
|
(a)Non-Cash Adjustments to Net Income includes Depreciation and Amortization, Deferred Income Taxes, AFUDC and Amortization of Nuclear Fuel.
| |
(a) | Non-Cash Adjustments to Net Income includes Depreciation and Amortization, Deferred Income Taxes, AFUDC and Amortization of Nuclear Fuel. |
Net Cash Flows from Operating Activities decreased by $583$428 million primarily due to the following:
•A $512$404 million decrease in cash from the Change in Certain Components of Working Capital. The decrease is primarily due to timing of accounts receivable, an increase in purchases of fuel, material and supplies, decreased accrued taxes, higher employee-related payments and refund related to Tax Reform, partially offset by receivablesa decrease in accrued taxes primarily due to the changes in timing.increased property tax payments.
•A $171$210 million decrease in cash from ChangeChanges in Other Noncurrent Assets primarily due to a change in regulatory assets as a result of AEP subsidiaries with rider recovery mechanisms.deferred storm costs related to Hurricane Laura in 2020 and the settlement of deferred restoration costs from the Texas Storm Cost Securitization financing order received in 2019. See Note 4 - Rate Matters for additional information.
•A $158$110 million decrease in cash from Change in Other Noncurrent Liabilities primarily due to decreased Accumulated Provisionsa discretionary contribution to the qualified pension plan. See Note 7 - Benefit Plans for Rate Refunds as a result of Tax Reform
A $117 million decrease in cash from Deferred Fuel Over/Under Recovery, Net primarily due to fluctuations APCo and WPCo as a result of the 2018 West Virginia Tax Reform Order, the full recovery of Ohio Phase in recovery rider and the fluctuations of fuel and purchase power cost at PSO.additional information.
These decreases in cash were partially offset by:
•A $310$250 million increase in cash from Income from Continuing Operations, after non-cash adjustments. See Results of Operations for further detail.
•An $88 million increase in fair value of risk management contracts due to pricing movement in the commodities markets.
Investing Activities
| | | | | | | | | | | |
| Nine Months Ended September 30, | | |
| 2020 | | 2019 |
| (in millions) | | |
Construction Expenditures | $ | (4,690.4) | | | $ | (4,336.0) | |
Acquisitions of Nuclear Fuel | (68.4) | | | (91.9) | |
| | | |
| | | |
Acquisition of Sempra Renewables LLC and Santa Rita East, Net of Cash and Restricted Cash Acquired | — | | | (921.3) | |
Other | 51.5 | | | (8.4) | |
Net Cash Flows Used for Investing Activities | $ | (4,707.3) | | | $ | (5,357.6) | |
|
| | | | | | | |
| Nine Months Ended September 30, |
| 2019 | | 2018 |
| (in millions) |
Construction Expenditures | $ | (4,336.0 | ) | | $ | (4,688.4 | ) |
Acquisitions of Nuclear Fuel | (91.9 | ) | | (26.1 | ) |
Acquisition of Sempra Renewables LLC and Santa Rita East, net of cash and restricted cash acquired | (921.3 | ) | | — |
|
Other | (8.4 | ) | | 25.8 |
|
Net Cash Flows Used for Investing Activities | $ | (5,357.6 | ) | | $ | (4,688.7 | ) |
Net Cash Flows Used for Investing Activities increaseddecreased by $669$650 million primarily due to the following:
•A $921 million increasedecrease due to the 2019 acquisition of Sempra Renewables LLC and Santa Rita East. The $921 million representsrepresented a cash payment of $939 million, net of cash and restricted cash acquired of $18 million. See Note 6 - AcquisitionsAcquisition and ImpairmentsDispositions for additional information.
This increasedecrease in the use of cash was partially offset by:
•A $352$354 million decrease due to decreasedincrease in construction expenditures, primarily driven by decreasesdue to increases at AEP Transmission Holdco of $210$189 million, Generation & Marketing of $76 million and Transmission and Distribution Utilities of $109$55 million.
Financing Activities
| | | | | | | | | | | |
| Nine Months Ended September 30, | | |
| 2020 | | 2019 |
| (in millions) | | |
Issuance of Common Stock | $ | 136.5 | | | $ | 44.7 | |
Issuance/Retirement of Debt, Net | 2,844.0 | | | 3,063.9 | |
| | | |
Dividends Paid on Common Stock | (1,055.7) | | | (1,002.0) | |
Other | (108.5) | | | (53.2) | |
Net Cash Flows from Financing Activities | $ | 1,816.3 | | | $ | 2,053.4 | |
|
| | | | | | | |
| Nine Months Ended September 30, |
| 2019 | | 2018 |
| (in millions) |
Issuance of Common Stock | $ | 44.7 |
| | $ | 62.5 |
|
Issuance/Retirement of Debt, Net | 3,063.9 |
| | 2,206.2 |
|
Dividends Paid on Common Stock | (1,002.0 | ) | | (922.5 | ) |
Other | (53.2 | ) | | (65.2 | ) |
Net Cash Flows from Financing Activities | $ | 2,053.4 |
| | $ | 1,281.0 |
|
Net Cash Flows from Financing Activities increaseddecreased by $772$237 million primarily due to the following:
•A $936 million increase$1 billion decrease in cashshort-term debt primarily due to decreased retirementsincreased repayments of long-term debt.commercial paper. See Note 1312 - Financing Activities for additional information.
This increasedecrease in cash was partially offset by:
An $80•A $493 million decreaseincrease in issuances of long-term debt. See Note 1312 - Financing Activities for additional information.
An $80•A $323 million decrease in cash due to the increased common stock dividends payments primarily due to increase dividends per share from 2018 to 2019.retirement of long-term debt. See Note 12 - Financing Activities for additional information.
See “Long-term Debt Subsequent Events” section of Note 1312 for Long-term debt and other securities issued, retired and principal payments made after September 30, 20192020 through October 24, 2019,22, 2020, the date that the third quarter 10-Q was issued.
BUDGETED CAPITAL EXPENDITURES
Management forecasts approximately $32.9currently estimates $5.9 billion of capital expenditures for 20192020 and forecasts approximately $34.9 billion of capital expenditures for 2020 to 2023. Capital2024. In the second quarter of 2020, management revised the capital expenditure forecast for 2020 to 2024 to include approximately $2 billion of capital expenditures related tofor North Central Wind Energy Facilities are excluded from these budgeted amounts.Facilities. The expenditures are generally for transmission, generation, distribution, regulated and contracted renewables, and required environmental investment to comply with the Federal EPA rules. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, environmental regulations, business opportunities, market volatility, economic trends,
weather, legal reviews and the ability to access capital. Management expects to fund these capital expenditures through cash flows from operations and financing activities. Generally, the Registrant Subsidiaries use cash or short-term borrowings under the money pool to fund these expenditures until long-
termlong-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 20182019 Annual Report.
CONTRACTUAL OBLIGATION INFORMATION
A summary of contractual obligations is included in the 20182019 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 20182019 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 adopted in 20192020 and standards effective in the future.
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 Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports
regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s Chief Financial Officer, Executive Vice President of Generation, Executive Vice President of Utilities, Senior Vice President of Commercial Operations, Senior Vice President of Treasury and Risk and Chief Risk Officer. The Competitive Risk Committee consists of AEPSC’s Chief Financial Officer, Senior Vice President of Treasury and Risk and Chief Risk Officer in addition to Energy Supply’s President and Vice President.
When commercial activities exceed predetermined limits, positions are modified to reduce the risk to be within the limits unless specifically approved by the respective committee.
The effects of COVID-19 may adversely impact AEP’s risk management contracts on a forward basis. Markets could experience reduced market liquidity as they face potential uncertainties. Credit risk may increase as counterparties encounter business and supply chain disruptions and overall solvency challenges. Also, interest rates could continue to see increased volatility as capital markets confront uncertainty.
The following table summarizes the reasons for changes in total MTM value as compared to December 31, 2018:2019:
| | | | | | | | | | | | | | | | | | | | | | | |
MTM Risk Management Contract Net Assets (Liabilities) | | | | | | | |
Nine Months Ended September 30, 2020 | | | | | | | |
| | | | | | | |
| Vertically Integrated Utilities | | Transmission and Distribution Utilities | | Generation & Marketing | | Total |
| (in millions) | | | | | | |
Total MTM Risk Management Contract Net Assets (Liabilities) as of December 31, 2019 | $ | 75.9 | | | $ | (103.6) | | | $ | 163.4 | | | $ | 135.7 | |
Gain from Contracts Realized/Settled During the Period and Entered in a Prior Period | (43.8) | | | (5.1) | | | (16.6) | | | (65.5) | |
Fair Value of New Contracts at Inception When Entered During the Period (a) | — | | | — | | | 12.0 | | | 12.0 | |
| | | | | | | |
Changes in Fair Value Due to Market Fluctuations During the Period (b) | — | | | — | | | 10.7 | | | 10.7 | |
Changes in Fair Value Allocated to Regulated Jurisdictions (c) | 26.9 | | | (4.9) | | | — | | | 22.0 | |
Total MTM Risk Management Contract Net Assets (Liabilities) as of September 30, 2020 | $ | 59.0 | | | $ | (113.6) | | | $ | 169.5 | | | 114.9 | |
Commodity Cash Flow Hedge Contracts | | | | | | | (55.6) | |
Interest Rate Cash Flow Hedge Contracts | | | | | | | (4.7) | |
| | | | | | | |
Collateral Deposits | | | | | | | 8.7 | |
| | | | | | | |
Total MTM Derivative Contract Net Assets as of September 30, 2020 | | | | | | | $ | 63.3 | |
|
| | | | | | | | | | | | | | | |
MTM Risk Management Contract Net Assets (Liabilities) |
Nine Months Ended September 30, 2019 |
| | | | | | | |
| Vertically Integrated Utilities | | Transmission and Distribution Utilities | | Generation & Marketing | | Total |
| (in millions) |
Total MTM Risk Management Contract Net Assets (Liabilities) as of December 31, 2018 | $ | 90.9 |
| | $ | (101.0 | ) | | $ | 164.5 |
| | $ | 154.4 |
|
Gain from Contracts Realized/Settled During the Period and Entered in a Prior Period | (65.5 | ) | | (5.0 | ) | | (14.3 | ) | | (84.8 | ) |
Fair Value of New Contracts at Inception When Entered During the Period (a) | — |
| | — |
| | 8.8 |
| | 8.8 |
|
Changes in Fair Value Due to Market Fluctuations During the Period (b) | — |
| | — |
| | 12.8 |
| | 12.8 |
|
Changes in Fair Value Allocated to Regulated Jurisdictions (c) | 76.9 |
| | (7.2 | ) | | — |
| | 69.7 |
|
Total MTM Risk Management Contract Net Assets (Liabilities) as of September 30, 2019 | $ | 102.3 |
| | $ | (113.2 | ) | | $ | 171.8 |
| | 160.9 |
|
Commodity Cash Flow Hedge Contracts | | | |
| | | | (97.3 | ) |
Interest Rate Cash Flow Hedge Contracts | | | |
| | |
| | 1.9 |
|
Fair Value Hedge Contracts | | | |
| | |
| | 25.1 |
|
Collateral Deposits | | | |
| | |
| | 21.2 |
|
Total MTM Derivative Contract Net Assets as of September 30, 2019 | | | |
| | |
| | $ | 111.8 |
|
(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.
| |
(a) | Reflects fair value on primarily long-term structured contracts which are typically with customers that seek fixed pricing to limit their risk against fluctuating energy prices. The contract prices are valued against market curves associated with the delivery location and delivery term. A significant portion of the total volumetric position has been economically hedged. |
| |
(b) | Market fluctuations are attributable to various factors such as supply/demand, weather, etc. |
| |
(c) | Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory liabilities/assets or accounts payable. |
See Note 9 – Derivatives and Hedging and Note 10 – Fair Value Measurements for additional information related to risk management contracts. The following tables and discussion provide information on credit risk and market volatility risk.
Credit Risk
Credit risk is mitigated in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses credit agency ratings and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis.
AEP has risk management contracts (includes non-derivative contracts) with numerous counterparties. Since open risk management contracts are valued based on changes in market prices of the related commodities, exposures change daily. As of September 30, 2019,2020, credit exposure net of collateral to sub investment grade counterparties was approximately 6.4%7.2%, 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, 2019,2020, the following table approximates AEP’s counterparty credit quality and exposure based on netting across commodities, instruments and legal entities where applicable:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Counterparty Credit Quality | | Exposure Before Credit Collateral | | Credit Collateral | | Net Exposure | | Number of Counterparties >10% of Net Exposure | | Net Exposure of Counterparties >10% |
| | (in millions, except number of counterparties) | | | | | | | | |
Investment Grade | | $ | 401.8 | | | $ | — | | | $ | 401.8 | | | 2 | | | $ | 194.8 | |
Split Rating | | 0.8 | | | — | | | 0.8 | | | 1 | | | 0.8 | |
| | | | | | | | | | |
No External Ratings: | | | | | | | | | | |
Internal Investment Grade | | 128.0 | | | — | | | 128.0 | | | 3 | | | 87.1 | |
Internal Noninvestment Grade | | 51.9 | | | 10.5 | | | 41.4 | | | 2 | | | 28.0 | |
Total as of September 30, 2020 | | $ | 582.5 | | | $ | 10.5 | | | $ | 572.0 | | | | | |
|
| | | | | | | | | | | | | | | | | | | |
Counterparty Credit Quality | | Exposure Before Credit Collateral | | Credit Collateral | | Net Exposure | | Number of Counterparties >10% of Net Exposure | | Net Exposure of Counterparties >10% |
| | (in millions, except number of counterparties) |
Investment Grade | | $ | 529.6 |
| | $ | 0.3 |
| | $ | 529.3 |
| | 2 |
| | $ | 218.3 |
|
Split Rating | | 0.8 |
| | — |
| | 0.8 |
| | 1 |
| | 0.8 |
|
No External Ratings: | | |
| | |
| |
|
| | |
| | |
|
Internal Investment Grade | | 138.2 |
| | — |
| | 138.2 |
| | 3 |
| | 84.2 |
|
Internal Noninvestment Grade | | 56.2 |
| | 10.5 |
| | 45.7 |
| | 2 |
| | 30.1 |
|
Total as of September 30, 2019 | | $ | 724.8 |
| | $ | 10.8 |
| | $ | 714.0 |
| |
|
| |
|
|
All exposure in the table above relates to AEPSC and AEPEP as AEPSC is agent for and transacts on behalf of AEP subsidiaries, including the Registrant Subsidiaries and AEPEP is agent for and transacts on behalf of other AEP subsidiaries.
In addition, AEP is exposed to credit risk related to participation in RTOs. For each of the RTOs in which AEP participates, this risk is generally determined based on the proportionate share of member gross activity over a specified period of time.
Value at Risk (VaR) Associated with Risk Management Contracts
Management uses a risk measurement model, which calculates VaR, to measure AEP’s commodity price risk in the risk management portfolio. The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period. Based on this VaR analysis, as of September 30, 2019,2020, 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 | | Twelve Months Ended |
September 30, 2019 | | December 31, 2018 |
End | | High | | Average | | Low | | End | | High | | Average | | Low |
(in millions) | | (in millions) |
$ | 0.3 |
| | $ | 1.2 |
| | $ | 0.2 |
| | $ | 0.1 |
| | $ | 1.1 |
| | $ | 1.8 |
| | $ | 0.3 |
| | $ | 0.1 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Nine Months Ended | | | | | | | | Twelve Months Ended | | | | | | |
September 30, 2020 | | | | | | | | December 31, 2019 | | | | | | |
End | | High | | Average | | Low | | End | | High | | Average | | Low |
(in millions) | | | | | | | | (in millions) | | | | | | |
$ | 0.1 | | | $ | 0.3 | | | $ | 0.1 | | | $ | — | | | $ | 0.1 | | | $ | 1.2 | | | $ | 0.2 | | | $ | 0.1 | |
VaR Model
Non-Trading Portfolio
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Nine Months Ended | | | | | | | | Twelve Months Ended | | | | | | |
September 30, 2020 | | | | | | | | December 31, 2019 | | | | | | |
End | | High | | Average | | Low | | End | | High | | Average | | Low |
(in millions) | | | | | | | | (in millions) | | | | | | |
$ | 1.0 | | | $ | 1.5 | | | $ | 0.8 | | | $ | 0.1 | | | $ | 0.2 | | | $ | 8.5 | | | $ | 1.1 | | | $ | 0.2 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Nine Months Ended | | Twelve Months Ended |
September 30, 2019 | | December 31, 2018 |
End | | High | | Average | | Low | | End | | High | | Average | | Low |
(in millions) | | (in millions) |
$ | 0.2 |
| | $ | 8.5 |
| | $ | 1.3 |
| | $ | 0.2 |
| | $ | 4.0 |
| | $ | 16.5 |
| | $ | 2.7 |
| | $ | 0.4 |
|
Management back-tests VaR results against performance due to actual price movements. Based on the assumed 95% confidence interval, the performance due to actual price movements would be expected to exceed the VaR at least once every 20 trading days.
As the VaR calculation captures recent price movements, management also performs regular stress testing of the trading portfolio to understand AEP’s exposure to extreme price movements. A historical-based method is employed whereby the current trading portfolio is subjected to actual, observed price movements from the last several years in order to ascertain which historical price movements translated into the largest potential MTM loss. Management then researches the underlying positions, price movements and market events that created the most significant exposure and reports the findings to the Risk Executive Committee, Regulated Risk Committee or Competitive Risk Committee as appropriate.
Interest Rate Risk
AEP is exposed to interest rate market fluctuations in the normal course of business operations. AEP has outstanding short and long-term debt which is subject to a variable rate. AEP manages interest rate risk by limiting variable-rate exposures to a percentage of total debt, by entering into interest rate derivative instruments and by monitoring the effects of market changes in interest rates. For the nine months ended September 30, 20192020 and 2018,2019, a 100 basis point change in the benchmark rate on AEP’s variable rate debt would impact pretax interest expense annually by $24$18 million and $25$24 million, respectively.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 20192020 and 20182019
(in millions, except per-share and share amounts)
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | | | Nine Months Ended | | |
| | September 30, | | | | September 30, | | |
| | 2020 | | 2019 | | 2020 | | 2019 |
REVENUES | | | | | | | | |
Vertically Integrated Utilities | | $ | 2,400.1 | | | $ | 2,598.9 | | | $ | 6,655.4 | | | $ | 7,087.6 | |
Transmission and Distribution Utilities | | 1,124.1 | | | 1,147.3 | | | 3,208.7 | | | 3,328.7 | |
Generation & Marketing | | 464.8 | | | 501.2 | | | 1,223.4 | | | 1,323.8 | |
Other Revenues | | 77.4 | | | 67.6 | | | 220.4 | | | 205.3 | |
TOTAL REVENUES | | 4,066.4 | | | 4,315.0 | | | 11,307.9 | | | 11,945.4 | |
| | | | | | | | |
EXPENSES | | | | | | | | |
Fuel and Other Consumables Used for Electric Generation | | 459.3 | | | 631.2 | | | 1,174.9 | | | 1,662.5 | |
Purchased Electricity for Resale | | 741.1 | | | 783.9 | | | 2,141.4 | | | 2,306.4 | |
Other Operation | | 702.9 | | | 708.3 | | | 1,871.0 | | | 1,981.7 | |
Maintenance | | 237.6 | | | 267.7 | | | 730.5 | | | 890.9 | |
| | | | | | | | |
| | | | | | | | |
Depreciation and Amortization | | 644.6 | | | 645.2 | | | 1,996.3 | | | 1,873.6 | |
Taxes Other Than Income Taxes | | 337.7 | | | 320.5 | | | 976.3 | | | 932.7 | |
TOTAL EXPENSES | | 3,123.2 | | | 3,356.8 | | | 8,890.4 | | | 9,647.8 | |
| | | | | | | | |
OPERATING INCOME | | 943.2 | | | 958.2 | | | 2,417.5 | | | 2,297.6 | |
| | | | | | | | |
Other Income (Expense): | | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Other Income | | 5.5 | | | 3.2 | | | 15.4 | | | 18.4 | |
Allowance for Equity Funds Used During Construction | | 45.2 | | | 43.0 | | | 111.7 | | | 122.3 | |
Non-Service Cost Components of Net Periodic Benefit Cost | | 29.7 | | | 30.0 | | | 89.2 | | | 90.0 | |
| | | | | | | | |
Interest Expense | | (291.3) | | | (275.1) | | | (877.4) | | | (781.6) | |
| | | | | | | | |
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS | | 732.3 | | | 759.3 | | | 1,756.4 | | | 1,746.7 | |
| | | | | | | | |
Income Tax Expense (Benefit) | | (1.2) | | | 40.6 | | | 57.9 | | | 30.7 | |
Equity Earnings of Unconsolidated Subsidiaries | | 14.7 | | | 15.2 | | | 63.5 | | | 51.1 | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
NET INCOME | | 748.2 | | | 733.9 | | | 1,762.0 | | | 1,767.1 | |
| | | | | | | | |
Net Income (Loss) Attributable to Noncontrolling Interests | | (0.4) | | | 0.4 | | | (2.6) | | | (0.5) | |
| | | | | | | | |
EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS | | $ | 748.6 | | | $ | 733.5 | | | $ | 1,764.6 | | | $ | 1,767.6 | |
| | | | | | | | |
WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING | | 496,177,968 | | | 493,839,034 | | | 495,479,190 | | | 493,579,430 | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS | | $ | 1.51 | | | $ | 1.49 | | | $ | 3.56 | | | $ | 3.58 | |
| | | | | | | | |
WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING | | 497,458,523 | | | 495,461,509 | | | 496,916,187 | | | 495,105,986 | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS | | $ | 1.50 | | | $ | 1.48 | | | $ | 3.55 | | | $ | 3.57 | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134. | | | | | | | | |
|
| | | | | | | | | | | | | | | | |
| | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, |
| | 2019 | | 2018 | | 2019 | | 2018 |
REVENUES | | | | | | | | |
Vertically Integrated Utilities | | $ | 2,598.9 |
| | $ | 2,610.2 |
| | $ | 7,087.6 |
| | $ | 7,332.4 |
|
Transmission and Distribution Utilities | | 1,147.3 |
| | 1,180.9 |
| | 3,328.7 |
| | 3,450.0 |
|
Generation & Marketing | | 501.2 |
| | 486.5 |
| | 1,323.8 |
| | 1,399.3 |
|
Other Revenues | | 67.6 |
| | 55.5 |
| | 205.3 |
| | 212.9 |
|
TOTAL REVENUES | | 4,315.0 |
| | 4,333.1 |
| | 11,945.4 |
| | 12,394.6 |
|
| | | | | | | | |
EXPENSES | | |
| | |
| | |
| | |
|
Fuel and Other Consumables Used for Electric Generation | | 631.2 |
| | 840.4 |
| | 1,662.5 |
| | 1,909.1 |
|
Purchased Electricity for Resale | | 783.9 |
| | 784.7 |
| | 2,306.4 |
| | 2,551.7 |
|
Other Operation | | 708.3 |
| | 826.0 |
| | 1,981.7 |
| | 2,332.7 |
|
Maintenance | | 267.7 |
| | 316.6 |
| | 890.9 |
| | 911.0 |
|
Depreciation and Amortization | | 645.2 |
| | 602.6 |
| | 1,873.6 |
| | 1,695.5 |
|
Taxes Other Than Income Taxes | | 320.5 |
| | 294.2 |
| | 932.7 |
| | 863.0 |
|
TOTAL EXPENSES | | 3,356.8 |
| | 3,664.5 |
| | 9,647.8 |
| | 10,263.0 |
|
| | | | | | | | |
OPERATING INCOME | | 958.2 |
| | 668.6 |
| | 2,297.6 |
| | 2,131.6 |
|
| | | | | | | | |
Other Income (Expense): | | |
| | |
| | |
| | |
|
Other Income | | 3.2 |
| | 6.3 |
| | 18.4 |
| | 18.5 |
|
Allowance for Equity Funds Used During Construction | | 43.0 |
| | 30.9 |
| | 122.3 |
| | 92.4 |
|
Non-Service Cost Components of Net Periodic Benefit Cost | | 30.0 |
| | 31.9 |
| | 90.0 |
| | 95.3 |
|
Interest Expense | | (275.1 | ) | | (256.8 | ) | | (781.6 | ) | | (733.1 | ) |
| | | | | | | | |
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS | | 759.3 |
| | 480.9 |
| | 1,746.7 |
| | 1,604.7 |
|
| | | | | | | | |
Income Tax Expense (Benefit) | | 40.6 |
| | (80.7 | ) | | 30.7 |
| | 93.5 |
|
Equity Earnings of Unconsolidated Subsidiaries | | 15.2 |
| | 18.1 |
| | 51.1 |
| | 55.3 |
|
| | | | | | | | |
NET INCOME | | 733.9 |
| | 579.7 |
| | 1,767.1 |
| | 1,566.5 |
|
| | | | | | | | |
Net Income (Loss) Attributable to Noncontrolling Interests | | 0.4 |
| | 2.1 |
| | (0.5 | ) | | 6.1 |
|
| | | | | | | | |
EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS | | $ | 733.5 |
| | $ | 577.6 |
| | $ | 1,767.6 |
| | $ | 1,560.4 |
|
| | | | | | | | |
WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING | | 493,839,034 |
| | 492,984,741 |
| | 493,579,430 |
| | 492,649,456 |
|
| | | | | | | | |
TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS | | $ | 1.49 |
| | $ | 1.17 |
| | $ | 3.58 |
| | $ | 3.17 |
|
| | | | | | | | |
WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING | | 495,461,509 |
| | 493,940,543 |
| | 495,105,986 |
| | 493,526,937 |
|
| | | | | | | | |
TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS | | $ | 1.48 |
| | $ | 1.17 |
| | $ | 3.57 |
| | $ | 3.16 |
|
|
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 126.
|
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 20192020 and 20182019
(in millions)
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | | | Nine Months Ended | | |
| | September 30, | | | | September 30, | | |
| | 2020 | | 2019 | | 2020 | | 2019 |
Net Income | | $ | 748.2 | | | $ | 733.9 | | | $ | 1,762.0 | | | $ | 1,767.1 | |
| | | | | | | | |
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES | | | | | | | | |
Cash Flow Hedges, Net of Tax of $10.5 and $11.8 for the Three Months Ended September 30, 2020 and 2019, Respectively, and $4.7 and $(16.8) for the Nine Months Ended September 30, 2020 and 2019, Respectively | | 39.3 | | | 44.2 | | | 17.6 | | | (63.3) | |
| | | | | | | | |
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.5) and $(0.4) for the Three Months Ended September 30, 2020 and 2019, Respectively, and $(1.4) and $(1.1) for the Nine Months Ended September 30, 2020 and 2019, Respectively | | (1.8) | | | (1.4) | | | (5.3) | | | (4.2) | |
| | | | | | | | |
TOTAL OTHER COMPREHENSIVE INCOME (LOSS) | | 37.5 | | | 42.8 | | | 12.3 | | | (67.5) | |
| | | | | | | | |
TOTAL COMPREHENSIVE INCOME | | 785.7 | | | 776.7 | | | 1,774.3 | | | 1,699.6 | |
| | | | | | | | |
Total Other Comprehensive Income (Loss) Attributable To Noncontrolling Interests | | (0.4) | | | 0.4 | | | (2.6) | | | (0.5) | |
| | | | | | | | |
TOTAL OTHER COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS | | $ | 786.1 | | | $ | 776.3 | | | $ | 1,776.9 | | | $ | 1,700.1 | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134. | | | | | | | | |
|
| | | | | | | | | | | | | | | | |
| | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, |
| | 2019 | | 2018 | | 2019 | | 2018 |
Net Income | | $ | 733.9 |
| | $ | 579.7 |
| | $ | 1,767.1 |
| | $ | 1,566.5 |
|
| | | | | | | | |
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES | | |
| | |
| | |
| | |
|
Cash Flow Hedges, Net of Tax of $11.8 and $2.7 for the Three Months Ended September 30, 2019 and 2018, Respectively, and $(16.8) and $3.9 for the Nine Months Ended September 30, 2019 and 2018, Respectively | | 44.2 |
| | 10.2 |
| | (63.3 | ) | | 14.7 |
|
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.4) and $(0.4) for the Three Months Ended September 30, 2019 and 2018, Respectively, and $(1.1) and $(1.1) for the Nine Months Ended September 30, 2019 and 2018, Respectively | | (1.4 | ) | | (1.4 | ) | | (4.2 | ) | | (4.0 | ) |
| | |
| | |
| | |
| | |
|
TOTAL OTHER COMPREHENSIVE INCOME (LOSS) | | 42.8 |
| | 8.8 |
| | (67.5 | ) | | 10.7 |
|
| | | | | | | | |
TOTAL COMPREHENSIVE INCOME | | 776.7 |
| | 588.5 |
| | 1,699.6 |
| | 1,577.2 |
|
| | | | | | | | |
Total Other Comprehensive Income (Loss) Attributable To Noncontrolling Interests | | 0.4 |
| | 2.1 |
| | (0.5 | ) | | 6.1 |
|
| | | | | | | | |
TOTAL OTHER COMPREHENSIVE INCOME ATTIBUTABLE TO AEP COMMON SHAREHOLDERS | | $ | 776.3 |
| | $ | 586.4 |
| | $ | 1,700.1 |
| | $ | 1,571.1 |
|
|
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 126.
|
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Nine Months Ended September 30, 20192020 and 20182019
(in millions)
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| AEP Common Shareholders | | | | | | | | | | | | |
| Common Stock | | | | | | | | Accumulated Other Comprehensive Income (Loss) | | | | |
| Shares | | Amount | | Paid-in Capital | | Retained Earnings | | | | Noncontrolling Interests | | Total |
TOTAL EQUITY – DECEMBER 31, 2018 | 513.5 | | | $ | 3,337.4 | | | $ | 6,486.1 | | | $ | 9,325.3 | | | $ | (120.4) | | | $ | 31.0 | | | $ | 19,059.4 | |
| | | | | | | | | | | | | |
Issuance of Common Stock | 0.1 | | | 1.2 | | | 13.3 | | | | | | | | | 14.5 | |
Common Stock Dividends | | | | | | | (332.5) | | (b) | | | (1.1) | | | (333.6) | |
Other Changes in Equity | | | | | (56.6) | | (a) | | | | | 1.0 | | | (55.6) | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Net Income | | | | | | | 572.8 | | | | | 1.3 | | | 574.1 | |
Other Comprehensive Loss | | | | | | | | | (30.3) | | | | | (30.3) | |
TOTAL EQUITY – MARCH 31, 2019 | 513.6 | | | 3,338.6 | | | 6,442.8 | | | 9,565.6 | | | (150.7) | | | 32.2 | | | 19,228.5 | |
| | | | | | | | | | | | | |
Issuance of Common Stock | 0.4 | | | 2.2 | | | 15.6 | | | | | | | | | 17.8 | |
Common Stock Dividends | | | | | | | (332.7) | | (b) | | | (1.8) | | | (334.5) | |
Other Changes in Equity | | | | | (3.1) | | | | | | | 0.6 | | | (2.5) | |
Acquisition of Sempra Renewables LLC | | | | | | | | | | | 134.8 | | | 134.8 | |
Net Income (Loss) | | | | | | | 461.3 | | | | | (2.2) | | | 459.1 | |
Other Comprehensive Loss | | | | | | | | | (80.0) | | | | | (80.0) | |
TOTAL EQUITY – JUNE 30, 2019 | 514.0 | | | 3,340.8 | | | 6,455.3 | | | 9,694.2 | | | (230.7) | | | 163.6 | | | 19,423.2 | |
| | | | | | | | | | | | | |
Issuance of Common Stock | 0.1 | | | 1.1 | | | 11.3 | | | | | | | | | 12.4 | |
Common Stock Dividends | | | | | | | (332.4) | | (b) | | | (1.5) | | | (333.9) | |
Other Changes in Equity | | | | | 0.5 | | | | | | | | | 0.5 | |
Acquisition of Santa Rita East | | | | | | | | | | | 118.8 | | | 118.8 | |
Net Income | | | | | | | 733.5 | | | | | 0.4 | | | 733.9 | |
Other Comprehensive Income | | | | | | | | | 42.8 | | | | | 42.8 | |
TOTAL EQUITY – SEPTEMBER 30, 2019 | 514.1 | | | $ | 3,341.9 | | | $ | 6,467.1 | | | $ | 10,095.3 | | | $ | (187.9) | | | $ | 281.3 | | | $ | 19,997.7 | |
| | | | | | | | | | | | | |
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) | | (c) | | | (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) | | (c) | | | (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) | | (c) | | | (2.0) | | | (351.1) | |
Other Changes in Equity | | | | | (104.0) | | (d) | | | | | 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 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| AEP Common Shareholders | | | | |
| Common Stock | | | | | | Accumulated Other Comprehensive Income (Loss) | | | | |
| Shares | | Amount | | Paid-in Capital | | Retained Earnings | | | Noncontrolling Interests | | Total |
TOTAL EQUITY – DECEMBER 31, 2017 | 512.2 |
| | $ | 3,329.4 |
| | $ | 6,398.7 |
| | $ | 8,626.7 |
| | $ | (67.8 | ) | | $ | 26.6 |
| | $ | 18,313.6 |
|
| | | | | | | | | | | | | |
Issuance of Common Stock | 0.5 |
| | 3.3 |
| | 28.9 |
| | |
| | | | | | 32.2 |
|
Common Stock Dividends | | | | | | | (305.5 | ) | (b) | | | (0.6 | ) | | (306.1 | ) |
Other Changes in Equity | | | | | 16.9 |
| | | | | | | | 16.9 |
|
ASU 2018-02 Adoption | | | | | | | 14.0 |
| | (17.0 | ) | | | | (3.0 | ) |
ASU 2016-01 Adoption | | | | | | | 11.9 |
| | (11.9 | ) | | | | — |
|
Net Income | | | | | | | 454.4 |
| | | | 2.3 |
| | 456.7 |
|
Other Comprehensive Income | |
| | |
| | |
| | |
| | 1.3 |
| | | | 1.3 |
|
TOTAL EQUITY – MARCH 31, 2018 | 512.7 |
| | 3,332.7 |
| | 6,444.5 |
| | 8,801.5 |
| | (95.4 | ) | | 28.3 |
| | 18,511.6 |
|
| | | | | | | | | | | | | |
Issuance of Common Stock | 0.4 |
| | 2.7 |
| | 16.0 |
| | |
| | |
| | |
| | 18.7 |
|
Common Stock Dividends | |
| | |
| | |
| | (306.8 | ) | (b) | |
| | (1.3 | ) | | (308.1 | ) |
Other Changes in Equity | |
| | |
| | (1.9 | ) | | | | |
| | 0.4 |
| | (1.5 | ) |
Net Income | | | | | | | 528.4 |
| | |
| | 1.7 |
| | 530.1 |
|
Other Comprehensive Income | |
| | |
| | |
| | |
| | 0.6 |
| | |
| | 0.6 |
|
TOTAL EQUITY – JUNE 30, 2018 | 513.1 |
| | 3,335.4 |
| | 6,458.6 |
| | 9,023.1 |
| | (94.8 | ) | | 29.1 |
| | 18,751.4 |
|
| | | | | | | | | | | | | |
Issuance of Common Stock | 0.2 |
| | 1.1 |
| | 10.5 |
| | | | | | | | 11.6 |
|
Common Stock Dividends | | | | | | | (307.0 | ) | (b) | | | (1.3 | ) | | (308.3 | ) |
Other Changes in Equity | | | | | 3.5 |
| | | | | | 0.1 |
| | 3.6 |
|
Net Income | | | | | | | 577.6 |
| | | | 2.1 |
| | 579.7 |
|
Other Comprehensive Income | | | | | | | | | 8.8 |
| | | | 8.8 |
|
TOTAL EQUITY – SEPTEMBER 30, 2018 | 513.3 |
| | $ | 3,336.5 |
| | $ | 6,472.6 |
| | $ | 9,293.7 |
| | $ | (86.0 | ) | | $ | 30.0 |
| | $ | 19,046.8 |
|
| | | | | | | | | | | | | |
TOTAL EQUITY – DECEMBER 31, 2018 | 513.5 |
| | $ | 3,337.4 |
| | $ | 6,486.1 |
| | $ | 9,325.3 |
| | $ | (120.4 | ) | | $ | 31.0 |
| | $ | 19,059.4 |
|
| | | | | | | | | | | | | |
Issuance of Common Stock | 0.1 |
| | 1.2 |
| | 13.3 |
| | | | | | | | 14.5 |
|
Common Stock Dividends | | | | | | | (332.5 | ) | (c) | | | (1.1 | ) | | (333.6 | ) |
Other Changes in Equity | | | | | (56.6 | ) | (a) | | | | | 1.0 |
| | (55.6 | ) |
Net Income | | | | | | | 572.8 |
| | | | 1.3 |
| | 574.1 |
|
Other Comprehensive Loss | | | | | | | | | (30.3 | ) | | | | (30.3 | ) |
TOTAL EQUITY – MARCH 31, 2019 | 513.6 |
| | 3,338.6 |
| | 6,442.8 |
| | 9,565.6 |
| | (150.7 | ) | | 32.2 |
| | 19,228.5 |
|
| | | | | | | | | | | | | |
Issuance of Common Stock | 0.4 |
| | 2.2 |
| | 15.6 |
| | | | | | | | 17.8 |
|
Common Stock Dividends | | | | | | | (332.7 | ) | (c) | | | (1.8 | ) | | (334.5 | ) |
Other Changes in Equity | | | | | (3.1 | ) | | | | | | 0.6 |
| | (2.5 | ) |
Acquisition of Sempra Renewables LLC | | | | | | | | | | | 134.8 |
| | 134.8 |
|
Net Income (Loss) | | | | | | | 461.3 |
| | | | (2.2 | ) | | 459.1 |
|
Other Comprehensive Loss | | | | | | | | | (80.0 | ) | | | | (80.0 | ) |
TOTAL EQUITY – JUNE 30, 2019 | 514.0 |
| | 3,340.8 |
| | 6,455.3 |
| | 9,694.2 |
| | (230.7 | ) | | 163.6 |
| | 19,423.2 |
|
| | | | | | | | | | | | | |
Issuance of Common Stock | 0.1 |
| | 1.1 |
| | 11.3 |
| | |
| | |
| | |
| | 12.4 |
|
Common Stock Dividends | |
| | |
| | |
| | (332.4 | ) | (c) | |
| | (1.5 | ) | | (333.9 | ) |
Other Changes in Equity | |
| | |
| | 0.5 |
| | | | |
| |
|
| | 0.5 |
|
Acquisition of Santa Rita East | | | | | | | | | | | 118.8 |
| | 118.8 |
|
Net Income | | | | | | | 733.5 |
| | |
| | 0.4 |
| | 733.9 |
|
Other Comprehensive Income | |
| | |
| | |
| | |
| | 42.8 |
| | |
| | 42.8 |
|
TOTAL EQUITY – SEPTEMBER 30, 2019 | 514.1 |
| | $ | 3,341.9 |
| | $ | 6,467.1 |
| | $ | 10,095.3 |
| | $ | (187.9 | ) | | $ | 281.3 |
| | $ | 19,997.7 |
|
(a)Includes $(62) million related to a forward equity purchase contract associated with the issuance of Equity Units.
(b)Cash dividends declared per AEP common share were $0.67.
(c)Cash dividends declared per AEP common share were $0.70.
(d)Includes $(121) million related to a forward equity purchase contract associated with the issuance of Equity Units.
| |
(a) | Includes $(62) million related to a forward equity purchase contract associated with the issuance of Equity Units. See “Equity Units” section of Note 13 for additional information. |
| |
(b) | Common Stock dividends declared per AEP common share were $0.62. |
| |
(c) | Common Stock dividends declared per AEP common share were $0.67. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 126134. | | | | | | | | | | | | | |
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 20192020 and December 31, 20182019
(in millions)
(Unaudited)
| | | | | | | | | | | | | | |
| | September 30, | | December 31, |
| | 2020 | | 2019 |
CURRENT ASSETS | | | | |
Cash and Cash Equivalents | | $ | 409.7 | | | $ | 246.8 | |
Restricted Cash (September 30, 2020 and December 31, 2019 Amounts Include $54.1 and $185.8, Respectively, Related to Transition Funding, Restoration Funding, Appalachian Consumer Rate Relief Funding and Santa Rita East) | | 54.1 | | | 185.8 | |
Other Temporary Investments (September 30, 2020 and December 31, 2019 Amounts Include $198 and $187.8, Respectively, Related to EIS and Transource Energy) | | 209.0 | | | 202.7 | |
Accounts Receivable: | | | | |
Customers | | 600.5 | | | 625.3 | |
Accrued Unbilled Revenues | | 212.4 | | | 222.4 | |
Pledged Accounts Receivable – AEP Credit | | 1,055.1 | | | 873.9 | |
Miscellaneous | | 46.1 | | | 27.2 | |
Allowance for Uncollectible Accounts | | (63.4) | | | (43.7) | |
Total Accounts Receivable | | 1,850.7 | | | 1,705.1 | |
Fuel | | 586.1 | | | 528.5 | |
Materials and Supplies | | 681.2 | | | 640.7 | |
Risk Management Assets | | 115.2 | | | 172.8 | |
| | | | |
Regulatory Asset for Under-Recovered Fuel Costs | | 61.4 | | | 92.9 | |
Margin Deposits | | 54.1 | | | 60.4 | |
| | | | |
Prepayments and Other Current Assets | | 316.7 | | | 242.1 | |
TOTAL CURRENT ASSETS | | 4,338.2 | | | 4,077.8 | |
| | | | |
PROPERTY, PLANT AND EQUIPMENT | | | | |
Electric: | | | | |
Generation | | 23,036.9 | | | 22,762.4 | |
Transmission | | 26,539.1 | | | 24,808.6 | |
Distribution | | 23,459.8 | | | 22,443.4 | |
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel) | | 5,204.7 | | | 4,811.5 | |
Construction Work in Progress | | 4,662.5 | | | 4,319.8 | |
Total Property, Plant and Equipment | | 82,903.0 | | | 79,145.7 | |
Accumulated Depreciation and Amortization | | 20,116.6 | | | 19,007.6 | |
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | 62,786.4 | | | 60,138.1 | |
| | | | |
OTHER NONCURRENT ASSETS | | | | |
Regulatory Assets | | 3,518.8 | | | 3,158.8 | |
Securitized Assets | | 684.0 | | | 858.1 | |
Spent Nuclear Fuel and Decommissioning Trusts | | 3,075.9 | | | 2,975.7 | |
Goodwill | | 52.5 | | | 52.5 | |
Long-term Risk Management Assets | | 242.9 | | | 266.6 | |
Operating Lease Assets | | 881.0 | | | 957.4 | |
Deferred Charges and Other Noncurrent Assets | | 3,109.6 | | | 3,407.3 | |
TOTAL OTHER NONCURRENT ASSETS | | 11,564.7 | | | 11,676.4 | |
| | | | |
TOTAL ASSETS | | $ | 78,689.3 | | | $ | 75,892.3 | |
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134. | | | | |
|
| | | | | | | | |
| | September 30, | | December 31, |
| | 2019 | | 2018 |
CURRENT ASSETS | | |
| | |
|
Cash and Cash Equivalents | | $ | 348.8 |
| | $ | 234.1 |
|
Restricted Cash (September 30, 2019 and December 31, 2018 Amounts Include $141 and $210, Respectively, Related to Transition Funding, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding and Santa Rita East) | | 141.0 |
| | 210.0 |
|
Other Temporary Investments (September 30, 2019 and December 31, 2018 Amounts Include $193.4 and $152.7, Respectively, Related to EIS and Transource Energy) | | 198.4 |
| | 159.1 |
|
Accounts Receivable: | | |
| | |
|
Customers | | 609.0 |
| | 699.0 |
|
Accrued Unbilled Revenues | | 268.8 |
| | 209.3 |
|
Pledged Accounts Receivable – AEP Credit | | 955.6 |
| | 999.8 |
|
Miscellaneous | | 36.6 |
| | 55.2 |
|
Allowance for Uncollectible Accounts | | (44.9 | ) | | (36.8 | ) |
Total Accounts Receivable | | 1,825.1 |
| | 1,926.5 |
|
Fuel | | 437.8 |
| | 341.5 |
|
Materials and Supplies | | 613.5 |
| | 579.6 |
|
Risk Management Assets | | 186.7 |
| | 162.8 |
|
Regulatory Asset for Under-Recovered Fuel Costs | | 98.5 |
| | 150.1 |
|
Margin Deposits | | 54.2 |
| | 141.4 |
|
Prepayments and Other Current Assets | | 262.4 |
| | 208.8 |
|
TOTAL CURRENT ASSETS | | 4,166.4 |
| | 4,113.9 |
|
| | | | |
PROPERTY, PLANT AND EQUIPMENT | | |
| | |
|
Electric: | | |
| | |
|
Generation | | 22,624.4 |
| | 21,699.9 |
|
Transmission | | 23,082.8 |
| | 21,531.0 |
|
Distribution | | 21,991.0 |
| | 21,195.4 |
|
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel) | | 4,510.2 |
| | 4,265.0 |
|
Construction Work in Progress | | 5,244.5 |
| | 4,393.9 |
|
Total Property, Plant and Equipment | | 77,452.9 |
| | 73,085.2 |
|
Accumulated Depreciation and Amortization | | 18,760.2 |
| | 17,986.1 |
|
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | 58,692.7 |
| | 55,099.1 |
|
| | | | |
OTHER NONCURRENT ASSETS | | |
| | |
|
Regulatory Assets | | 3,131.4 |
| | 3,310.4 |
|
Securitized Assets | | 938.7 |
| | 920.6 |
|
Spent Nuclear Fuel and Decommissioning Trusts | | 2,835.2 |
| | 2,474.9 |
|
Goodwill | | 52.5 |
| | 52.5 |
|
Long-term Risk Management Assets | | 299.0 |
| | 254.0 |
|
Operating Lease Assets | | 990.0 |
| | — |
|
Deferred Charges and Other Noncurrent Assets | | 2,794.8 |
| | 2,577.4 |
|
TOTAL OTHER NONCURRENT ASSETS | | 11,041.6 |
| | 9,589.8 |
|
| | | | |
TOTAL ASSETS | | $ | 73,900.7 |
| | $ | 68,802.8 |
|
|
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 126.
|
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
September 30, 20192020 and December 31, 20182019
(in millions, except per-share and share amounts)
(Unaudited) |
| | | | | | | | | | | | | |
| | | | | | | September 30, | | December 31, |
| | | | | | | 2019 | | 2018 |
CURRENT LIABILITIES | | | | |
Accounts Payable | | | | | | | $ | 1,766.8 |
| | $ | 1,874.3 |
|
Short-term Debt: | | | | | | | | | |
Securitized Debt for Receivables – AEP Credit | | | | | | | 750.0 |
| | 750.0 |
|
Other Short-term Debt | | | | | | | 1,760.0 |
| | 1,160.0 |
|
Total Short-term Debt | | | | | | | 2,510.0 |
| | 1,910.0 |
|
Long-term Debt Due Within One Year (September 30, 2019 and December 31, 2018 Amounts Include $544.7 and $406.5, Respectively, Related to Transition Funding, DCC Fuel, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding, Transource Energy, Sabine and Restoration Funding) | | | 1,327.7 |
| | 1,698.5 |
|
Risk Management Liabilities | | | | | | | 75.3 |
| | 55.0 |
|
Customer Deposits | | | | | | | 381.4 |
| | 412.2 |
|
Accrued Taxes | | | | | | | 883.4 |
| | 1,218.0 |
|
Accrued Interest | | | | | | | 304.8 |
| | 231.7 |
|
Obligations Under Operating Leases | | | | | | | 228.8 |
| | — |
|
Regulatory Liability for Over-Recovered Fuel Costs | | | | | 100.6 |
| | 58.6 |
|
Other Current Liabilities | | | | | | | 1,032.4 |
| | 1,190.5 |
|
TOTAL CURRENT LIABILITIES | | | | | | | 8,611.2 |
| | 8,648.8 |
|
| | | | | | | |
NONCURRENT LIABILITIES | | | | |
Long-term Debt (September 30, 2019 and December 31, 2018 Amounts Include $918.4 and $1,109.2, Respectively, Related to Transition Funding, DCC Fuel, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding, Transource Energy, Sabine and Restoration Funding) | | | 24,553.5 |
| | 21,648.2 |
|
Long-term Risk Management Liabilities | | | | | | | 298.6 |
| | 263.4 |
|
Deferred Income Taxes | | | | | | | 7,427.8 |
| | 7,086.5 |
|
Regulatory Liabilities and Deferred Investment Tax Credits | | | 8,552.8 |
| | 8,540.3 |
|
Asset Retirement Obligations | | | | | | | 2,353.5 |
| | 2,287.7 |
|
Employee Benefits and Pension Obligations | | | | | | | 376.6 |
| | 377.1 |
|
Obligations Under Operating Leases | | | | | | | 801.1 |
| | — |
|
Deferred Credits and Other Noncurrent Liabilities | | | 790.0 |
| | 782.6 |
|
TOTAL NONCURRENT LIABILITIES | | | | | | | 45,153.9 |
| | 40,985.8 |
|
| | | | | | | | | |
TOTAL LIABILITIES | | | | | | | 53,765.1 |
| | 49,634.6 |
|
| | | | | | | | | |
Rate Matters (Note 4) | | | | | | |
| |
|
Commitments and Contingencies (Note 5) | | | | | | |
| |
|
| | | | | | | | | |
MEZZANINE EQUITY | | | | |
Redeemable Noncontrolling Interest | | | | | | | 67.3 |
| | 69.4 |
|
Contingently Redeemable Performance Share Awards | | | | | | | 70.6 |
| | 39.4 |
|
TOTAL MEZZANINE EQUITY | | | | | | | 137.9 |
| | 108.8 |
|
| | | | | | | | | |
EQUITY | | | | |
Common Stock – Par Value – $6.50 Per Share: | | | | | | | | | |
| | 2019 | | 2018 | | | | | |
Shares Authorized | | 600,000,000 | | 600,000,000 | | | | | |
Shares Issued | | 514,140,235 | | 513,450,036 | | | | | |
(20,204,160 Shares were Held in Treasury as of September 30, 2019 and December 31, 2018, Respectively) | | | 3,341.9 |
| | 3,337.4 |
|
Paid-in Capital | | �� | | | | | 6,467.1 |
| | 6,486.1 |
|
Retained Earnings | | | | | | | 10,095.3 |
| | 9,325.3 |
|
Accumulated Other Comprehensive Income (Loss) | | | (187.9 | ) | | (120.4 | ) |
TOTAL AEP COMMON SHAREHOLDERS’ EQUITY | | | 19,716.4 |
| | 19,028.4 |
|
| | | | | | | | | |
Noncontrolling Interests | | | | | | | 281.3 |
| | 31.0 |
|
| | | | | | | | | |
TOTAL EQUITY | | | | | | | 19,997.7 |
| | 19,059.4 |
|
| | | | | | | | | |
TOTAL LIABILITIES, MEZZANINE EQUITY AND TOTAL EQUITY | | $ | 73,900.7 |
| | $ | 68,802.8 |
|
|
| | | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 126. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | September 30, | | December 31, | | | | | | | | 2020 | | 2019 | CURRENT LIABILITIES | | | | | | | | | | Accounts Payable | | | | | | | $ | 1,659.6 | | | $ | 2,085.8 | | Short-term Debt: | | | | | | | | | | Securitized Debt for Receivables – AEP Credit | | | | | | | 703.0 | | | 710.0 | | Other Short-term Debt | | | | | | | 1,694.0 | | | 2,128.3 | | Total Short-term Debt | | | | | | | 2,397.0 | | | 2,838.3 | | Long-term Debt Due Within One Year (September 30, 2020 and December 31, 2019 Amounts Include $176.6 and $565.1, Respectively, Related to Transition Funding, DCC Fuel, Appalachian Consumer Rate Relief Funding, Transource Energy, Sabine and Restoration Funding) | | | | | | | 1,911.6 | | | 1,598.7 | | Risk Management Liabilities | | | | | | | 62.4 | | | 114.3 | | Customer Deposits | | | | | | | 339.7 | | | 366.1 | | Accrued Taxes | | | | | | | 942.7 | | | 1,357.8 | | Accrued Interest | | | | | | | 331.0 | | | 243.6 | | Obligations Under Operating Leases | | | | | | | 236.5 | | | 234.1 | | Regulatory Liability for Over-Recovered Fuel Costs | | | | | | | 82.5 | | | 86.6 | | | | | | | | | | | | Other Current Liabilities | | | | | | | 1,084.2 | | | 1,373.8 | | TOTAL CURRENT LIABILITIES | | | | | | | 9,047.2 | | | 10,299.1 | | | | | | | | | | | | NONCURRENT LIABILITIES | | | | | | | | | | Long-term Debt (September 30, 2020 and December 31, 2019 Amounts Include $958.7 and $907, Respectively, Related to Transition Funding, DCC Fuel, Appalachian Consumer Rate Relief Funding, Transource Energy, Sabine and Restoration Funding) | | | | | | | 28,155.5 | | | 25,126.8 | | Long-term Risk Management Liabilities | | | | | | | 232.4 | | | 261.8 | | Deferred Income Taxes | | | | | | | 8,011.4 | | | 7,588.2 | | Regulatory Liabilities and Deferred Investment Tax Credits | | | | | | | 8,249.2 | | | 8,457.6 | | Asset Retirement Obligations | | | | | | | 2,448.3 | | | 2,216.6 | | Employee Benefits and Pension Obligations | | | | | | | 353.1 | | | 466.0 | | Obligations Under Operating Leases | | | | | | | 690.5 | | | 734.6 | | Deferred Credits and Other Noncurrent Liabilities | | | | | | | 794.6 | | | 719.8 | | TOTAL NONCURRENT LIABILITIES | | | | | | | 48,935.0 | | | 45,571.4 | | | | | | | | | | | | TOTAL LIABILITIES | | | | | | | 57,982.2 | | | 55,870.5 | | | | | | | | | | | | Rate Matters (Note 4) | | | | | | | | | | Commitments and Contingencies (Note 5) | | | | | | | | | | | | | | | | | | | | MEZZANINE EQUITY | | | | | | | | | | Redeemable Noncontrolling Interest | | | | | | | 0 | | | 65.7 | | Contingently Redeemable Performance Share Awards | | | | | | | 72.5 | | | 42.9 | | TOTAL MEZZANINE EQUITY | | | | | | | 72.5 | | | 108.6 | | | | | | | | | | | | EQUITY | | | | | | | | | | Common Stock – Par Value – $6.50 Per Share: | | | | | | | | | | | | 2020 | | 2019 | | | | | | Shares Authorized | | 600,000,000 | | 600,000,000 | | | | | | Shares Issued | | 516,551,408 | | 514,373,631 | | | | | | (20,204,160 Shares were Held in Treasury as of September 30, 2020 and December 31, 2019, Respectively) | | | | | | | 3,357.6 | | | 3,343.4 | | Paid-in Capital | | | | | | | 6,522.3 | | | 6,535.6 | | Retained Earnings | | | | | | | 10,621.4 | | | 9,900.9 | | Accumulated Other Comprehensive Income (Loss) | | | | | | | (135.4) | | | (147.7) | | TOTAL AEP COMMON SHAREHOLDERS’ EQUITY | | | | | | | 20,365.9 | | | 19,632.2 | | | | | | | | | | | | Noncontrolling Interests | | | | | | | 268.7 | | | 281.0 | | | | | | | | | | | | TOTAL EQUITY | | | | | | | 20,634.6 | | | 19,913.2 | | | | | | | | | | | | TOTAL LIABILITIES, MEZZANINE EQUITY AND TOTAL EQUITY | | | | | | | $ | 78,689.3 | | | $ | 75,892.3 | | | | | | | | | | | | See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134. | | | | | | | | | |
|
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 20192020 and 20182019
(in millions)
(Unaudited)
| | | | Nine Months Ended September 30, | | | Nine Months Ended September 30, | |
| | 2019 | | 2018 | | | 2020 | | 2019 |
OPERATING ACTIVITIES | | |
| | |
| OPERATING ACTIVITIES | | | | |
Net Income | | $ | 1,767.1 |
| | $ | 1,566.5 |
| Net Income | | $ | 1,762.0 | | | $ | 1,767.1 | |
| Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | | | | Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | | | |
Depreciation and Amortization | | 1,873.6 |
| | 1,695.5 |
| Depreciation and Amortization | | 1,996.3 | | | 1,873.6 | |
| Deferred Income Taxes | | 15.9 |
| | 43.0 |
| Deferred Income Taxes | | 142.5 | | | 15.9 | |
| Allowance for Equity Funds Used During Construction | | (122.3 | ) | | (92.4 | ) | Allowance for Equity Funds Used During Construction | | (111.7) | | | (122.3) | |
Mark-to-Market of Risk Management Contracts | | (41.6 | ) | | (95.4 | ) | Mark-to-Market of Risk Management Contracts | | 46.4 | | | (41.6) | |
Amortization of Nuclear Fuel | | 71.6 |
| | 82.6 |
| Amortization of Nuclear Fuel | | 67.2 | | | 71.6 | |
Pension Contributions to Qualified Plan Trust | | Pension Contributions to Qualified Plan Trust | | (110.3) | | | 0 | |
Property Taxes | | 341.7 |
| | 304.8 |
| Property Taxes | | 396.9 | | | 341.7 | |
Deferred Fuel Over/Under-Recovery, Net | | 93.7 |
| | 210.6 |
| Deferred Fuel Over/Under-Recovery, Net | | 27.4 | | | 93.7 | |
| Recovery of Ohio Capacity Costs | | 34.1 |
| | 52.7 |
| Recovery of Ohio Capacity Costs | | 0 | | | 34.1 | |
Refund of Global Settlement | | (12.4 | ) | | (5.5 | ) | Refund of Global Settlement | | 0 | | | (12.4) | |
Change in Other Noncurrent Assets | | (9.6 | ) | | 161.6 |
| Change in Other Noncurrent Assets | | (219.6) | | | (9.6) | |
Change in Other Noncurrent Liabilities | | (16.3 | ) | | 141.9 |
| Change in Other Noncurrent Liabilities | | (25.1) | | | (16.3) | |
Changes in Certain Components of Working Capital: | | | | | Changes in Certain Components of Working Capital: | | | | |
Accounts Receivable, Net | | 125.0 |
| | (52.3 | ) | Accounts Receivable, Net | | (138.9) | | | 125.0 | |
Fuel, Materials and Supplies | | (116.6 | ) | | 98.7 |
| Fuel, Materials and Supplies | | (97.4) | | | (116.6) | |
Accounts Payable | | (32.4 | ) | | (45.0 | ) | Accounts Payable | | 21.9 | | | (32.4) | |
Accrued Taxes, Net | | (359.9 | ) | | (247.5 | ) | Accrued Taxes, Net | | (502.9) | | | (359.9) | |
Other Current Assets | | 60.2 |
| | 11.7 |
| Other Current Assets | | 26.0 | | | 60.2 | |
Other Current Liabilities | | (321.9 | ) | | 101.1 |
| Other Current Liabilities | | (358.5) | | | (321.9) | |
Net Cash Flows from Operating Activities | | 3,349.9 |
| | 3,932.6 |
| Net Cash Flows from Operating Activities | | 2,922.2 | | | 3,349.9 | |
| | | | | | | | |
INVESTING ACTIVITIES | | | | | INVESTING ACTIVITIES | | | | |
Construction Expenditures | | (4,336.0 | ) | | (4,688.4 | ) | Construction Expenditures | | (4,690.4) | | | (4,336.0) | |
| Purchases of Investment Securities | | (951.5 | ) | | (1,591.2 | ) | Purchases of Investment Securities | | (1,329.5) | | | (951.5) | |
Sales of Investment Securities | | 874.2 |
| | 1,550.9 |
| Sales of Investment Securities | | 1,293.0 | | | 874.2 | |
Acquisitions of Nuclear Fuel | | (91.9 | ) | | (26.1 | ) | Acquisitions of Nuclear Fuel | | (68.4) | | | (91.9) | |
Acquisition of Sempra Renewables LLC and Santa Rita East, net of cash and restricted cash acquired | | (921.3 | ) | | — |
| |
Acquisition of Sempra Renewables LLC and Santa Rita East, Net of Cash and Restricted Cash Acquired | | Acquisition of Sempra Renewables LLC and Santa Rita East, Net of Cash and Restricted Cash Acquired | | 0 | | | (921.3) | |
| Other Investing Activities | | 68.9 |
| | 66.1 |
| Other Investing Activities | | 88.0 | | | 68.9 | |
Net Cash Flows Used for Investing Activities | | (5,357.6 | ) | | (4,688.7 | ) | Net Cash Flows Used for Investing Activities | | (4,707.3) | | | (5,357.6) | |
| | | | | | | | |
FINANCING ACTIVITIES | | | | | FINANCING ACTIVITIES | | | | |
Issuance of Common Stock | | 44.7 |
| | 62.5 |
| Issuance of Common Stock | | 136.5 | | | 44.7 | |
Issuance of Long-term Debt | | 3,492.4 |
| | 3,572.0 |
| Issuance of Long-term Debt | | 3,985.8 | | | 3,492.4 | |
Commercial Paper and Credit Facility Borrowings | | — |
| | 205.6 |
| |
Change in Short-term Debt, Net | | 600.0 |
| | 604.0 |
| |
Issuance of Short-term Debt with Original Maturities greater than 90 Days | | Issuance of Short-term Debt with Original Maturities greater than 90 Days | | 1,304.5 | | | 0 | |
Change in Short-term Debt with Original Maturities less than 90 Days, Net | | Change in Short-term Debt with Original Maturities less than 90 Days, Net | | (1,445.8) | | | 600.0 | |
Retirement of Long-term Debt | | (1,023.5 | ) | | (1,959.5 | ) | Retirement of Long-term Debt | | (700.5) | | | (1,023.5) | |
Make Whole Premium on Extinguishment of Long-term Debt | | (5.0 | ) | | (10.3 | ) | Make Whole Premium on Extinguishment of Long-term Debt | | 0 | | | (5.0) | |
Commercial Paper and Credit Facility Repayments | | — |
| | (205.6 | ) | |
Redemption of Short-term Debt with Original Maturities Greater than 90 Days | | Redemption of Short-term Debt with Original Maturities Greater than 90 Days | | (300.0) | | | 0 | |
Principal Payments for Finance Lease Obligations | | (44.5 | ) | | (49.4 | ) | Principal Payments for Finance Lease Obligations | | (46.3) | | | (44.5) | |
Dividends Paid on Common Stock | | (1,002.0 | ) | | (922.5 | ) | Dividends Paid on Common Stock | | (1,055.7) | | | (1,002.0) | |
Redemption of Noncontrolling Interest in Trent and Desert Sky Windfarms | | Redemption of Noncontrolling Interest in Trent and Desert Sky Windfarms | | (56.5) | | | 0 | |
Other Financing Activities | | (8.7 | ) | | (15.8 | ) | Other Financing Activities | | (5.7) | | | (8.7) | |
Net Cash Flows from Financing Activities | | 2,053.4 |
| | 1,281.0 |
| Net Cash Flows from Financing Activities | | 1,816.3 | | | 2,053.4 | |
| | | | | | | |
Net Increase in Cash, Cash Equivalents and Restricted Cash | | 45.7 |
| | 524.9 |
| Net Increase in Cash, Cash Equivalents and Restricted Cash | | 31.2 | | | 45.7 | |
Cash, Cash Equivalents and Restricted Cash at Beginning of Period | | 444.1 |
| | 412.6 |
| Cash, Cash Equivalents and Restricted Cash at Beginning of Period | | 432.6 | | | 444.1 | |
Cash, Cash Equivalents and Restricted Cash at End of Period | | $ | 489.8 |
| | $ | 937.5 |
| Cash, Cash Equivalents and Restricted Cash at End of Period | | $ | 463.8 | | | $ | 489.8 | |
| | | | | | | | |
SUPPLEMENTARY INFORMATION | | | | | SUPPLEMENTARY INFORMATION | |
Cash Paid for Interest, Net of Capitalized Amounts | | $ | 689.7 |
| | $ | 631.3 |
| Cash Paid for Interest, Net of Capitalized Amounts | | $ | 690.5 | | | $ | 689.7 | |
Net Cash Paid (Received) for Income Taxes | | 22.8 |
| | (27.9 | ) | Net Cash Paid (Received) for Income Taxes | | (23.9) | | | 22.8 | |
Noncash Acquisitions Under Finance Leases | | 66.7 |
| | 43.5 |
| Noncash Acquisitions Under Finance Leases | | 33.0 | | | 66.7 | |
Construction Expenditures Included in Current Liabilities as of September 30, | | 1,018.9 |
| | 882.3 |
| Construction Expenditures Included in Current Liabilities as of September 30, | | 830.1 | | | 1,018.9 | |
Construction Expenditures Included in Noncurrent Liabilities as of September 30, | | Construction Expenditures Included in Noncurrent Liabilities as of September 30, | | 8.3 | | | 0 | |
Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30, | | — |
| | 12.1 |
| Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30, | | 1.0 | | | 0 | |
Noncash Contribution of Assets by Noncontrolling Interest | | — |
| | 84.0 |
| |
| Expected Reimbursement for Spent Nuclear Fuel Dry Cask Storage | | — |
| | 2.1 |
| Expected Reimbursement for Spent Nuclear Fuel Dry Cask Storage | | 2.4 | | | 0 | |
Noncontrolling Interest assumed with Sempra Renewable LLC and Santa Rita East Acquisition | | 253.4 |
| | — |
| Noncontrolling Interest assumed with Sempra Renewable LLC and Santa Rita East Acquisition | | 0 | | | 253.4 | |
Liabilities assumed with Sempra Renewable LLC and Santa Rita East Acquisition | | 32.4 |
| | — |
| Liabilities assumed with Sempra Renewable LLC and Santa Rita East Acquisition | | 0 | | | 32.4 | |
Forward Equity Purchase Contract Included in Current and Noncurrent Liabilities as of September 30, | | Forward Equity Purchase Contract Included in Current and Noncurrent Liabilities as of September 30, | | 120.6 | | | 52.4 | |
| See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134. | | See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134. | |
|
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 126. |
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 | | |
| September 30, | | | | September 30, | | |
| 2020 | | 2019 | | 2020 | | 2019 |
| (in millions of KWhs) | | | | | | |
Retail: | | | | | | | |
Residential | 4,112 | | | 4,148 | | | 9,736 | | | 9,580 | |
Commercial | 2,941 | | | 3,152 | | | 7,700 | | | 7,997 | |
Industrial | 2,037 | | | 2,168 | | | 6,618 | | | 6,556 | |
Miscellaneous | 184 | | | 197 | | | 486 | | | 512 | |
Total Retail | 9,274 | | | 9,665 | | | 24,540 | | | 24,645 | |
|
| | | | | | | | | | | |
| Three Months Ended | | Nine Months Ended |
| September 30, | | September 30, |
| 2019 | | 2018 | | 2019 | | 2018 |
| (in millions of KWhs) |
Retail: | |
| | |
| | | | |
Residential | 4,148 |
| | 3,893 |
| | 9,580 |
| | 9,679 |
|
Commercial | 3,152 |
| | 2,987 |
| | 7,997 |
| | 7,916 |
|
Industrial | 2,168 |
| | 2,216 |
| | 6,556 |
| | 6,705 |
|
Miscellaneous | 197 |
| | 182 |
| | 512 |
| | 490 |
|
Total Retail (a) | 9,665 |
| | 9,278 |
| | 24,645 |
| | 24,790 |
|
| |
(a) | 2018 KWhs have been revised to reflect the reclassification of certain customer accounts between Retail classes. This reclassification did not impact previously reported Total Retail KWhs. Management concluded that these prior period disclosure only errors were immaterial individually and in the aggregate. |
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 | | |
| September 30, | | | | September 30, | | |
| 2020 | | 2019 | | 2020 | | 2019 |
| (in degree days) | | | | | | |
Actual – Heating (a) | 1 | | | — | | | 98 | | | 180 | |
Normal – Heating (b) | — | | | — | | | 188 | | | 190 | |
| | | | | | | |
Actual – Cooling (c) | 1,357 | | | 1,587 | | | 2,524 | | | 2,679 | |
Normal – Cooling (b) | 1,378 | | | 1,368 | | | 2,436 | | | 2,425 | |
|
| | | | | | | | | | | |
| Three Months Ended | | Nine Months Ended |
| September 30, | | September 30, |
| 2019 | | 2018 | | 2019 | | 2018 |
| (in degree days) |
Actual – Heating (a) | — |
| | — |
| | 180 |
| | 234 |
|
Normal – Heating (b) | — |
| | — |
| | 190 |
| | 194 |
|
| | | | | | | |
Actual – Cooling (c) | 1,587 |
| | 1,424 |
| | 2,679 |
| | 2,612 |
|
Normal – Cooling (b) | 1,368 |
| | 1,367 |
| | 2,425 |
| | 2,413 |
|
(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 20192020 Compared to Third Quarter of 20182019
| | | | | | | | |
Reconciliation of Third Quarter of 2019 to Third Quarter of 2020 | | |
Net Income | | |
(in millions) | | |
| | |
Third Quarter of 2019 | | $ | 77.0 | |
| | |
Changes in Gross Margin: | | |
Retail Margins | | (1.4) | |
Margins from Off-system Sales | | (0.4) | |
Transmission Revenues | | 4.3 | |
Other Revenues | | (59.0) | |
Total Change in Gross Margin | | (56.5) | |
| | |
Changes in Expenses and Other: | | |
Other Operation and Maintenance | | (4.8) | |
Depreciation and Amortization | | 62.5 | |
Taxes Other Than Income Taxes | | 1.1 | |
| | |
Interest Income | | 0.1 | |
| | |
Allowance for Equity Funds Used During Construction | | (0.7) | |
| | |
Interest Expense | | (8.7) | |
Total Change in Expenses and Other | | 49.5 | |
| | |
Income Tax Expense | | 12.6 | |
| | |
Third Quarter of 2020 | | $ | 82.6 | |
|
| | | | |
Reconciliation of Third Quarter of 2018 to Third Quarter of 2019 |
Net Income |
(in millions) |
|
Third Quarter of 2018 | | $ | 57.8 |
|
| | |
|
Changes in Gross Margin: | | |
Retail Margins | | 12.6 |
|
Margins from Off-system Sales | | 16.7 |
|
Transmission Revenues | | 23.9 |
|
Other Revenues | | 4.7 |
|
Total Change in Gross Margin | | 57.9 |
|
| | |
|
Changes in Expenses and Other: | | |
|
Other Operation and Maintenance | | 6.7 |
|
Depreciation and Amortization | | (36.9 | ) |
Taxes Other Than Income Taxes | | (3.5 | ) |
Interest Income | | (0.1 | ) |
Allowance for Equity Funds Used During Construction | | (0.7 | ) |
Non-Service Cost Components of Net Periodic Benefit Cost | | (0.3 | ) |
Interest Expense | | 1.5 |
|
Total Change in Expenses and Other | | (33.3 | ) |
| | |
|
Income Tax Expense (Benefit) | | (5.4 | ) |
| | |
|
Third Quarter of 2019 | | $ | 77.0 |
|
The major components of the increasedecrease in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals were as follows:
| |
• | •Retail Margins decreased $1 million primarily due to the following: •A $19 million decrease due to refunds of Excess ADIT and excess federal income taxes collected as a result of Tax Reform. This decrease was partially offset in Income Tax Expense below. • increased $13 million primarily due to the following: |
An $8$11 million increasedecrease in weather-related usage primarily due to an 11% increasea 14% decrease in cooling degree days.
•A $4$3 million decrease due to refunds to customers associated with the most recent base rate case. This decrease was offset in Other Revenues below.
These decreases were partially offset by:
•A $19 million increase in weather-normalized margins primarily in the residential class.
| |
• | Margins from Off-system Sales •A $6 million increase from interim rate increases driven by increased distribution investment. •A $5 million increase due to new base rates implemented in June 2020. •Transmission Revenues increased $4 million primarily due to: •An $11 million increase from interim rate increases driven by increased transmission investment. This increase was partially offset by: •A $7 million decrease due to refunds to customers associated with the most recent base rate case. This decrease was offset in Other Revenues below. •Other Revenues decreased $59 million primarily due to the following: •A $68 million decrease in securitization revenues primarily due to the AEP Texas Central Transition Funding II LLC bonds that matured in July 2020. This decrease was offset below in Depreciation and Amortization expenses and in Interest Expense. This decrease was partially offset by: •An $8 million increase in revenues due to the amortization of a provision for refund recorded in December 2019 as part of the most recent base rate case. This increase was partially offset in Retail Margins and Transmission Revenues above.
increased $17 million due to higher affiliated PPA revenues. This increase was partially offset below in Other Operation and Maintenance expenses and in Depreciation and Amortization expenses.
|
| |
• | Transmission Revenues increased $24 million primarily due to the recovery of increased transmission investment in ERCOT.
|
| |
• | Other Revenues increased $5 million primarily due to securitization revenue related to Transition Funding. This decrease was offset below in Depreciation and Amortization expenses and in Interest Expense.
|
Expenses and Other and Income Tax Expense (Benefit) changed between years as follows:
| |
• | •Other Operation and Maintenance expenses increased $5 million primarily due to the following: • expenses decreased $7 million primarily due to the following: |
A $4$5 million decrease in expensesincrease due to the write-off of land associated with Oklaunion Power Station. This decrease was partially offset in Margins from Off-system Sales above and in Depreciation and Amortization expenses below.
A $3 million decrease in ERCOT transmission expenses. This decrease was partially offset in Retail Margins above.
| |
• | Depreciation and Amortization expenses increased $37 million primarily due to the following:
|
A $16 million increase in depreciation expense due to a change in the useful life of the Oklaunion Power Station.
•A $4 million increase in transmission expenses. This increase was partially offset in Margins from Off-system Sales aboveGross Margin above.
These increases were partially offset by:
•A $3 million decrease in distribution expenses.
•Depreciation and in Other Operation and MaintenanceAmortization expenses above.
An $11decreased $63 million increase in depreciation expenseprimarily due to an increase in the depreciable base of transmission and distribution assets primarily related to advanced metering systems.
A $7 million increasea decrease in securitization amortizations primarily relateddue to the AEP Texas Central Transition Funding.Funding II LLC bonds that matured in July 2020. This increasedecrease was offset in Other Revenues above and in Interest Expense below.
| |
•Interest Expense increased $9 million primarily due to the following: • | Taxes Other Than Income Taxes increased $4 million primarily due to increased property taxes as a result of additional investments in transmission and distribution assets and higher tax rates.
|
| |
• | Interest Expense decreased $2 million primarily due to the following:
|
A $5 million decreaseincrease due to higher long-term debt balances.
•A $3 million increase due to the prior year deferral of previously recorded interest expense approved for recovery as a result of the Texas Storm Cost Securitization financing order issued by the PUCT in June 2019.
A $3•Income Tax Expense decreased $13 million decreaseprimarily due to an increase in expense relatedamortization of Excess ADIT and the recognition of a discrete tax adjustment in 2020 which was primarily attributable to Transition Funding Securitization assets.the 5-year net operating loss carryback provision of the CARES Act. This decrease was partially offset above in Gross Margins and in Other RevenuesOperation and Depreciation and AmortizationMaintenance expenses.
These decreases were partially offset by:A $2 million increase due to higher long-term debt balances.
| |
• | Income Tax Expense (Benefit)
increased $5 million primarily due to an increase in pretax book income.
|
Nine Months Ended September 30, 20192020 Compared to Nine Months Ended September 30, 20182019
| | | | | | | | |
Reconciliation of Nine Months Ended September 30, 2019 to Nine Months Ended September 30, 2020 | | |
Net Income | | |
(in millions) | | |
| | |
Nine Months Ended September 30, 2019 | | $ | 192.0 | |
| | |
Changes in Gross Margin: | | |
Retail Margins | | 2.7 | |
Margins from Off-system Sales | | (20.2) | |
Transmission Revenues | | 8.9 | |
Other Revenues | | (36.8) | |
Total Change in Gross Margin | | (45.4) | |
| | |
Changes in Expenses and Other: | | |
Other Operation and Maintenance | | 77.3 | |
Depreciation and Amortization | | 29.0 | |
Taxes Other Than Income Taxes | | 3.6 | |
| | |
Interest Income | | (0.3) | |
| | |
Allowance for Equity Funds Used During Construction | | 6.1 | |
| | |
Interest Expense | | (36.5) | |
Total Change in Expenses and Other | | 79.2 | |
| | |
Income Tax Expense | | (28.7) | |
| | |
Nine Months Ended September 30, 2020 | | $ | 197.1 | |
|
| | | | |
Reconciliation of Nine Months Ended September 30, 2018 to Nine Months Ended September 30, 2019 |
Net Income |
(in millions) |
|
Nine Months Ended September 30, 2018 | | $ | 151.1 |
|
| | |
|
Changes in Gross Margin: | | |
Retail Margins | | — |
|
Margins from Off-system Sales | | 59.3 |
|
Transmission Revenues | | 62.3 |
|
Other Revenues | | 1.9 |
|
Total Change in Gross Margin | | 123.5 |
|
| | |
|
Changes in Expenses and Other: | | |
|
Other Operation and Maintenance | | (49.9 | ) |
Depreciation and Amortization | | (99.9 | ) |
Taxes Other Than Income Taxes | | (8.0 | ) |
Interest Income | | 1.5 |
|
Allowance for Equity Funds Used During Construction | | (6.9 | ) |
Non-Service Cost Components of Net Periodic Benefit Cost | | (0.8 | ) |
Interest Expense | | 16.2 |
|
Total Change in Expenses and Other | | (147.8 | ) |
| | |
|
Income Tax Expense (Benefit) | | 65.2 |
|
| | |
|
Nine Months Ended September 30, 2019 | | $ | 192.0 |
|
The major components of the increasedecrease in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals were as follows:
| |
• | •Retail Margins increased $3 million primarily due to the following: •A $21 million increase in weather-normalized margins primarily driven by the residential class and partially offset by a decrease in the industrial class. • were unchanged primarily due to the following: |
A $7 million increase from interim rate increases driven by increased transmission investment.
•A $7 million increase from interim rate increases driven by increased distribution investment.
•A $7 million increase due to new base rates implemented in June 2020.
•A $5 million increase due to the change in the recording of merger savings as authorized by the PUCT in the most recent base rate case.
These increases were partially offset by:
•A $25 million decrease due to refunds of Excess ADIT and excess federal income taxes collected as a result of Tax Reform. This decrease was partially offset in Income Tax Expense below.
•A $15 million decrease in revenuesweather-related usage primarily due to a 6% decrease in cooling degree days and a 46% decrease in heating degree days.
•A $4 million decrease due to refunds to customers associated with the Transmission Cost Recovery Factor revenue rider.most recent base rate case. This decrease was offset in Other Revenues below.
•Margins from Off-system Sales decreased $20 million primarily due to lower Oklaunion Power Station PPA revenues. This decrease was partially offset in Other Operation and Maintenance expenses below.
A $5•Transmission Revenues increased $9 million decrease in weather-related usage primarily due to a 23% decrease in heating degree days,the following:
•A $30 million increase from interim rate increases driven by increased transmission investment.
This increase was partially offset byby:
•A $14 million decrease due to a 3% increaseone-time credit to transmission customers as a result of Tax Reform and the most recent base rate case. This decrease was offset in cooling degree days.Income Tax Expense below.
These decreases were•A $7 million decrease due to refunds to customers associated with the most recent base rate case. This decrease was offset in Other Revenues below.
•Other Revenues decreased $37 million primarily due to the following:
•A $49 million decrease related to securitization revenues primarily due to the AEP Texas Central Transition Funding II LLC bonds that matured in July 2020. This decrease was offset below in Depreciation and Amortization expenses and in Interest Expense.
This decrease was partially offset by:
A $12•An $11 million increase in weather-normalized margins primarilyrevenues due to the amortization of a provision for refund recorded in December 2019 as part of the residentialmost recent base rate case. This increase was offset in Retail Margins and commercial classes.Transmission Revenues above.
| |
• |
Margins from Off-system Sales increased $59 million due to higher affiliated PPA revenues. This increase was partially offset below in Other Operation and Maintenance expenses and in Depreciation and Amortization expenses.
|
| |
• | Transmission Revenues increased $62 million primarily due to recovery of increased transmission investment in ERCOT.
|
Expenses and Other and Income Tax Expense (Benefit) changed between years as follows:
| |
• | Other Operation and Maintenance expenses increased $50Other Operation and Maintenance expenses decreased $77 million primarily due to the following: |
A $64 million increase in expense due to the following:
•A $67 million decrease due to prior year partial amortization of the AEP Texas Storm Cost Restoration Securitization regulatory asset as a result of the AEP Texas Storm Cost Securitization financing order issued by the PUCT in June 2019. This increasedecrease was offset in Income Tax Expense (Benefit) below.
•A $17 million decrease due to the revision of the Oklaunion Power Station ARO. This decrease was offset in Margins from Off-System Sales above.
These increasesdecreases were partially offset by:
•A $7$9 million increase in transmission expenses. This increase was partially offset in Gross Margin above.
•A $5 million increase due to the write-off of land associated with the Oklaunion Power Station.
•Depreciation and Amortization expenses decreased $29 million primarily due to the following:
•A $43 million decrease in distribution expenses.securitization amortizations due to the AEP Texas Central Transition Funding II LLC bonds that matured in July 2020. This increase was offset in Other Revenues above and in Interest Expense below.
A $7 million decrease in ERCOT transmission expenses. This decrease was partially offset in Retail Margins above.by:
•A $5 million decrease in expenses associated with Oklaunion Power Station. This decrease was partially offset in Margins from Off-system Sales above and in Depreciation and Amortization expenses below.
| |
• | Depreciation and Amortization expenses increased $100 million primarily due to the following:
|
A $49 million increase in depreciation expense due to a change in the useful life of the Oklaunion Power Station. This increase was offset above in Margins from Off-system Sales and in Other Operation and Maintenance expenses.
A $34$14 million increase in depreciation expense due to an increase in the depreciable base of transmission and distribution assetsassets.
•Taxes Other Than Income Taxes decreased $4 million primarily relateddue to advanced metering systems.lower property taxes.
•Allowance for Equity Funds Used During Construction increased $6 million primarily due to an increase in the equity component of AFUDC as a result of lower short-term balances and increased transmission projects.
•Interest Expense increased $37 million primarily due to:
•A $9$24 million increase in securitization amortizations primarily related to Transition Funding. This increase was offset in Other Revenues above and in Interest Expense below.
A $6 million increase in ARO associated with Oklaunion Power Station.
| |
• | Taxes Other Than Income Taxes increased $8 million primarily due to an increase in property taxes driven by additional investments in transmission and distribution assets and higher tax rates.
|
| |
• | Allowance for Equity Funds Used During Construction decreased $7 million primarily due to a decrease in the Equity component as a result of higher short-term debt balances, partially offset by increased transmission projects.
|
| |
• | Interest Expense decreased $16 million primarily due to:
|
A $21 million decrease due to the prior year deferral of previously recorded interest expense approved for recovery as a result of the Texas Storm Cost Securitization financing order issued by the PUCT in June 2019.
An $8 million decrease in expense related to Transition Funding Securitization assets. This decrease was offset above in Other Revenues and Depreciation and Amortization expenses.
These decreases were partially offset by:
An $11•A $9 million increase due to higher long-term debt balances.
| |
• | Income Tax Expense (Benefit)•A $6 million increase due to due to a decrease in the debt component of AFUDC. These increases were partially offset by: •A $5 million decrease due to lower short-term debt balances. •Income Tax Expense increased $29 million primarily due to the prior year amortization of Excess ADIT not subject to normalization requirements as approved in the Texas Storm Cost Securitization financing order issued by the PUCT in 2019 partially offset by current year amortization of Excess ADIT and an increase in favorable AFUDC Equity tax benefit. This increase was partially offset in Gross Margins and Other Operation and Maintenance Expenses above. decreased $65 million primarily due to the amortization of Excess ADIT not subject to normalization requirements as approved in the Texas Storm Cost Securitization financing order issued by the PUCT in June 2019. This decrease was partially offset above in Other Operation and Maintenance expenses. |
AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 20192020 and 20182019
(in millions)
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | | | Nine Months Ended | | |
| | September 30, | | | | September 30, | | |
| | 2020 | | 2019 | | 2020 | | 2019 |
REVENUES | | | | | | | | |
Electric Transmission and Distribution | | $ | 390.1 | | | $ | 445.4 | | | $ | 1,165.2 | | | $ | 1,190.3 | |
Sales to AEP Affiliates | | 41.4 | | | 42.7 | | | 89.4 | | | 125.1 | |
Other Revenues | | 0.5 | | | 1.2 | | | 2.5 | | | 2.6 | |
TOTAL REVENUES | | 432.0 | | | 489.3 | | | 1,257.1 | | | 1,318.0 | |
| | | | | | | | |
EXPENSES | | | | | | | | |
Fuel and Other Consumables Used for Electric Generation | | 10.4 | | | 11.2 | | | 13.6 | | | 29.1 | |
Other Operation | | 134.3 | | | 128.2 | | | 344.7 | | | 349.2 | |
Maintenance | | 20.4 | | | 21.7 | | | 64.1 | | | 136.9 | |
Depreciation and Amortization | | 107.7 | | | 170.2 | | | 435.8 | | | 464.8 | |
Taxes Other Than Income Taxes | | 38.7 | | | 39.8 | | | 106.7 | | | 110.3 | |
TOTAL EXPENSES | | 311.5 | | | 371.1 | | | 964.9 | | | 1,090.3 | |
| | | | | | | | |
OPERATING INCOME | | 120.5 | | | 118.2 | | | 292.2 | | | 227.7 | |
| | | | | | | | |
Other Income (Expense): | | | | | | | | |
Interest Income | | 0.5 | | | 0.4 | | | 1.2 | | | 1.5 | |
| | | | | | | | |
Allowance for Equity Funds Used During Construction | | 4.4 | | | 5.1 | | | 14.4 | | | 8.3 | |
| | | | | | | | |
Non-Service Cost Components of Net Periodic Benefit Cost | | 2.8 | | | 2.8 | | | 8.4 | | | 8.4 | |
Interest Expense | | (44.5) | | | (35.8) | | | (129.2) | | | (92.7) | |
| | | | | | | | |
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) | | 83.7 | | | 90.7 | | | 187.0 | | | 153.2 | |
| | | | | | | | |
Income Tax Expense (Benefit) | | 1.1 | | | 13.7 | | | (10.1) | | | (38.8) | |
| | | | | | | | |
NET INCOME | | $ | 82.6 | | | $ | 77.0 | | | $ | 197.1 | | | $ | 192.0 | |
| | | | | | | | |
The common stock of AEP Texas is wholly-owned by Parent. | | | | | | | | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134. | | | | | | | | |
|
| | | | | | | | | | | | | | | | |
| | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, |
| | 2019 | | 2018 | | 2019 | | 2018 |
REVENUES | | | | | | | | |
Electric Transmission and Distribution | | $ | 445.4 |
| | $ | 404.5 |
| | $ | 1,190.3 |
| | $ | 1,127.0 |
|
Sales to AEP Affiliates | | 42.7 |
| | 27.5 |
| | 125.1 |
| | 63.3 |
|
Other Revenues | | 1.2 |
| | 1.4 |
| | 2.6 |
| | 3.0 |
|
TOTAL REVENUES | | 489.3 |
| | 433.4 |
| | 1,318.0 |
| | 1,193.3 |
|
| | | | | | | | |
EXPENSES | | |
| | |
| | |
| | |
|
Fuel and Other Consumables Used for Electric Generation | | 11.2 |
| | 13.2 |
| | 29.1 |
| | 27.9 |
|
Other Operation | | 128.2 |
| | 133.4 |
| | 349.2 |
| | 368.4 |
|
Maintenance | | 21.7 |
| | 23.2 |
| | 136.9 |
| | 67.8 |
|
Depreciation and Amortization | | 170.2 |
| | 133.3 |
| | 464.8 |
| | 364.9 |
|
Taxes Other Than Income Taxes | | 39.8 |
| | 36.3 |
| | 110.3 |
| | 102.3 |
|
TOTAL EXPENSES | | 371.1 |
| | 339.4 |
| | 1,090.3 |
| | 931.3 |
|
| | | | | | | | |
OPERATING INCOME | | 118.2 |
| | 94.0 |
| | 227.7 |
| | 262.0 |
|
| | | | | | | | |
Other Income (Expense): | | |
| | |
| | |
| | |
|
Interest Income | | 0.4 |
| | 0.5 |
| | 1.5 |
| | — |
|
Allowance for Equity Funds Used During Construction | | 5.1 |
| | 5.8 |
| | 8.3 |
| | 15.2 |
|
Non-Service Cost Components of Net Periodic Benefit Cost | | 2.8 |
| | 3.1 |
| | 8.4 |
| | 9.2 |
|
Interest Expense | | (35.8 | ) | | (37.3 | ) | | (92.7 | ) | | (108.9 | ) |
| | | | | | | | |
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) | | 90.7 |
| | 66.1 |
| | 153.2 |
| | 177.5 |
|
| | | | | | | | |
Income Tax Expense (Benefit) | | 13.7 |
| | 8.3 |
| | (38.8 | ) | | 26.4 |
|
| | | | | | | | |
NET INCOME | | $ | 77.0 |
| | $ | 57.8 |
| | $ | 192.0 |
| | $ | 151.1 |
|
|
|
The common stock of AEP Texas is wholly-owned by Parent. |
|
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 126.
|
AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 20192020 and 20182019
(in millions)
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | | | Nine Months Ended | | |
| | September 30, | | | | September 30, | | |
| | 2020 | | 2019 | | 2020 | | 2019 |
Net Income | | $ | 82.6 | | | $ | 77.0 | | | $ | 197.1 | | | $ | 192.0 | |
| | | | | | | | |
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, 2020 and 2019, Respectively, and $0.2 and $0.2 for the Nine Months Ended September 30, 2020 and 2019, 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, 2020 and 2019, Respectively, and $0 and $0 for the Nine Months Ended September 30, 2020 and 2019, Respectively | | 0 | | | 0 | | | 0.1 | | | 0.1 | |
| | | | | | | | |
TOTAL OTHER COMPREHENSIVE INCOME | | 0.3 | | | 0.3 | | | 0.9 | | | 0.9 | |
| | | | | | | | |
TOTAL COMPREHENSIVE INCOME | | $ | 82.9 | | | $ | 77.3 | | | $ | 198.0 | | | $ | 192.9 | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134. | | | | | | | | |
|
| | | | | | | | | | | | | | | | |
| | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, |
| | 2019 | | 2018 | | 2019 | | 2018 |
Net Income | | $ | 77.0 |
| | $ | 57.8 |
| | $ | 192.0 |
| | $ | 151.1 |
|
| | | | | | | | |
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, 2019 and 2018, Respectively, and $0.2 and $0.2 for the Nine Months Ended September 30, 2019 and 2018, 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, 2019 and 2018, Respectively, and $0 and $0 for the Nine Months Ended September 30, 2019 and 2018, Respectively | | — |
| | — |
| | 0.1 |
| | 0.1 |
|
| | | | | | | | |
TOTAL OTHER COMPREHENSIVE INCOME | | 0.3 |
| | 0.3 |
| | 0.9 |
| | 0.9 |
|
| | | | | | | | |
TOTAL COMPREHENSIVE INCOME | | $ | 77.3 |
| | $ | 58.1 |
| | $ | 192.9 |
| | $ | 152.0 |
|
|
|
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 126.
|
AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Nine Months Ended September 30, 20192020 and 20182019
(in millions)
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Paid-in Capital | | Retained Earnings | | Accumulated Other Comprehensive Income (Loss) | | Total |
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2018 | | $ | 1,257.9 | | | $ | 1,337.7 | | | $ | (15.1) | | | $ | 2,580.5 | |
| | | | | | | | |
Capital Contribution from Parent | | 200.0 | | | | | | | 200.0 | |
| | | | | | | | |
Net Income | | | | 34.4 | | | | | 34.4 | |
Other Comprehensive Income | | | | | | 0.3 | | | 0.3 | |
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2019 | | 1,457.9 | | | 1,372.1 | | | (14.8) | | | 2,815.2 | |
| | | | | | | | |
| | | | | | | | |
Net Income | | | | 80.6 | | | | | 80.6 | |
Other Comprehensive Income | | | | | | 0.3 | | | 0.3 | |
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2019 | | 1,457.9 | | | 1,452.7 | | | (14.5) | | | 2,896.1 | |
| | | | | | | | |
| | | | | | | | |
Net Income | | | | 77.0 | | | | | 77.0 | |
Other Comprehensive Income | | | | | | 0.3 | | | 0.3 | |
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2019 | | $ | 1,457.9 | | | $ | 1,529.7 | | | $ | (14.2) | | | $ | 2,973.4 | |
| | | | | | | | |
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2019 | | $ | 1,457.9 | | | $ | 1,516.0 | | | $ | (12.8) | | | $ | 2,961.1 | |
| | | | | | | | |
| | | | | | | | |
Net Income | | | | 47.6 | | | | | 47.6 | |
Other Comprehensive Income | | | | | | 0.3 | | | 0.3 | |
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2020 | | 1,457.9 | | | 1,563.6 | | | (12.5) | | | 3,009.0 | |
| | | | | | | | |
| | | | | | | | |
Net Income | | | | 66.9 | | | | | 66.9 | |
Other Comprehensive Income | | | | | | 0.3 | | | 0.3 | |
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2020 | | 1,457.9 | | | 1,630.5 | | | (12.2) | | | 3,076.2 | |
| | | | | | | | |
| | | | | | | | |
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 | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134. | | | | | | | | |
|
| | | | | | | | | | | | | | | | |
| | Paid-in Capital | | Retained Earnings | | Accumulated Other Comprehensive Income (Loss) | | Total |
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2017 | | $ | 1,057.9 |
| | $ | 1,124.6 |
| | $ | (12.6 | ) | | $ | 2,169.9 |
|
| | | | | | | | |
Capital Contribution from Parent | | 100.0 |
| | | | | | 100.0 |
|
ASU 2018-02 Adoption | | | | 1.8 |
| | (2.7 | ) | | (0.9 | ) |
Net Income | | | | 46.8 |
| | | | 46.8 |
|
Other Comprehensive Income | | | | | | 0.3 |
| | 0.3 |
|
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2018 | | 1,157.9 |
| | 1,173.2 |
| | (15.0 | ) | | 2,316.1 |
|
| | | | | | | | |
Net Income | | |
| | 46.5 |
| | |
| | 46.5 |
|
Other Comprehensive Income | | |
| | |
| | 0.3 |
| | 0.3 |
|
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2018 | | 1,157.9 |
| | 1,219.7 |
| | (14.7 | ) | | 2,362.9 |
|
| | | | | | | | |
Net Income | | | | 57.8 |
| | | | 57.8 |
|
Other Comprehensive Income | | | | | | 0.3 |
| | 0.3 |
|
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2018 | | $ | 1,157.9 |
| | $ | 1,277.5 |
| | $ | (14.4 | ) | | $ | 2,421.0 |
|
| | | | | | | | |
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2018 | | $ | 1,257.9 |
| | $ | 1,337.7 |
| | $ | (15.1 | ) | | $ | 2,580.5 |
|
| | | | | | | | |
Capital Contribution from Parent | | 200.0 |
| | | | | | 200.0 |
|
Net Income | | | | 34.4 |
| | | | 34.4 |
|
Other Comprehensive Income | | | | | | 0.3 |
| | 0.3 |
|
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2019 | | 1,457.9 |
| | 1,372.1 |
| | (14.8 | ) | | 2,815.2 |
|
| | | | | | | | |
Net Income | | |
| | 80.6 |
| | | | 80.6 |
|
Other Comprehensive Income | | |
| | | | 0.3 |
| | 0.3 |
|
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2019 | | 1,457.9 |
| | 1,452.7 |
| | (14.5 | ) | | 2,896.1 |
|
| | | | | | | | |
Net Income | | | | 77.0 |
| | | | 77.0 |
|
Other Comprehensive Income | | | | | | 0.3 |
| | 0.3 |
|
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2019 | | $ | 1,457.9 |
| | $ | 1,529.7 |
| | $ | (14.2 | ) | | $ | 2,973.4 |
|
|
|
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 126.
|
AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 20192020 and December 31, 20182019
(in millions)
(Unaudited)
| | | | | | | | | | | | | | |
| | September 30, | | December 31, |
| | 2020 | | 2019 |
CURRENT ASSETS | | | | |
Cash and Cash Equivalents | | $ | 0.1 | | | $ | 3.1 | |
Restricted Cash (September 30, 2020 and December 31, 2019 Amounts Include $44.8 and $154.7, Respectively, Related to Transition Funding and Restoration Funding) | | 44.8 | | | 154.7 | |
Advances to Affiliates | | 148.4 | | | 207.2 | |
Accounts Receivable: | | | | |
Customers | | 136.8 | | | 116.0 | |
Affiliated Companies | | 22.0 | | | 10.1 | |
Accrued Unbilled Revenues | | 74.8 | | | 68.8 | |
Miscellaneous | | 0 | | | 0.3 | |
Allowance for Uncollectible Accounts | | 0 | | | (1.8) | |
Total Accounts Receivable | | 233.6 | | | 193.4 | |
Fuel | | 0 | | | 5.9 | |
Materials and Supplies | | 72.0 | | | 56.7 | |
| | | | |
Accrued Tax Benefits | | 9.6 | | | 66.1 | |
Prepayments and Other Current Assets | | 5.6 | | | 5.8 | |
TOTAL CURRENT ASSETS | | 514.1 | | | 692.9 | |
| | | | |
PROPERTY, PLANT AND EQUIPMENT | | | | |
Electric: | | | | |
Generation | | 0 | | | 351.7 | |
Transmission | | 4,943.8 | | | 4,466.5 | |
Distribution | | 4,486.6 | | | 4,215.2 | |
Other Property, Plant and Equipment | | 868.2 | | | 805.9 | |
Construction Work in Progress | | 787.9 | | | 763.9 | |
Total Property, Plant and Equipment | | 11,086.5 | | | 10,603.2 | |
Accumulated Depreciation and Amortization | | 1,541.5 | | | 1,758.1 | |
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | 9,545.0 | | | 8,845.1 | |
| | | | |
OTHER NONCURRENT ASSETS | | | | |
Regulatory Assets | | 275.4 | | | 280.6 | |
Securitized Assets (September 30, 2020 and December 31, 2019 Amounts Include $467.8 and $621.2, Respectively, Related to Transition Funding and Restoration Funding) | | 467.8 | | | 623.4 | |
| | | | |
Deferred Charges and Other Noncurrent Assets | | 182.7 | | | 147.1 | |
TOTAL OTHER NONCURRENT ASSETS | | 925.9 | | | 1,051.1 | |
| | | | |
TOTAL ASSETS | | $ | 10,985.0 | | | $ | 10,589.1 | |
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134. | | | | |
|
| | | | | | | | |
| | September 30, | | December 31, |
| | 2019 | | 2018 |
CURRENT ASSETS | | | | |
Cash and Cash Equivalents | | $ | 0.1 |
| | $ | 3.1 |
|
Restricted Cash for Securitized Transition Funding | | 114.3 |
| | 156.7 |
|
Advances to Affiliates | | 7.7 |
| | 8.0 |
|
Accounts Receivable: | | | | |
Customers | | 148.0 |
| | 110.9 |
|
Affiliated Companies | | 17.6 |
| | 15.0 |
|
Accrued Unbilled Revenues | | 82.7 |
| | 70.4 |
|
Miscellaneous | | 0.2 |
| | 1.9 |
|
Allowance for Uncollectible Accounts | | (1.6 | ) | | (1.3 | ) |
Total Accounts Receivable | | 246.9 |
| | 196.9 |
|
Fuel | | 7.1 |
| | 8.8 |
|
Materials and Supplies | | 54.6 |
| | 52.8 |
|
Accrued Tax Benefits | | 111.3 |
| | 44.9 |
|
Prepayments and Other Current Assets | | 6.4 |
| | 5.3 |
|
TOTAL CURRENT ASSETS | | 548.4 |
| | 476.5 |
|
| | | | |
PROPERTY, PLANT AND EQUIPMENT | | | | |
Electric: | | | | |
Generation | | 351.8 |
| | 352.1 |
|
Transmission | | 4,102.8 |
| | 3,683.6 |
|
Distribution | | 4,122.2 |
| | 4,043.2 |
|
Other Property, Plant and Equipment | | 775.3 |
| | 727.9 |
|
Construction Work in Progress | | 978.4 |
| | 836.2 |
|
Total Property, Plant and Equipment | | 10,330.5 |
| | 9,643.0 |
|
Accumulated Depreciation and Amortization | | 1,742.7 |
| | 1,651.2 |
|
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | 8,587.8 |
| | 7,991.8 |
|
| | | | |
OTHER NONCURRENT ASSETS | | | | |
Regulatory Assets | | 259.6 |
| | 430.0 |
|
Securitized Assets (September 30, 2019 and December 31, 2018 Amounts Include $693 and $636.8, Respectively, Related to Transition Funding and Restoration Funding) | | 698.1 |
| | 649.1 |
|
Deferred Charges and Other Noncurrent Assets | | 161.9 |
| | 56.3 |
|
TOTAL OTHER NONCURRENT ASSETS | | 1,119.6 |
| | 1,135.4 |
|
| | | | |
TOTAL ASSETS | | $ | 10,255.8 |
| | $ | 9,603.7 |
|
|
|
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 126.
|
AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
September 30, 20192020 and December 31, 20182019
(in millions)
(Unaudited)
| | | | | | | | | | | | | | |
| | September 30, | | December 31, |
| | 2020 | | 2019 |
CURRENT LIABILITIES | | | | |
| | | | |
Accounts Payable: | | | | |
General | | $ | 235.3 | | | $ | 256.8 | |
Affiliated Companies | | 27.2 | | | 35.6 | |
Short-term Debt – Nonaffiliated | | 2.0 | | | 0 | |
Long-term Debt Due Within One Year – Nonaffiliated (September 30, 2020 and December 31, 2019 Amounts Include $87.7 and $281.4, Respectively, Related to Transition Funding and Restoration Funding) | | 87.8 | | | 392.1 | |
Risk Management Liabilities | | 0.1 | | | 0 | |
| | | | |
Accrued Taxes | | 101.8 | | | 84.9 | |
Accrued Interest (September 30, 2020 and December 31, 2019 Amounts Include $3.5 and $7.5, Respectively, Related to Transition Funding and Restoration Funding) | | 54.7 | | | 35.7 | |
Oklaunion Purchase Power Agreement | | 0 | | | 22.1 | |
Obligations Under Operating Leases | | 13.7 | | | 12.0 | |
Provision for Refund | | 31.6 | | | 64.7 | |
Other Current Liabilities | | 92.2 | | | 123.3 | |
TOTAL CURRENT LIABILITIES | | 646.4 | | | 1,027.2 | |
| | | | |
NONCURRENT LIABILITIES | | | | |
Long-term Debt – Nonaffiliated (September 30, 2020 and December 31, 2019 Amounts Include $440.2 and $495.4, Respectively, Related to Transition Funding and Restoration Funding) | | 4,766.9 | | | 4,166.3 | |
| | | | |
Deferred Income Taxes | | 1,004.4 | | | 965.4 | |
Regulatory Liabilities and Deferred Investment Tax Credits | | 1,282.6 | | | 1,316.9 | |
| | | | |
Obligations Under Operating Leases | | 71.0 | | | 71.1 | |
Deferred Credits and Other Noncurrent Liabilities | | 54.6 | | | 81.1 | |
TOTAL NONCURRENT LIABILITIES | | 7,179.5 | | | 6,600.8 | |
| | | | |
TOTAL LIABILITIES | | 7,825.9 | | | 7,628.0 | |
| | | | |
Rate Matters (Note 4) | | | | |
Commitments and Contingencies (Note 5) | | | | |
| | | | |
COMMON SHAREHOLDER’S EQUITY | | | | |
Paid-in Capital | | 1,457.9 | | | 1,457.9 | |
Retained Earnings | | 1,713.1 | | | 1,516.0 | |
Accumulated Other Comprehensive Income (Loss) | | (11.9) | | | (12.8) | |
TOTAL COMMON SHAREHOLDER’S EQUITY | | 3,159.1 | | | 2,961.1 | |
| | | | |
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY | | $ | 10,985.0 | | | $ | 10,589.1 | |
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134. | | | | |
|
| | | | | | | | |
| | September 30, | | December 31, |
| | 2019 | | 2018 |
CURRENT LIABILITIES | | | | |
Advances from Affiliates | | $ | 74.8 |
| | $ | 216.0 |
|
Accounts Payable: | | | | |
General | | 224.1 |
| | 276.5 |
|
Affiliated Companies | | 41.0 |
| | 30.3 |
|
Long-term Debt Due Within One Year – Nonaffiliated (September 30, 2019 and December 31, 2018 Amounts Include $280.8 and $251.1, Respectively, Related to Transition Funding and Restoration Funding) | | 391.4 |
| | 501.1 |
|
Risk Management Liabilities | | 0.3 |
| | 0.2 |
|
Accrued Taxes | | 108.5 |
| | 75.5 |
|
Accrued Interest (September 30, 2019 and December 31, 2018 Amounts Include $6.1 and $11.3, Respectively, Related to Transition Funding and Restoration Funding) | | 50.6 |
| | 37.3 |
|
Oklaunion Purchase Power Agreement | | 28.7 |
| | 24.3 |
|
Obligations Under Operating Leases | | 11.7 |
| | — |
|
Other Current Liabilities | | 85.1 |
| | 98.3 |
|
TOTAL CURRENT LIABILITIES | | 1,016.2 |
| | 1,259.5 |
|
| | | | |
NONCURRENT LIABILITIES | | | | |
Long-term Debt – Nonaffiliated (September 30, 2019 and December 31, 2018 Amounts Include $530.5 and $540.1, Respectively, Related to Transition Funding and Restoration Funding) | | 3,755.1 |
| | 3,380.2 |
|
Long-term Risk Management Liabilities | | 0.1 |
| | — |
|
Deferred Income Taxes | | 977.7 |
| | 913.1 |
|
Regulatory Liabilities and Deferred Investment Tax Credits | | 1,325.1 |
| | 1,344.3 |
|
Oklaunion Purchase Power Agreement | | — |
| | 22.1 |
|
Obligations Under Operating Leases | | 71.1 |
| | — |
|
Deferred Credits and Other Noncurrent Liabilities | | 137.1 |
| | 104.0 |
|
TOTAL NONCURRENT LIABILITIES | | 6,266.2 |
| | 5,763.7 |
|
| | | | |
TOTAL LIABILITIES | | 7,282.4 |
| | 7,023.2 |
|
| | | | |
Rate Matters (Note 4) | |
| |
|
Commitments and Contingencies (Note 5) | |
| |
|
| | | | |
COMMON SHAREHOLDER’S EQUITY | | | | |
Paid-in Capital | | 1,457.9 |
| | 1,257.9 |
|
Retained Earnings | | 1,529.7 |
| | 1,337.7 |
|
Accumulated Other Comprehensive Income (Loss) | | (14.2 | ) | | (15.1 | ) |
TOTAL COMMON SHAREHOLDER’S EQUITY | | 2,973.4 |
| | 2,580.5 |
|
| | | | |
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY | | $ | 10,255.8 |
| | $ | 9,603.7 |
|
|
|
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 126.
|
AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 20192020 and 20182019
(in millions)
(Unaudited)
| | | | | | | | | | | | | | |
| | Nine Months Ended September 30, | | |
| | 2020 | | 2019 |
OPERATING ACTIVITIES | | | | |
Net Income | | $ | 197.1 | | | $ | 192.0 | |
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | | | |
Depreciation and Amortization | | 435.8 | | | 464.8 | |
Deferred Income Taxes | | (11.5) | | | (0.6) | |
Allowance for Equity Funds Used During Construction | | (14.4) | | | (8.3) | |
Mark-to-Market of Risk Management Contracts | | 0.1 | | | 0.2 | |
Pension Contributions to Qualified Plan Trust | | (11.3) | | | 0 | |
| | | | |
| | | | |
Change in Other Noncurrent Assets | | (77.3) | | | 0.5 | |
Change in Other Noncurrent Liabilities | | (30.0) | | | 6.5 | |
Changes in Certain Components of Working Capital: | | | | |
Accounts Receivable, Net | | (40.2) | | | (50.0) | |
Fuel, Materials and Supplies | | (9.4) | | | (0.1) | |
Accounts Payable | | 24.2 | | | 17.8 | |
| | | | |
Accrued Taxes, Net | | 73.4 | | | (33.4) | |
| | | | |
Other Current Assets | | (0.8) | | | (0.7) | |
Other Current Liabilities | | (49.8) | | | (12.9) | |
Net Cash Flows from Operating Activities | | 485.9 | | | 575.8 | |
| | | | |
INVESTING ACTIVITIES | | | | |
Construction Expenditures | | (976.1) | | | (954.5) | |
Change in Advances to Affiliates, Net | | 58.8 | | | 0.3 | |
| | | | |
Other Investing Activities | | 24.1 | | | 18.4 | |
Net Cash Flows Used for Investing Activities | | (893.2) | | | (935.8) | |
| | | | |
FINANCING ACTIVITIES | | | | |
Capital Contribution from Parent | | 0 | | | 200.0 | |
Issuance of Long-term Debt – Nonaffiliated | | 652.8 | | | 627.5 | |
Change in Short-term Debt, Net – Nonaffiliated | | 2.0 | | | 0 | |
Change in Advances from Affiliates, Net | | 0 | | | (141.2) | |
Retirement of Long-term Debt – Nonaffiliated | | (356.5) | | | (366.8) | |
Principal Payments for Finance Lease Obligations | | (4.7) | | | (3.8) | |
| | | | |
Other Financing Activities | | 0.8 | | | (1.1) | |
Net Cash Flows from Financing Activities | | 294.4 | | | 314.6 | |
| | | | |
Net Decrease in Cash, Cash Equivalents and Restricted Cash | | (112.9) | | | (45.4) | |
Cash, Cash Equivalents and Restricted Cash at Beginning of Period | | 157.8 | | | 159.8 | |
Cash, Cash Equivalents and Restricted Cash at End of Period | | $ | 44.9 | | | $ | 114.4 | |
| | | | |
SUPPLEMENTARY INFORMATION | | | | |
Cash Paid for Interest, Net of Capitalized Amounts | | $ | 102.0 | | | $ | 95.1 | |
Net Cash Paid (Received) for Income Taxes | | (55.6) | | | 28.7 | |
Noncash Acquisitions Under Finance Leases | | 5.1 | | | 6.9 | |
Construction Expenditures Included in Current Liabilities as of September 30, | | 167.6 | | | 183.6 | |
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134. | | | | |
|
| | | | | | | | |
| | Nine Months Ended September 30, |
| | 2019 | | 2018 |
OPERATING ACTIVITIES | | |
| | |
|
Net Income | | $ | 192.0 |
| | $ | 151.1 |
|
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | |
| | |
|
Depreciation and Amortization | | 464.8 |
| | 364.9 |
|
Deferred Income Taxes | | (0.6 | ) | | (21.2 | ) |
Allowance for Equity Funds Used During Construction | | (8.3 | ) | | (15.2 | ) |
Mark-to-Market of Risk Management Contracts | | 0.2 |
| | — |
|
Change in Other Noncurrent Assets | | 0.5 |
| | (55.7 | ) |
Change in Other Noncurrent Liabilities | | 6.5 |
| | 67.1 |
|
Changes in Certain Components of Working Capital: | | |
| | |
Accounts Receivable, Net | | (50.0 | ) | | (26.5 | ) |
Fuel, Materials and Supplies | | (0.1 | ) | | (2.4 | ) |
Accounts Payable | | 17.8 |
| | (19.1 | ) |
Accrued Taxes, Net | | (33.4 | ) | | 40.0 |
|
Other Current Assets | | (0.7 | ) | | (6.3 | ) |
Other Current Liabilities | | (12.9 | ) | | 14.1 |
|
Net Cash Flows from Operating Activities | | 575.8 |
| | 490.8 |
|
| | | | |
INVESTING ACTIVITIES | | |
| | |
|
Construction Expenditures | | (954.5 | ) | | (1,096.1 | ) |
Change in Advances to Affiliates, Net | | 0.3 |
| | 103.9 |
|
Other Investing Activities | | 18.4 |
| | 31.1 |
|
Net Cash Flows Used for Investing Activities | | (935.8 | ) | | (961.1 | ) |
| | | | |
FINANCING ACTIVITIES | | |
| | |
|
Capital Contribution from Parent | | 200.0 |
| | 100.0 |
|
Issuance of Long-term Debt – Nonaffiliated | | 627.5 |
| | 494.0 |
|
Change in Advances from Affiliates, Net | | (141.2 | ) | | 77.8 |
|
Retirement of Long-term Debt – Nonaffiliated | | (366.8 | ) | | (231.7 | ) |
Principal Payments for Finance Lease Obligations | | (3.8 | ) | | (3.6 | ) |
Other Financing Activities | | (1.1 | ) | | 0.9 |
|
Net Cash Flows from Financing Activities | | 314.6 |
| | 437.4 |
|
| | | | |
Net Decrease in Cash, Cash Equivalents and Restricted Cash for Securitized Transition Funding | | (45.4 | ) | | (32.9 | ) |
Cash, Cash Equivalents and Restricted Cash for Securitized Transition Funding at Beginning of Period | | 159.8 |
| | 157.2 |
|
Cash, Cash Equivalents and Restricted Cash for Securitized Transition Funding at End of Period | | $ | 114.4 |
| | $ | 124.3 |
|
| | | | |
SUPPLEMENTARY INFORMATION | | |
| | |
|
Cash Paid for Interest, Net of Capitalized Amounts | | $ | 95.1 |
| | $ | 92.2 |
|
Net Cash Paid (Received) for Income Taxes | | 28.7 |
| | (14.2 | ) |
Noncash Acquisitions Under Finance Leases | | 6.9 |
| | 8.9 |
|
Construction Expenditures Included in Current Liabilities as of September 30, | | 183.6 |
| | 176.4 |
|
|
|
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page
126. |
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, | | |
| | 2020 | | 2019 |
| | (in millions) | | |
Plant In Service | | $ | 9,240.4 | | | $ | 7,409.0 | |
Construction Work in Progress | | 1,680.9 | | | 1,858.4 | |
Accumulated Depreciation and Amortization | | 531.8 | | | 368.8 | |
Total Transmission Property, Net | | $ | 10,389.5 | | | $ | 8,898.6 | |
|
| | | | | | | | |
| | As of September 30, |
| | 2019 | | 2018 |
| | (in millions) |
Plant In Service | | $ | 7,409.0 |
| | $ | 5,988.7 |
|
Construction Work in Progress | | 1,858.4 |
| | 1,772.9 |
|
Accumulated Depreciation and Amortization | | 368.8 |
| | 234.6 |
|
Total Transmission Property, Net | | $ | 8,898.6 |
| | $ | 7,527.0 |
|
Third Quarter of 20192020 Compared to Third Quarter of 20182019
| | | | | | | | |
Reconciliation of Third Quarter of 2019 to Third Quarter of 2020 | | |
Net Income | | |
(in millions) | | |
| | |
Third Quarter of 2019 | | $ | 107.6 | |
| | |
Changes in Transmission Revenues: | | |
Transmission Revenues | | 44.4 | |
Total Change in Transmission Revenues | | 44.4 | |
| | |
Changes in Expenses and Other: | | |
Other Operation and Maintenance | | 0.4 | |
Depreciation and Amortization | | (16.2) | |
Taxes Other Than Income Taxes | | (9.3) | |
Interest Income | | (0.6) | |
Allowance for Equity Funds Used During Construction | | (0.8) | |
Interest Expense | | (6.3) | |
Total Change in Expenses and Other | | (32.8) | |
| | |
Income Tax Expense | | (1.6) | |
| | |
| | |
Third Quarter of 2020 | | $ | 117.6 | |
|
| | | | |
Reconciliation of Third Quarter of 2018 to Third Quarter of 2019 |
Net Income |
(in millions) |
| | |
Third Quarter of 2018 | | $ | 78.1 |
|
| | |
Changes in Transmission Revenues: | | |
Transmission Revenues | | 65.3 |
|
Total Change in Transmission Revenues | | 65.3 |
|
| | |
Changes in Expenses and Other: | | |
Other Operation and Maintenance | | (1.9 | ) |
Depreciation and Amortization | | (10.4 | ) |
Taxes Other Than Income Taxes | | (7.7 | ) |
Interest Income | | 0.3 |
|
Allowance for Equity Funds Used During Construction | | 3.0 |
|
Interest Expense | | (6.6 | ) |
Total Change in Expenses and Other | | (23.3 | ) |
| | |
Income Tax Expense | | (12.5 | ) |
| | |
Third Quarter of 2019 | | $ | 107.6 |
|
The major components of the increase in transmission revenues, which consists of wholesale sales to affiliates and nonaffiliates were as follows:
| |
• | •Transmission Revenues increased $44 million primarily due to continued investment in transmission assets.
increased $65 million primarily due to continued investment in transmission assets.
|
Expenses and Other and Income Tax Expense changed between years as follows:
•Depreciation and Amortization expenses increased $16 million primarily due to a higher depreciable base.
•Taxes Other Than Income Taxes increased $9 million primarily due to higher property taxes as a result of increased transmission investment.
•Interest Expense increased $6 million primarily due to higher long-term debt balances.
Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019
| | | | | | | | |
•Reconciliation of Nine Months Ended September 30, 2019 to Nine Months Ended September 30, 2020 | | |
Net Income | | |
(in millions) | | |
| | |
Nine Months Ended September 30, 2019 | | $ | 347.9 | |
| | |
Changes in Transmission Revenues: | | |
Transmission Revenues | | 67.7 | |
Total Change in Transmission Revenues | | 67.7 | |
| | |
Changes in Expenses and Other: | | |
Other Operation and Maintenance | | (8.2) | |
Depreciation and Amortization | | expenses increased $10 million primarily due to a higher depreciable base.(48.0) |
| |
• | Taxes Other Than Income Taxes | | increased $8 million primarily due to higher property taxes as a result of increased transmission investment.(26.6) |
| |
•Interest Income | | 0.2 | |
Allowance for Equity Funds Used During Construction | | increased $3 million primarily due to higher CWIP balances.(6.2) |
| |
• | Interest Expense | | increased $7 million primarily due to higher long-term debt balances.(25.6) |
| |
• | Income Tax Expense increased $13 million primarily due to higher pretax book income.
|
Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018
|
| | | | |
Reconciliation of Nine Months Ended September 30, 2018 to Nine Months Ended September 30, 2019 |
Net Income |
(in millions) |
|
Nine Months Ended September 30, 2018 | | $ | 244.2 |
|
| | |
|
Changes in Transmission Revenues: | | |
|
Transmission Revenues | | 183.9 |
|
Total Change in Transmission Revenues | | 183.9 |
|
| | |
|
Changes in Expenses and Other: | | |
|
Other Operation and Maintenance | | (3.4 | ) |
Depreciation and Amortization | | (30.9 | ) |
Taxes Other Than Income Taxes | | (23.3 | ) |
Interest Income | | 0.8 |
|
Allowance for Equity Funds Used During Construction | | 12.4 |
|
Interest Expense | | (8.8 | ) |
Total Change in Expenses and Other | | (53.2(114.4) | ) |
| | |
|
Income Tax Expense | | (27.07.9 | ) |
| | |
|
Nine Months Ended September 30, 20192020 | | $ | 347.9309.1 |
|
The major components of the increase in transmission revenues, which consists of wholesale sales to affiliates and nonaffiliates were as follows:
| |
• | •Transmission Revenues increased $68 million primarily due to the following: •A $147 million increase due to continued investment in transmission assets. This increase was partially offset by: •A $62 million decrease as a result of the affiliated annual transmission formula rate true-up which is offset in Other Operation and Maintenance expense across the other Registrant subsidiaries. •A $17 million decrease as a result of the non-affiliated annual transmission formula rate true-up.
increased $184 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 $8 million primarily due to the following: • | Depreciation and Amortization expenses increased $31 million primarily due to a higher depreciable base.
|
| |
• | Taxes Other Than Income Taxes increased $23 million primarily due to higher property taxes as a result of increased transmission investment.
|
| |
• | Allowance for Equity Funds Used During Construction increased $12 millionprimarily due to the following:
|
A $13$5 million increase in rent expense.
•A $3 million increase in employee-related expenses.
•Depreciation and Amortization expenses increased $48 million primarily due to a higher depreciable base.
•Taxes Other Than Income Taxes increased $27 million primarily due to higher CWIP balances.property taxes as a result of increased transmission investment.
•Allowance for Equity Funds Used During Construction decreased $6 millionprimarily due to the following:
•A $12 million increasedecrease driven by the favorable impact of a FERC settlement agreement recorded in 2019.
•An $8 million decrease due to the FERC’s approval of a settlement agreement.lower CWIP.
These increasesdecreases were partially offset by:
•A $13 million decreaseincrease driven by FERC audit findings recorded in 2019.
•Interest Expense increased $26 million primarily due to recent FERC audit findings.higher long-term debt balances.
| |
• | Interest•Income Tax Expense decreased $8 million primarily due to lower pretax book income, partially offset by the recognition of a discrete tax adjustment in 2019.
increased $9 million primarily due to higher long-term debt balances.
|
| |
• | Income Tax Expense increased $27 million primarily due to higher pretax book income.
|
AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 20192020 and 20182019
(in millions)
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | | | Nine Months Ended | | |
| | September 30, | | | | September 30, | | |
| | 2020 | | 2019 | | 2020 | | 2019 |
REVENUES | | | | | | | | |
Transmission Revenues | | $ | 62.9 | | | $ | 54.0 | | | $ | 184.6 | | | $ | 162.1 | |
Sales to AEP Affiliates | | 241.2 | | | 205.7 | | | 652.6 | | | 608.0 | |
Other Revenues | | 0 | | | 0 | | | 0.6 | | | 0 | |
TOTAL REVENUES | | 304.1 | | | 259.7 | | | 837.8 | | | 770.1 | |
| | | | | | | | |
EXPENSES | | | | | | | | |
Other Operation | | 25.3 | | | 26.0 | | | 72.0 | | | 61.7 | |
Maintenance | | 3.5 | | | 3.2 | | | 6.8 | | | 8.9 | |
Depreciation and Amortization | | 61.5 | | | 45.3 | | | 176.4 | | | 128.4 | |
Taxes Other Than Income Taxes | | 52.2 | | | 42.9 | | | 152.8 | | | 126.2 | |
TOTAL EXPENSES | | 142.5 | | | 117.4 | | | 408.0 | | | 325.2 | |
| | | | | | | | |
OPERATING INCOME | | 161.6 | | | 142.3 | | | 429.8 | | | 444.9 | |
| | | | | | | | |
Other Income (Expense): | | | | | | | | |
Interest Income - Affiliated | | 0.2 | | | 0.8 | | | 2.3 | | | 2.1 | |
Allowance for Equity Funds Used During Construction | | 20.2 | | | 21.0 | | | 54.9 | | | 61.1 | |
| | | | | | | | |
Interest Expense | | (32.7) | | | (26.4) | | | (95.1) | | | (69.5) | |
| | | | | | | | |
INCOME BEFORE INCOME TAX EXPENSE | | 149.3 | | | 137.7 | | | 391.9 | | | 438.6 | |
| | | | | | | | |
Income Tax Expense | | 31.7 | | | 30.1 | | | 82.8 | | | 90.7 | |
| | | | | | | | |
NET INCOME | | $ | 117.6 | | | $ | 107.6 | | | $ | 309.1 | | | $ | 347.9 | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134. | | | | | | | | |
|
| | | | | | | | | | | | | | | | |
| | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, |
| | 2019 | | 2018 | | 2019 | | 2018 |
REVENUES | | | | | | | | |
Transmission Revenues | | $ | 54.0 |
| | $ | 46.0 |
| | $ | 162.1 |
| | $ | 132.3 |
|
Sales to AEP Affiliates | | 205.7 |
| | 148.4 |
| | 608.0 |
| | 453.8 |
|
Other Revenues | | — |
| | — |
| | — |
| | 0.1 |
|
TOTAL REVENUES | | 259.7 |
| | 194.4 |
| | 770.1 |
| | 586.2 |
|
| | | | | | | | |
EXPENSES | | |
| | |
| | |
| | |
|
Other Operation | | 26.0 |
| | 24.5 |
| | 61.7 |
| | 59.6 |
|
Maintenance | | 3.2 |
| | 2.8 |
| | 8.9 |
| | 7.6 |
|
Depreciation and Amortization | | 45.3 |
| | 34.9 |
| | 128.4 |
| | 97.5 |
|
Taxes Other Than Income Taxes | | 42.9 |
| | 35.2 |
| | 126.2 |
| | 102.9 |
|
TOTAL EXPENSES | | 117.4 |
| | 97.4 |
| | 325.2 |
| | 267.6 |
|
| | | | | | | | |
OPERATING INCOME | | 142.3 |
| | 97.0 |
| | 444.9 |
| | 318.6 |
|
| | | | | | | | |
Other Income (Expense): | | |
| | |
| | |
| | |
|
Interest Income | | 0.8 |
| | 0.5 |
| | 2.1 |
| | 1.3 |
|
Allowance for Equity Funds Used During Construction | | 21.0 |
| | 18.0 |
| | 61.1 |
| | 48.7 |
|
Interest Expense | | (26.4 | ) | | (19.8 | ) | | (69.5 | ) | | (60.7 | ) |
| | | | | | | | |
INCOME BEFORE INCOME TAX EXPENSE | | 137.7 |
| | 95.7 |
| | 438.6 |
| | 307.9 |
|
| | | | | | | | |
Income Tax Expense | | 30.1 |
| | 17.6 |
| | 90.7 |
| | 63.7 |
|
| | | | | | | | |
NET INCOME | | $ | 107.6 |
| | $ | 78.1 |
| | $ | 347.9 |
| | $ | 244.2 |
|
|
|
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 126.
|
AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER’S EQUITY
For the Nine Months Ended September 30, 20192020 and 20182019
(in millions)
(Unaudited)
| | | | | | | | | | | | | | | | | | | | |
| | Paid-in Capital | | Retained Earnings | | Total |
TOTAL MEMBER'S EQUITY – DECEMBER 31, 2018 | | $ | 2,480.6 | | | $ | 1,089.2 | | | $ | 3,569.8 | |
| | | | | | |
| | | | | | |
Net Income | | | | 104.3 | | | 104.3 | |
TOTAL MEMBER'S EQUITY – MARCH 31, 2019 | | 2,480.6 | | | 1,193.5 | | | 3,674.1 | |
| | | | | | |
| | | | | | |
Net Income | | | | 136.0 | | | 136.0 | |
TOTAL MEMBER'S EQUITY – JUNE 30, 2019 | | 2,480.6 | | | 1,329.5 | | | 3,810.1 | |
| | | | | | |
| | | | | | |
Net Income | | | | 107.6 | | | 107.6 | |
TOTAL MEMBER'S EQUITY – SEPTEMBER 30, 2019 | | $ | 2,480.6 | | | $ | 1,437.1 | | | $ | 3,917.7 | |
| | | | | | |
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 AEP Transmission Holdco | | | | (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 | |
| | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134. | | | | | | |
|
| | | | | | | | | | | | |
| | Paid-in Capital | | Retained Earnings | | Total |
TOTAL MEMBER'S EQUITY – DECEMBER 31, 2017 | | $ | 1,816.6 |
| | $ | 773.3 |
| | $ | 2,589.9 |
|
| | | | | | |
Capital Contribution from Member | | 65.0 |
| | | | 65.0 |
|
Net Income | | |
| | 84.1 |
| | 84.1 |
|
TOTAL MEMBER'S EQUITY – MARCH 31, 2018 | | 1,881.6 |
| | 857.4 |
| | 2,739.0 |
|
| | | | | | |
Capital Contributions from Member | | 312.0 |
| | | | 312.0 |
|
Net Income | | | | 82.0 |
| | 82.0 |
|
TOTAL MEMBER'S EQUITY – JUNE 30, 2018 | | 2,193.6 |
| | 939.4 |
| | 3,133.0 |
|
| | | | | | |
Capital Contribution from Member | | 205.0 |
| | | | 205.0 |
|
Net Income | | | | 78.1 |
| | 78.1 |
|
TOTAL MEMBER'S EQUITY – SEPTEMBER 30, 2018 | | $ | 2,398.6 |
| | $ | 1,017.5 |
| | $ | 3,416.1 |
|
| | | | | | |
TOTAL MEMBER'S EQUITY – DECEMBER 31, 2018 | | $ | 2,480.6 |
| | $ | 1,089.2 |
| | $ | 3,569.8 |
|
| | | | | | |
Net Income | | | | 104.3 |
| | 104.3 |
|
TOTAL MEMBER'S EQUITY – MARCH 31, 2019 | | 2,480.6 |
| | 1,193.5 |
| | 3,674.1 |
|
| | | | | | |
Net Income | | | | 136.0 |
| | 136.0 |
|
TOTAL MEMBER'S EQUITY – JUNE 30, 2019 | | 2,480.6 |
| | 1,329.5 |
| | 3,810.1 |
|
| | | | | | |
Net Income | | |
| | 107.6 |
| | 107.6 |
|
TOTAL MEMBER'S EQUITY – SEPTEMBER 30, 2019 | | $ | 2,480.6 |
| | $ | 1,437.1 |
| | $ | 3,917.7 |
|
|
|
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 126.
|
AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 20192020 and December 31, 20182019
(in millions)
(Unaudited)
| | | | | | | | | | | | | | |
| | September 30, | | December 31, |
| | 2020 | | 2019 |
CURRENT ASSETS | | | | |
Advances to Affiliates | | $ | 106.7 | | | $ | 85.4 | |
Accounts Receivable: | | | | |
Customers | | 34.1 | | | 19.0 | |
Affiliated Companies | | 81.1 | | | 66.1 | |
| | | | |
Total Accounts Receivable | | 115.2 | | | 85.1 | |
Materials and Supplies | | 13.6 | | | 13.8 | |
| | | | |
Prepayments and Other Current Assets | | 5.3 | | | 13.1 | |
TOTAL CURRENT ASSETS | | 240.8 | | | 197.4 | |
| | | | |
TRANSMISSION PROPERTY | | | | |
Transmission Property | | 8,947.4 | | | 8,137.9 | |
Other Property, Plant and Equipment | | 293.0 | | | 269.6 | |
Construction Work in Progress | | 1,680.9 | | | 1,485.7 | |
Total Transmission Property | | 10,921.3 | | | 9,893.2 | |
Accumulated Depreciation and Amortization | | 531.8 | | | 402.3 | |
TOTAL TRANSMISSION PROPERTY – NET | | 10,389.5 | | | 9,490.9 | |
| | | | |
OTHER NONCURRENT ASSETS | | | | |
| | | | |
Regulatory Assets | | 6.8 | | | 4.2 | |
Deferred Property Taxes | | 57.2 | | | 193.5 | |
Deferred Charges and Other Noncurrent Assets | | 4.4 | | | 4.8 | |
TOTAL OTHER NONCURRENT ASSETS | | 68.4 | | | 202.5 | |
| | | | |
TOTAL ASSETS | | $ | 10,698.7 | | | $ | 9,890.8 | |
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134. | | | | |
|
| | | | | | | | |
| | September 30, | | December 31, |
| | 2019 | | 2018 |
CURRENT ASSETS | | | | |
Advances to Affiliates | | $ | 275.2 |
| | $ | 96.9 |
|
Accounts Receivable: | | | | |
Customers | | 23.5 |
| | 11.8 |
|
Affiliated Companies | | 61.3 |
| | 61.0 |
|
Total Accounts Receivable | | 84.8 |
| | 72.8 |
|
Materials and Supplies | | 15.1 |
| | 19.0 |
|
Accrued Tax Benefits | | 9.7 |
| | 33.4 |
|
Prepayments and Other Current Assets | | 4.4 |
| | 3.4 |
|
TOTAL CURRENT ASSETS | | 389.2 |
| | 225.5 |
|
| | | | |
TRANSMISSION PROPERTY | | | | |
Transmission Property | | 7,181.8 |
| | 6,515.8 |
|
Other Property, Plant and Equipment | | 227.2 |
| | 174.0 |
|
Construction Work in Progress | | 1,858.4 |
| | 1,578.3 |
|
Total Transmission Property | | 9,267.4 |
| | 8,268.1 |
|
Accumulated Depreciation and Amortization | | 368.8 |
| | 271.9 |
|
TOTAL TRANSMISSION PROPERTY – NET | | 8,898.6 |
| | 7,996.2 |
|
| | | | |
OTHER NONCURRENT ASSETS | | | | |
Accounts Receivable – Affiliated Companies | | 4.8 |
| | — |
|
Regulatory Assets | | 7.3 |
| | 12.9 |
|
Deferred Property Taxes | | 47.2 |
| | 157.9 |
|
Deferred Charges and Other Noncurrent Assets | | 5.6 |
| | 1.6 |
|
TOTAL OTHER NONCURRENT ASSETS | | 64.9 |
| | 172.4 |
|
| | | | |
TOTAL ASSETS | | $ | 9,352.7 |
| | $ | 8,394.1 |
|
|
|
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 126.
|
AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND MEMBER’S EQUITY
September 30, 20192020 and December 31, 20182019
(in millions)
(Unaudited)
| | | | | | | | | | | | | | |
| | September 30, | | December 31, |
| | 2020 | | 2019 |
CURRENT LIABILITIES | | | | |
Advances from Affiliates | | $ | 86.8 | | | $ | 137.0 | |
Accounts Payable: | | | | |
General | | 337.7 | | | 493.4 | |
Affiliated Companies | | 62.4 | | | 71.2 | |
| | | | |
Accrued Taxes | | 216.6 | | | 355.6 | |
Accrued Interest | | 48.2 | | | 19.2 | |
Obligations Under Operating Leases | | 2.3 | | | 2.1 | |
Other Current Liabilities | | 9.1 | | | 14.6 | |
TOTAL CURRENT LIABILITIES | | 763.1 | | | 1,093.1 | |
| | | | |
NONCURRENT LIABILITIES | | | | |
Long-term Debt – Nonaffiliated | | 3,947.9 | | | 3,427.3 | |
Deferred Income Taxes | | 892.6 | | | 817.8 | |
Regulatory Liabilities | | 575.2 | | | 540.9 | |
Obligations Under Operating Leases | | 1.4 | | | 1.9 | |
Deferred Credits and Other Noncurrent Liabilities | | 19.9 | | | 0.3 | |
TOTAL NONCURRENT LIABILITIES | | 5,437.0 | | | 4,788.2 | |
| | | | |
TOTAL LIABILITIES | | 6,200.1 | | | 5,881.3 | |
| | | | |
Rate Matters (Note 4) | | | | |
Commitments and Contingencies (Note 5) | | | | |
| | | | |
MEMBER’S EQUITY | | | | |
Paid-in Capital | | 2,665.6 | | | 2,480.6 | |
Retained Earnings | | 1,833.0 | | | 1,528.9 | |
TOTAL MEMBER’S EQUITY | | 4,498.6 | | | 4,009.5 | |
| | | | |
TOTAL LIABILITIES AND MEMBER’S EQUITY | | $ | 10,698.7 | | | $ | 9,890.8 | |
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134. | | | | |
|
| | | | | | | | |
| | September 30, | | December 31, |
| | 2019 | | 2018 |
CURRENT LIABILITIES | | | | |
Advances from Affiliates | | $ | 9.1 |
| | $ | 45.4 |
|
Accounts Payable: | | | | |
General | | 319.1 |
| | 347.2 |
|
Affiliated Companies | | 57.1 |
| | 56.0 |
|
Long-term Debt Due Within One Year – Nonaffiliated | | 85.0 |
| | 85.0 |
|
Accrued Taxes | | 172.4 |
| | 288.9 |
|
Accrued Interest | | 39.7 |
| | 15.9 |
|
Obligations Under Operating Leases | | 2.3 |
| | — |
|
Other Current Liabilities | | 25.5 |
| | 3.8 |
|
TOTAL CURRENT LIABILITIES | | 710.2 |
| | 842.2 |
|
| | | | |
NONCURRENT LIABILITIES | | | | |
Long-term Debt – Nonaffiliated | | 3,426.9 |
| | 2,738.0 |
|
Deferred Income Taxes | | 751.4 |
| | 704.4 |
|
Regulatory Liabilities | | 541.2 |
| | 521.3 |
|
Obligations Under Operating Leases | | 2.2 |
| | — |
|
Deferred Credits and Other Noncurrent Liabilities | | 3.1 |
| | 18.4 |
|
TOTAL NONCURRENT LIABILITIES | | 4,724.8 |
| | 3,982.1 |
|
| | | | |
TOTAL LIABILITIES | | 5,435.0 |
| | 4,824.3 |
|
| | | | |
Rate Matters (Note 4) | |
| |
|
Commitments and Contingencies (Note 5) | |
| |
|
| | | | |
MEMBER’S EQUITY | | | | |
Paid-in Capital | | 2,480.6 |
| | 2,480.6 |
|
Retained Earnings | | 1,437.1 |
| | 1,089.2 |
|
TOTAL MEMBER’S EQUITY | | 3,917.7 |
| | 3,569.8 |
|
| | | | |
TOTAL LIABILITIES AND MEMBER’S EQUITY | | $ | 9,352.7 |
| | $ | 8,394.1 |
|
|
|
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 126.
|
AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 20192020 and 20182019
(in millions)
(Unaudited)
| | | | | | | | | | | | | | |
| | Nine Months Ended September 30, | | |
| | 2020 | | 2019 |
OPERATING ACTIVITIES | | | | |
Net Income | | $ | 309.1 | | | $ | 347.9 | |
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | | | |
Depreciation and Amortization | | 176.4 | | | 128.4 | |
Deferred Income Taxes | | 65.4 | | | 36.7 | |
Allowance for Equity Funds Used During Construction | | (54.9) | | | (61.1) | |
Property Taxes | | 136.3 | | | 110.7 | |
| | | | |
Change in Other Noncurrent Assets | | (1.5) | | | 1.0 | |
Change in Other Noncurrent Liabilities | | 19.5 | | | (3.8) | |
Changes in Certain Components of Working Capital: | | | | |
Accounts Receivable, Net | | (30.1) | | | (5.1) | |
Materials and Supplies | | 0.2 | | | 3.9 | |
Accounts Payable | | 26.0 | | | 4.1 | |
Accrued Taxes, Net | | (139.0) | | | (92.8) | |
Accrued Interest | | 29.0 | | | 23.8 | |
Other Current Assets | | 9.1 | | | (1.0) | |
Other Current Liabilities | | (10.7) | | | (8.5) | |
Net Cash Flows from Operating Activities | | 534.8 | | | 484.2 | |
| | | | |
INVESTING ACTIVITIES | | | | |
Construction Expenditures | | (1,163.8) | | | (959.9) | |
Change in Advances to Affiliates, Net | | (21.3) | | | (178.3) | |
Acquisitions of Assets | | (3.6) | | | (7.6) | |
| | | | |
Other Investing Activities | | 4.7 | | | 12.0 | |
Net Cash Flows Used for Investing Activities | | (1,184.0) | | | (1,133.8) | |
| | | | |
FINANCING ACTIVITIES | | | | |
Capital Contributions from Member | | 185.0 | | | 0 | |
Issuance of Long-term Debt – Nonaffiliated | | 519.4 | | | 685.9 | |
Change in Advances from Affiliates, Net | | (50.2) | | | (36.3) | |
Dividends Paid to AEP Transmission Holdco | | (5.0) | | | 0 | |
| | | | |
Net Cash Flows from Financing Activities | | 649.2 | | | 649.6 | |
| | | | |
Net Change in Cash and Cash Equivalents | | 0 | | | 0 | |
Cash and Cash Equivalents at Beginning of Period | | 0 | | | 0 | |
Cash and Cash Equivalents at End of Period | | $ | 0 | | | $ | 0 | |
| | | | |
SUPPLEMENTARY INFORMATION | | | | |
Cash Paid for Interest, Net of Capitalized Amounts | | $ | 63.3 | | | $ | 43.0 | |
Net Cash Paid for Income Taxes | | 1.9 | | | 29.8 | |
Construction Expenditures Included in Current Liabilities as of September 30, | | 283.6 | | | 315.1 | |
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134. | | | | |
|
| | | | | | | | |
| | Nine Months Ended September 30, |
| | 2019 | | 2018 |
OPERATING ACTIVITIES | | | | |
Net Income | | $ | 347.9 |
| | $ | 244.2 |
|
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | | | |
Depreciation and Amortization | | 128.4 |
| | 97.5 |
|
Deferred Income Taxes | | 36.7 |
| | 76.3 |
|
Allowance for Equity Funds Used During Construction | | (61.1 | ) | | (48.7 | ) |
Property Taxes | | 110.7 |
| | 86.9 |
|
Long-term Accounts Receivable – Affiliated | | (4.8 | ) | | (3.1 | ) |
Change in Other Noncurrent Assets | | 5.8 |
| | 12.7 |
|
Change in Other Noncurrent Liabilities | | (3.8 | ) | | 18.0 |
|
Changes in Certain Components of Working Capital: | | | | |
|
Accounts Receivable, Net | | (5.1 | ) | | 23.5 |
|
Materials and Supplies | | 3.9 |
| | (2.8 | ) |
Accounts Payable | | 4.1 |
| | 3.3 |
|
Accrued Taxes, Net | | (92.8 | ) | | (73.2 | ) |
Accrued Interest | | 23.8 |
| | 20.9 |
|
Other Current Assets | | (1.0 | ) | | (0.5 | ) |
Other Current Liabilities | | (8.5 | ) | | (28.0 | ) |
Net Cash Flows from Operating Activities | | 484.2 |
| | 427.0 |
|
| | | | |
INVESTING ACTIVITIES | | |
| | |
|
Construction Expenditures | | (959.9 | ) | | (1,171.8 | ) |
Change in Advances to Affiliates, Net | | (178.3 | ) | | (131.7 | ) |
Acquisitions of Assets | | (7.6 | ) | | (13.2 | ) |
Other Investing Activities | | 12.0 |
| | 1.2 |
|
Net Cash Flows Used for Investing Activities | | (1,133.8 | ) | | (1,315.5 | ) |
| | | | |
FINANCING ACTIVITIES | | | | |
|
Capital Contributions from Member | | — |
| | 582.0 |
|
Issuance of Long-term Debt – Nonaffiliated | | 685.9 |
| | 321.1 |
|
Change in Advances from Affiliates, Net | | (36.3 | ) | | (14.6 | ) |
Net Cash Flows from Financing Activities | | 649.6 |
| | 888.5 |
|
| | | | |
Net Change in Cash and Cash Equivalents | | — |
| | — |
|
Cash and Cash Equivalents at Beginning of Period | | — |
| | — |
|
Cash and Cash Equivalents at End of Period | | $ | — |
| | $ | — |
|
| | | | |
SUPPLEMENTARY INFORMATION | | |
| | |
|
Cash Paid for Interest, Net of Capitalized Amounts | | $ | 43.0 |
| | $ | 38.4 |
|
Net Cash Paid (Received) for Income Taxes | | 29.8 |
| | (32.1 | ) |
Construction Expenditures Included in Current Liabilities as of September 30, | | 315.1 |
| | 237.0 |
|
|
|
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page
126. |
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 | | |
| September 30, | | | | September 30, | | |
| 2020 | | 2019 | | 2020 | | 2019 |
| (in millions of KWhs) | | | | | | |
Retail: | | | | | | | |
Residential | 2,772 | | | 2,728 | | | 8,229 | | | 8,401 | |
Commercial | 1,612 | | | 1,721 | | | 4,410 | | | 4,812 | |
Industrial | 2,193 | | | 2,487 | | | 6,507 | | | 7,180 | |
Miscellaneous | 203 | | | 216 | | | 585 | | | 640 | |
Total Retail | 6,780 | | | 7,152 | | | 19,731 | | | 21,033 | |
| | | | | | | |
Wholesale | 1,187 | | | 938 | | | 2,894 | | | 2,667 | |
| | | | | | | |
Total KWhs | 7,967 | | | 8,090 | | | 22,625 | | | 23,700 | |
|
| | | | | | | | | | | |
| Three Months Ended | | Nine Months Ended |
| September 30, | | September 30, |
| 2019 | | 2018 | | 2019 | | 2018 |
| (in millions of KWhs) |
Retail: | |
| | |
| | |
| | |
|
Residential | 2,728 |
| | 2,662 |
| | 8,401 |
| | 8,895 |
|
Commercial | 1,721 |
| | 1,715 |
| | 4,812 |
| | 4,980 |
|
Industrial | 2,487 |
| | 2,433 |
| | 7,180 |
| | 7,181 |
|
Miscellaneous | 216 |
| | 215 |
| | 640 |
| | 644 |
|
Total Retail (a) | 7,152 |
| | 7,025 |
| | 21,033 |
| | 21,700 |
|
| | | | | | | |
Wholesale | 938 |
| | 1,143 |
| | 2,667 |
| | 2,252 |
|
| | | | | | | |
Total KWhs | 8,090 |
| | 8,168 |
| | 23,700 |
| | 23,952 |
|
| |
(a) | 2018 KWhs have been revised to reflect the reclassification of certain customer accounts between Retail classes. This reclassification did not impact previously reported Total Retail KWhs. Management concluded that these prior period disclosure only errors were immaterial individually and in the aggregate. |
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 | | |
| September 30, | | | | September 30, | | |
| 2020 | | 2019 | | 2020 | | 2019 |
| (in degree days) | | | | | | |
Actual – Heating (a) | 1 | | | — | | | 1,098 | | | 1,295 | |
Normal – Heating (b) | 2 | | | 3 | | | 1,413 | | | 1,407 | |
| | | | | | | |
Actual – Cooling (c) | 988 | | | 1,071 | | | 1,354 | | | 1,530 | |
Normal – Cooling (b) | 825 | | | 815 | | | 1,208 | | | 1,194 | |
(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.
|
| | | | | | | | | | | |
| Three Months Ended | | Nine Months Ended |
| September 30, | | September 30, |
| 2019 | | 2018 | | 2019 | | 2018 |
| (in degree days) |
Actual – Heating (a) | — |
| | — |
| | 1,295 |
| | 1,518 |
|
Normal – Heating (b) | 3 |
| | 2 |
| | 1,407 |
| | 1,410 |
|
| | | | | | | |
Actual – Cooling (c) | 1,071 |
| | 950 |
| | 1,530 |
| | 1,495 |
|
Normal – Cooling (b) | 815 |
| | 814 |
| | 1,194 |
| | 1,184 |
|
| |
(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 20192020 Compared to Third Quarter of 20182019
| | | | | | | | |
Reconciliation of Third Quarter of 2019 to Third Quarter of 2020 | | |
Net Income | | |
(in millions) | | |
| | |
Third Quarter of 2019 | | $ | 104.3 | |
| | |
Changes in Gross Margin: | | |
Retail Margins | | 7.9 | |
Margins from Off-system Sales | | (1.2) | |
Transmission Revenues | | (3.1) | |
Other Revenues | | (1.3) | |
Total Change in Gross Margin | | 2.3 | |
| | |
Changes in Expenses and Other: | | |
Other Operation and Maintenance | | 13.6 | |
Depreciation and Amortization | | (4.5) | |
Taxes Other Than Income Taxes | | (2.1) | |
Interest Income | | 0.3 | |
| | |
Allowance for Equity Funds Used During Construction | | 1.9 | |
Non-Service Cost Components of Net Periodic Benefit Cost | | 0.4 | |
Interest Expense | | (3.4) | |
Total Change in Expenses and Other | | 6.2 | |
| | |
Income Tax Expense (Benefit) | | 3.8 | |
| | |
Third Quarter of 2020 | | $ | 116.6 | |
|
| | | | |
Reconciliation of Third Quarter of 2018 to Third Quarter of 2019 |
Net Income |
(in millions) |
|
Third Quarter of 2018 | | $ | 87.1 |
|
| | |
|
Changes in Gross Margin: | | |
|
Retail Margins | | 68.2 |
|
Transmission Revenues | | 12.8 |
|
Other Revenues | | 0.7 |
|
Total Change in Gross Margin | | 81.7 |
|
| | |
|
Changes in Expenses and Other: | | |
|
Other Operation and Maintenance | | 27.2 |
|
Depreciation and Amortization | | (13.0 | ) |
Taxes Other Than Income Taxes | | (3.1 | ) |
Interest Income | | (0.1 | ) |
Carrying Costs Income | | (0.2 | ) |
Allowance for Equity Funds Used During Construction | | 0.7 |
|
Non-Service Cost Components of Net Periodic Benefit Cost | | (0.2 | ) |
Interest Expense | | (0.8 | ) |
Total Change in Expenses and Other | | 10.5 |
|
| | |
|
Income Tax Expense (Benefit) | | (75.0 | ) |
| | |
|
Third Quarter of 2019 | | $ | 104.3 |
|
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 $68•Retail Margins increased $8 million primarily due to the following: |
A $78 million increase due to a 2018 reduction in the deferred fuel under recovery balance as a result of the 2018 West Virginia Tax Reform settlement. This increase was offset in Income Tax Expense (Benefit) below.following:
A $15•An $8 million increase in deferred fuel relatedprimarily due to the timing of recoverable PJM expenses that were offset below.
An $11 million increase in weather-related usage primarily driven by a 13% increase in cooling degree days.
A $10 million increase due to 2018 Virginia legislation which increased non-recoverable fuel expense in the prior year.
An $8 million increase due to revenue primarily from rate riders in West Virginia.expenses. This increase was offset in other expense items below.
•A $6 million increase due to a base ratedecrease in customer refunds related to Tax Reform. This increase was partially offset in West Virginia implemented in March 2019.Income Tax Expense below.
•A $4 million increase due to the WVPSC approval of the Mitchell Plant surcharge effective January 2020.
These increases were partially offset by:
A $56•An $8 million decrease due to customer refunds related to Tax Reform. Thisin weather-related usage primarily driven by an 8% decrease was partially offset in Income Tax Expense (Benefit) below.cooling degree days.
•A $3 million decrease in weather-normalized margins occurring across all retail classes.
| |
• | Transmission Revenues primarily in the commercial and industrial classes, partially offset in the residential class.increased $13 million primarily due to 2018 provisions for refunds.
|
•Transmission Revenue decreased $3 million primarily due to an adjustment in July 2019 to the annual transmission formula rate true-up.
Expenses and Other and Income Tax Expense (Benefit) changed between years as follows:
| |
• | Other Operation and Maintenance expenses decreased $27•Other Operation and Maintenance expenses decreased $14 million primarily due to the following: |
A $39 million decrease due to the extinguishment of certain regulatory asset balances as agreedfollowing:
•A $6 million decrease in distribution expense primarily due to withinstorm and vegetation management expenses.
•A $3 million decrease in PJM expenses primarily related to the 2018 West Virginia Tax Reform settlement.annual transmission formula rate true-up.
•A $4$3 million decrease in maintenance expense at various generation plants.
•A $2 million decrease in uncollectible accounts expenses.
These decreases were partially offset by:
An $11•A $4 million increase in recoverable PJM transmissionemployee-related expenses.
•Depreciation and Amortization expenses increased $5 million primarily due to a higher depreciable base.
•Interest Expense increased $3 million primarily due to higher long-term debt balances.
•Income Tax Expense (Benefit) decreased $4 million primarily due the recognition of a discrete tax adjustment, which werewas primarily attributable to the filing of the 2019 Federal Income Tax return in the third quarter of 2020, and an increase in parent company loss benefit, partially offset withinby a decrease in amortization of Excess ADIT. The decrease in amortization of Excess ADIT is partially offset above in Gross Margins above.Margin and Other Operation and Maintenance expenses.
A $9 million increase in PJM expenses related to the annual formula rate true-up.
| |
• | Depreciation and Amortization expenses increased $13 million primarily due to a higher depreciable base and an increase in West Virginia depreciation rates beginning in March 2019.
|
| |
• | Taxes Other Than Income Taxes increased $3 million primarily due to an increase in West Virginia business and occupational taxes.
|
| |
• | Income Tax Expense (Benefit) increased $75 million primarily due to a one-time recognition of increased amortization of Excess ADIT not subject to normalization requirements as a result of the 2018 West Virginia Tax Reform settlement. This increase was partially offset in Gross Margin and Other Operation and Maintenance expenses above.
|
Nine Months Ended September 30, 20192020 Compared to Nine Months Ended September 30, 20182019
| | | | | | | | |
Reconciliation of Nine Months Ended September 30, 2019 to Nine Months Ended September 30, 2020 | | |
Net Income | | |
(in millions) | | |
| | |
Nine Months Ended September 30, 2019 | | $ | 293.5 | |
| | |
Changes in Gross Margin: | | |
Retail Margins | | 35.7 | |
Margins from Off-system Sales | | (3.2) | |
Transmission Revenues | | (8.9) | |
Other Revenues | | (1.3) | |
Total Change in Gross Margin | | 22.3 | |
| | |
Changes in Expenses and Other: | | |
Other Operation and Maintenance | | 72.7 | |
Depreciation and Amortization | | (17.7) | |
Taxes Other Than Income Taxes | | (5.7) | |
Interest Income | | (0.7) | |
| | |
Allowance for Equity Funds Used During Construction | | (1.0) | |
Non-Service Cost Components of Net Periodic Benefit Cost | | 1.3 | |
Interest Expense | | (9.7) | |
Total Change in Expenses and Other | | 39.2 | |
| | |
Income Tax Expense (Benefit) | | (41.8) | |
| | |
Nine Months Ended September 30, 2020 | | $ | 313.2 | |
|
| | | | |
Reconciliation of Nine Months Ended September 30, 2018 to Nine Months Ended September 30, 2019 |
Net Income |
(in millions) |
|
Nine Months Ended September 30, 2018 | | $ | 290.0 |
|
| | |
Changes in Gross Margin: | | |
|
Retail Margins | | (11.0 | ) |
Margins from Off-system Sales | | 2.0 |
|
Transmission Revenues | | 25.9 |
|
Other Revenues | | 1.1 |
|
Total Change in Gross Margin | | 18.0 |
|
| | |
|
Changes in Expenses and Other: | | |
|
Other Operation and Maintenance | | 14.4 |
|
Depreciation and Amortization | | (28.8 | ) |
Taxes Other Than Income Taxes | | (7.4 | ) |
Interest Income | | 0.8 |
|
Carrying Costs Income | | (1.2 | ) |
Allowance for Equity Funds Used During Construction | | 2.9 |
|
Non-Service Cost Components of Net Periodic Benefit Cost | | (0.6 | ) |
Interest Expense | | (6.5 | ) |
Total Change in Expenses and Other | | (26.4 | ) |
| | |
|
Income Tax Expense (Benefit) | | 11.9 |
|
| | |
|
Nine Months Ended September 30, 2019 | | $ | 293.5 |
|
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 decreased $11•Retail Margins increased $36 million primarily due to the following: |
A $91 million decrease due to the following:
•A $30 million increase due to a decrease in customer refunds related to Tax Reform. This decreaseincrease was partially offset in Income Tax Expense (Benefit) below.
•A $23$28 million decreaseincrease in weather-normalized margins occurring across all retail classes.deferred fuel primarily due to the timing of recoverable PJM expenses offset in line items below.
•A $22$12 million increase due to the WVPSC approval of the Mitchell Plant surcharge effective January 2020. Pursuant to the WVPSC approval of the surcharge, this increase was partially offset by the amortization of Excess ADIT not subject to normalization requirements in Income Tax Expense below.
•A $12 million increase due to the impact of the 2019 WVPSC order which required APCo to offset Excess ADIT not subject to normalization requirements against the deferred fuel under-recovery balance in 2019.
•An $11 million increase due to a base rate increase in West Virginia.
These increases were partially offset by:
•A $41 million decrease in weather-related usage primarily driven by a 15% decrease in heating degree days partially offset byand a 2% increase12% decrease in cooling degree days.
These decreases were•A $16 million decrease in weather-normalized margins primarily in the commercial and industrial classes, partially offset in the residential class.
•Margins from Off-system Sales decreased $3 million due to weaker market prices for energy in the RTOs which caused a decrease in sales volume and margins.
•Transmission Revenues decreased $9 million primarily due to the following:
•A $13 million decrease from the annual transmission formula rate true-up.
This decrease was partially offset by:
•A $78$4 million increase due to a 2018 reductionfrom investment in the deferred fuel under recovery balance as a result of the 2018 West Virginia Tax Reform settlement. This increase was offset in Income Tax Expense (Benefit) below.transmission assets.
A $14 million increase primarily due to revenue from rate riders in West Virginia. This increase was offset in other expense items below.
A $12 million increase due to base rate increases in West Virginia implemented in March 2019.
A $12 million increase in deferred fuel related to recoverable PJM expenses that were offset below.
A $10 million increase due to 2018 Virginia legislation which increased non-recoverable fuel expense at APCo in the prior year.
| |
• | Transmission Revenues increased $26 million primarily due to 2018 provisions for refunds.
|
Expenses and Other and Income Tax Expense (Benefit) changed between years as follows:
| |
• | Other Operation and Maintenance expenses decreased $14•Other Operation and Maintenance expenses decreased $73 million primarily due to the following: |
A $39 million decrease due to the extinguishment of certain regulatory asset balances as agreed to within the 2018 West Virginia Tax Reform settlement.following:
•A $10$17 million decrease in expense duetransmission expenses primarily related to lower current year amortization of certain regulatory assets that were extinguished in August 2018 as agreed to within the 2018 West Virginia Tax Reform settlement.annual transmission formula rate true-up.
An $8•A $20 million decrease in maintenance expense at various generation plants.
•A $5$14 million decrease in vegetation management expenses.
A $5 million decrease in storm-related expenses.
A $5 million decrease in estimated expenses for claims related to asbestos exposure.
These decreases were partially offset by:
A $42 million increase in PJM expenses primarily related to the annual formula rate true-up.
A $13 million increase due to 2019as a result of prior year contributions to benefit low income West Virginia residential customers as a result of the 2018 West Virginia Tax Reform settlement. This increasedecrease was offset in Income Tax Expense (Benefit) below.
•A $5$10 million decrease in distribution expense primarily due to storm and vegetation management expenses.
•An $8 million decrease in employee-related expenses.
•Depreciation and Amortization expenses increased $18 million primarily due to a higher depreciable base and an increase in West Virginia depreciation rates beginning in March 2019. This increase was partially offset in Retail Margins above.
•Taxes Other Than Income Taxes increased $6 million primarily due to the following:
•A $3 million increase in employee-relatedproperty taxes due to additional investments in utility plant.
•A $3 million increase in state business and occupation taxes due to the reduction of the revitalization tax credit.
•Interest Expense increased $10 million primarily due to higher long-term debt balances.
•Income Tax Expense (Benefit) increased $42 million primarily due to a decrease in amortization of Excess ADIT. The decrease in amortization of Excess ADIT is partially offset above in Gross Margin and Other Operation and Maintenance expenses.
| |
• |
Depreciation and Amortization expenses increased $29 million primarily due to a higher depreciable base and an increase in West Virginia depreciation rates beginning in March 2019.
|
| |
• | Taxes Other Than Income Taxes increased $7 million primarily due to an increase in West Virginia business and occupational taxes.
|
| |
• | Interest Expense increased $7 million primarily due to higher long-term debt balances.
|
| |
• | Income Tax Expense (Benefit) decreased $12 million primarily due to an increase in amortization of Excess ADIT not subject to normalization requirements and a decrease in pretax book income. This benefit was partially offset by the one-time recognition of increased amortization of Excess ADIT not subject to normalization requirements as a result of the 2018 West Virginia Tax Reform settlement. This decrease was partially offset in Gross Margin and Other Operation and Maintenance expenses above.
|
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 20192020 and 20182019
(in millions)
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | | | Nine Months Ended | | |
| | September 30, | | | | September 30, | | |
| | 2020 | | 2019 | | 2020 | | 2019 |
REVENUES | | | | | | | | |
Electric Generation, Transmission and Distribution | | $ | 688.9 | | | $ | 696.7 | | | $ | 1,989.9 | | | $ | 2,041.3 | |
Sales to AEP Affiliates | | 44.4 | | | 56.6 | | | 124.9 | | | 154.6 | |
Other Revenues | | 2.4 | | | 2.2 | | | 7.8 | | | 8.2 | |
TOTAL REVENUES | | 735.7 | | | 755.5 | | | 2,122.6 | | | 2,204.1 | |
| | | | | | | | |
EXPENSES | | | | | | | | |
Fuel and Other Consumables Used for Electric Generation | | 166.0 | | | 177.3 | | | 430.9 | | | 521.8 | |
Purchased Electricity for Resale | | 67.5 | | | 78.3 | | | 240.5 | | | 253.4 | |
| | | | | | | | |
| | | | | | | | |
Other Operation | | 136.3 | | | 140.4 | | | 379.1 | | | 416.2 | |
Maintenance | | 52.0 | | | 61.5 | | | 148.7 | | | 184.3 | |
Depreciation and Amortization | | 123.2 | | | 118.7 | | | 366.0 | | | 348.3 | |
Taxes Other Than Income Taxes | | 38.8 | | | 36.7 | | | 114.2 | | | 108.5 | |
TOTAL EXPENSES | | 583.8 | | | 612.9 | | | 1,679.4 | | | 1,832.5 | |
| | | | | | | | |
OPERATING INCOME | | 151.9 | | | 142.6 | | | 443.2 | | | 371.6 | |
| | | | | | | | |
Other Income (Expense): | | | | | | | | |
Interest Income | | 0.6 | | | 0.3 | | | 1.4 | | | 2.1 | |
| | | | | | | | |
Allowance for Equity Funds Used During Construction | | 6.7 | | | 4.8 | | | 11.5 | | | 12.5 | |
Non-Service Cost Components of Net Periodic Benefit Cost | | 4.7 | | | 4.3 | | | 14.1 | | | 12.8 | |
Interest Expense | | (55.0) | | | (51.6) | | | (162.2) | | | (152.5) | |
| | | | | | | | |
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) | | 108.9 | | | 100.4 | | | 308.0 | | | 246.5 | |
| | | | | | | | |
Income Tax Expense (Benefit) | | (7.7) | | | (3.9) | | | (5.2) | | | (47.0) | |
| | | | | | | | |
NET INCOME | | $ | 116.6 | | | $ | 104.3 | | | $ | 313.2 | | | $ | 293.5 | |
| | | | | | | | |
The common stock of APCo is wholly-owned by Parent. | | | | | | | | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134. | | | | | | | | |
|
| | | | | | | | | | | | | | | | |
| | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, |
| | 2019 | | 2018 | | 2019 | | 2018 |
REVENUES | | | | | | | | |
|
Electric Generation, Transmission and Distribution | | $ | 696.7 |
| | $ | 716.8 |
| | $ | 2,041.3 |
| | $ | 2,103.1 |
|
Sales to AEP Affiliates | | 56.6 |
| | 42.9 |
| | 154.6 |
| | 138.7 |
|
Other Revenues | | 2.2 |
| | 2.3 |
| | 8.2 |
| | 7.6 |
|
TOTAL REVENUES | | 755.5 |
| | 762.0 |
| | 2,204.1 |
| | 2,249.4 |
|
| | | | | | | | |
EXPENSES | | |
| | |
| | |
| | |
|
Fuel and Other Consumables Used for Electric Generation | | 177.3 |
| | 263.4 |
| | 521.8 |
| | 487.7 |
|
Purchased Electricity for Resale | | 78.3 |
| | 80.4 |
| | 253.4 |
| | 350.8 |
|
Other Operation | | 140.4 |
| | 131.9 |
| | 416.2 |
| | 380.0 |
|
Maintenance | | 61.5 |
| | 97.2 |
| | 184.3 |
| | 234.9 |
|
Depreciation and Amortization | | 118.7 |
| | 105.7 |
| | 348.3 |
| | 319.5 |
|
Taxes Other Than Income Taxes | | 36.7 |
| | 33.6 |
| | 108.5 |
| | 101.1 |
|
TOTAL EXPENSES | | 612.9 |
| | 712.2 |
| | 1,832.5 |
| | 1,874.0 |
|
| | | | | | | | |
OPERATING INCOME | | 142.6 |
| | 49.8 |
| | 371.6 |
| | 375.4 |
|
| | | | | | | | |
Other Income (Expense): | | |
| | |
| | |
| | |
|
Interest Income | | 0.3 |
| | 0.4 |
| | 2.1 |
| | 1.3 |
|
Carrying Costs Income | | — |
| | 0.2 |
| | — |
| | 1.2 |
|
Allowance for Equity Funds Used During Construction | | 4.8 |
| | 4.1 |
| | 12.5 |
| | 9.6 |
|
Non-Service Cost Components of Net Periodic Benefit Cost | | 4.3 |
| | 4.5 |
| | 12.8 |
| | 13.4 |
|
Interest Expense | | (51.6 | ) | | (50.8 | ) | | (152.5 | ) | | (146.0 | ) |
| | | | | | | | |
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) | | 100.4 |
| | 8.2 |
| | 246.5 |
| | 254.9 |
|
| | | | | | | | |
Income Tax Expense (Benefit) | | (3.9 | ) | | (78.9 | ) | | (47.0 | ) | | (35.1 | ) |
| | | | | | | | |
NET INCOME | | $ | 104.3 |
| | $ | 87.1 |
| | $ | 293.5 |
| | $ | 290.0 |
|
|
| | | | |
The common stock of APCo is wholly-owned by Parent. | |
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 126.
|
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 20192020 and 20182019
(in millions)
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | | | Nine Months Ended | | |
| | September 30, | | | | September 30, | | |
| | 2020 | | 2019 | | 2020 | | 2019 |
Net Income | | $ | 116.6 | | | $ | 104.3 | | | $ | 313.2 | | | $ | 293.5 | |
| | | | | | | | |
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, 2020 and 2019, Respectively, and $(1.2) and $(0.2) for the Nine Months Ended September 30, 2020 and 2019, Respectively | | 0.6 | | | (0.3) | | | (4.4) | | | (0.7) | |
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.3) and $(0.2) for the Three Months Ended September 30, 2020 and 2019, Respectively, and $(0.8) and $(0.5) for the Nine Months Ended September 30, 2020 and 2019, Respectively | | (0.9) | | | (0.6) | | | (2.8) | | | (1.9) | |
| | | | | | | | |
TOTAL OTHER COMPREHENSIVE LOSS | | (0.3) | | | (0.9) | | | (7.2) | | | (2.6) | |
| | | | | | | | |
TOTAL COMPREHENSIVE INCOME | | $ | 116.3 | | | $ | 103.4 | | | $ | 306.0 | | | $ | 290.9 | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134. | | | | | | | | |
|
| | | | | | | | | | | | | | | | |
| | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, |
| | 2019 | | 2018 | | 2019 | | 2018 |
Net Income | | $ | 104.3 |
| | $ | 87.1 |
| | $ | 293.5 |
| | $ | 290.0 |
|
| | | | | | | | |
OTHER COMPREHENSIVE LOSS, NET OF TAXES | | |
| | | | | | |
|
Cash Flow Hedges, Net of Tax of $(0.1) and $(0.1) for the Three Months Ended September 30, 2019 and 2018, Respectively, and $(0.2) and $(0.2) for the Nine Months Ended September 30, 2019 and 2018, Respectively | | (0.3 | ) | | (0.3 | ) | | (0.7 | ) | | (0.7 | ) |
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.2) and $(0.2) for the Three Months Ended September 30, 2019 and 2018, Respectively, and $(0.5) and $(0.6) for the Nine Months Ended September 30, 2019 and 2018, Respectively | | (0.6 | ) | | (0.7 | ) | | (1.9 | ) | | (2.3 | ) |
| | | | | | | | |
TOTAL OTHER COMPREHENSIVE LOSS | | (0.9 | ) | | (1.0 | ) | | (2.6 | ) | | (3.0 | ) |
| | | | | | | | |
TOTAL COMPREHENSIVE INCOME | | $ | 103.4 |
| | $ | 86.1 |
| | $ | 290.9 |
| | $ | 287.0 |
|
|
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 126.
|
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Nine Months Ended September 30, 20192020 and 20182019
(in millions)
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Common Stock | | Paid-in Capital | | Retained Earnings | | Accumulated Other Comprehensive Income (Loss) | | Total |
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2018 | | $ | 260.4 | | | $ | 1,828.7 | | | $ | 1,922.0 | | | $ | (5.0) | | | $ | 4,006.1 | |
| | | | | | | | | | |
Common Stock Dividends | | | | | | (50.0) | | | | | (50.0) | |
| | | | | | | | | | |
Net Income | | | | | | 133.7 | | | | | 133.7 | |
Other Comprehensive Loss | | | | | | | | (0.8) | | | (0.8) | |
TOTAL COMMON SHAREHOLDER’S EQUITY - MARCH 31, 2019 | | 260.4 | | | 1,828.7 | | | 2,005.7 | | | (5.8) | | | 4,089.0 | |
| | | | | | | | | | |
Common Stock Dividends | | | | | | (50.0) | | | | | (50.0) | |
Net Income | | | | | | 55.5 | | | | | 55.5 | |
Other Comprehensive Loss | | | | | | | | (0.9) | | | (0.9) | |
TOTAL COMMON SHAREHOLDER’S EQUITY - JUNE 30, 2019 | | 260.4 | | | 1,828.7 | | | 2,011.2 | | | (6.7) | | | 4,093.6 | |
| | | | | | | | | | |
Common Stock Dividends | | | | | | (25.0) | | | | | (25.0) | |
Net Income | | | | | | 104.3 | | | | | 104.3 | |
Other Comprehensive Loss | | | | | | | | (0.9) | | | (0.9) | |
TOTAL COMMON SHAREHOLDER’S EQUITY - SEPTEMBER 30, 2019 | | $ | 260.4 | | | $ | 1,828.7 | | | $ | 2,090.5 | | | $ | (7.6) | | | $ | 4,172.0 | |
| | | | | | | | | | |
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 | |
| | | | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134. | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | |
| | Common Stock | | Paid-in Capital | | Retained Earnings | | Accumulated Other Comprehensive Income (Loss) | | Total |
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2017 | | $ | 260.4 |
| | $ | 1,828.7 |
| | $ | 1,714.1 |
| | $ | 1.3 |
| | $ | 3,804.5 |
|
| | | | | | | | | | |
Common Stock Dividends | | | | | | (40.0 | ) | | | | (40.0 | ) |
ASU 2018-02 Adoption | | | | | | 0.1 |
| | 0.3 |
| | 0.4 |
|
Net Income | | | | | | 125.5 |
| | | | 125.5 |
|
Other Comprehensive Loss | | | | | | | | (1.0 | ) | | (1.0 | ) |
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2018 | | 260.4 |
| | 1,828.7 |
| | 1,799.7 |
| | 0.6 |
| | 3,889.4 |
|
| | | | | | | | | | |
Common Stock Dividends | | |
| | |
| | (40.0 | ) | | |
| | (40.0 | ) |
Net Income | | |
| | |
| | 77.4 |
| | |
| | 77.4 |
|
Other Comprehensive Loss | | |
| | |
| | |
| | (1.0 | ) | | (1.0 | ) |
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2018 | | 260.4 |
| | 1,828.7 |
| | 1,837.1 |
| | (0.4 | ) | | 3,925.8 |
|
| | | | | | | | | | |
Common Stock Dividends | | | | | | (40.0 | ) | | | | (40.0 | ) |
Net Income | | | | | | 87.1 |
| | | | 87.1 |
|
Other Comprehensive Loss | | | | | | | | (1.0 | ) | | (1.0 | ) |
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2018 | | $ | 260.4 |
| | $ | 1,828.7 |
| | $ | 1,884.2 |
| | $ | (1.4 | ) | | $ | 3,971.9 |
|
| | | | | | | | | | |
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2018 | | $ | 260.4 |
| | $ | 1,828.7 |
| | $ | 1,922.0 |
| | $ | (5.0 | ) | | $ | 4,006.1 |
|
| | | | | | | | | | |
Common Stock Dividends | | | | | | (50.0 | ) | | | | (50.0 | ) |
Net Income | | | | | | 133.7 |
| | | | 133.7 |
|
Other Comprehensive Loss | | | | | | | | (0.8 | ) | | (0.8 | ) |
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2019 | | 260.4 |
| | 1,828.7 |
| | 2,005.7 |
| | (5.8 | ) | | 4,089.0 |
|
| | | | | | | | | | |
Common Stock Dividends | | | | | | (50.0 | ) | | | | (50.0 | ) |
Net Income | | | | | | 55.5 |
| | | | 55.5 |
|
Other Comprehensive Loss | | | | | | | | (0.9 | ) | | (0.9 | ) |
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2019 | | 260.4 |
| | 1,828.7 |
| | 2,011.2 |
| | (6.7 | ) | | 4,093.6 |
|
| | | | | | | | | | |
Common Stock Dividends | | |
| | |
| | (25.0 | ) | | |
| | (25.0 | ) |
Net Income | | |
| | |
| | 104.3 |
| | |
| | 104.3 |
|
Other Comprehensive Loss | | |
| | |
| | |
| | (0.9 | ) | | (0.9 | ) |
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2019 | | $ | 260.4 |
| | $ | 1,828.7 |
| | $ | 2,090.5 |
| | $ | (7.6 | ) | | $ | 4,172.0 |
|
|
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 126.
|
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 20192020 and December 31, 20182019
(in millions)
(Unaudited)
| | | | | | | | | | | | | | |
| | September 30, | | December 31, |
| | 2020 | | 2019 |
CURRENT ASSETS | | | | |
Cash and Cash Equivalents | | $ | 3.9 | | | $ | 3.3 | |
Restricted Cash for Securitized Funding | | 9.3 | | | 23.5 | |
Advances to Affiliates | | 159.5 | | | 22.1 | |
Accounts Receivable: | | | | |
Customers | | 136.6 | | | 129.0 | |
Affiliated Companies | | 60.2 | | | 64.3 | |
Accrued Unbilled Revenues | | 52.6 | | | 59.7 | |
Miscellaneous | | 0.2 | | | 0.5 | |
Allowance for Uncollectible Accounts | | (3.4) | | | (2.6) | |
Total Accounts Receivable | | 246.2 | | | 250.9 | |
Fuel | | 144.4 | | | 149.7 | |
Materials and Supplies | | 98.2 | | | 105.2 | |
Risk Management Assets | | 30.7 | | | 39.4 | |
| | | | |
Regulatory Asset for Under-Recovered Fuel Costs | | 3.7 | | | 42.5 | |
| | | | |
Prepayments and Other Current Assets | | 29.7 | | | 64.0 | |
TOTAL CURRENT ASSETS | | 725.6 | | | 700.6 | |
| | | | |
PROPERTY, PLANT AND EQUIPMENT | | | | |
Electric: | | | | |
Generation | | 6,615.9 | | | 6,563.7 | |
Transmission | | 3,811.4 | | | 3,584.1 | |
Distribution | | 4,348.8 | | | 4,201.7 | |
Other Property, Plant and Equipment | | 622.5 | | | 571.3 | |
Construction Work in Progress | | 539.9 | | | 593.4 | |
Total Property, Plant and Equipment | | 15,938.5 | | | 15,514.2 | |
Accumulated Depreciation and Amortization | | 4,652.7 | | | 4,432.3 | |
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | 11,285.8 | | | 11,081.9 | |
| | | | |
OTHER NONCURRENT ASSETS | | | | |
Regulatory Assets | | 659.1 | | | 457.2 | |
Securitized Assets | | 216.2 | | | 234.7 | |
Long-term Risk Management Assets | | 0.1 | | | 0.1 | |
Operating Lease Assets | | 80.3 | | | 78.5 | |
Deferred Charges and Other Noncurrent Assets | | 190.9 | | | 215.3 | |
TOTAL OTHER NONCURRENT ASSETS | | 1,146.6 | | | 985.8 | |
| | | | |
TOTAL ASSETS | | $ | 13,158.0 | | | $ | 12,768.3 | |
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134. | | | | |
|
| | | | | | | | |
| | September 30, | | December 31, |
| | 2019 | | 2018 |
CURRENT ASSETS | | | | |
Cash and Cash Equivalents | | $ | 3.5 |
| | $ | 4.2 |
|
Restricted Cash for Securitized Funding | | 17.1 |
| | 25.6 |
|
Advances to Affiliates | | 22.7 |
| | 23.0 |
|
Accounts Receivable: | | | | |
Customers | | 112.1 |
| | 146.5 |
|
Affiliated Companies | | 56.4 |
| | 73.4 |
|
Accrued Unbilled Revenues | | 56.9 |
| | 63.5 |
|
Miscellaneous | | 1.0 |
| | 2.3 |
|
Allowance for Uncollectible Accounts | | (2.3 | ) | | (2.3 | ) |
Total Accounts Receivable | | 224.1 |
| | 283.4 |
|
Fuel | | 108.8 |
| | 61.3 |
|
Materials and Supplies | | 102.1 |
| | 100.1 |
|
Risk Management Assets | | 56.5 |
| | 57.2 |
|
Regulatory Asset for Under-Recovered Fuel Costs | | 43.7 |
| | 99.6 |
|
Prepayments and Other Current Assets | | 36.3 |
| | 44.3 |
|
TOTAL CURRENT ASSETS | | 614.8 |
| | 698.7 |
|
| | | | |
PROPERTY, PLANT AND EQUIPMENT | | | | |
Electric: | | | | |
Generation | | 6,560.5 |
| | 6,509.6 |
|
Transmission | | 3,412.4 |
| | 3,317.7 |
|
Distribution | | 4,126.7 |
| | 3,989.4 |
|
Other Property, Plant and Equipment | | 525.3 |
| | 485.8 |
|
Construction Work in Progress | | 667.4 |
| | 490.2 |
|
Total Property, Plant and Equipment | | 15,292.3 |
| | 14,792.7 |
|
Accumulated Depreciation and Amortization | | 4,300.2 |
| | 4,124.4 |
|
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | 10,992.1 |
| | 10,668.3 |
|
| | | | |
OTHER NONCURRENT ASSETS | | | | |
Regulatory Assets | | 474.2 |
| | 475.8 |
|
Securitized Assets | | 240.6 |
| | 258.7 |
|
Long-term Risk Management Assets | | 0.2 |
| | 0.9 |
|
Operating Lease Assets | | 79.4 |
| | — |
|
Deferred Charges and Other Noncurrent Assets | | 159.3 |
| | 188.1 |
|
TOTAL OTHER NONCURRENT ASSETS | | 953.7 |
| | 923.5 |
|
| | | | |
TOTAL ASSETS | | $ | 12,560.6 |
| | $ | 12,290.5 |
|
85
|
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 126. |
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
September 30, 20192020 and December 31, 20182019
(Unaudited)
| | | | | | | | | | | | | | |
| | September 30, | | December 31, |
| | 2020 | | 2019 |
| | (in millions) | | |
CURRENT LIABILITIES | | | | |
Advances from Affiliates | | $ | 4.3 | | | $ | 236.7 | |
Accounts Payable: | | | | |
General | | 191.6 | | | 307.8 | |
Affiliated Companies | | 80.0 | | | 92.5 | |
Long-term Debt Due Within One Year – Nonaffiliated | | 518.3 | | | 215.6 | |
| | | | |
Risk Management Liabilities | | 5.6 | | | 1.9 | |
Customer Deposits | | 80.1 | | | 85.8 | |
| | | | |
Accrued Taxes | | 77.3 | | | 99.6 | |
Accrued Interest | | 73.8 | | | 47.9 | |
Obligations Under Operating Leases | | 14.7 | | | 15.2 | |
| | | | |
Other Current Liabilities | | 98.4 | | | 123.0 | |
TOTAL CURRENT LIABILITIES | | 1,144.1 | | | 1,226.0 | |
| | | | |
NONCURRENT LIABILITIES | | | | |
Long-term Debt – Nonaffiliated | | 4,315.0 | | | 4,148.2 | |
| | | | |
Long-term Risk Management Liabilities | | 0.2 | | | 0 | |
Deferred Income Taxes | | 1,716.5 | | | 1,680.8 | |
Regulatory Liabilities and Deferred Investment Tax Credits | | 1,195.8 | | | 1,268.7 | |
Asset Retirement Obligations | | 298.2 | | | 102.1 | |
Employee Benefits and Pension Obligations | | 38.2 | | | 50.9 | |
Obligations Under Operating Leases | | 66.1 | | | 64.0 | |
Deferred Credits and Other Noncurrent Liabilities | | 55.5 | | | 55.2 | |
TOTAL NONCURRENT LIABILITIES | | 7,685.5 | | | 7,369.9 | |
| | | | |
TOTAL LIABILITIES | | 8,829.6 | | | 8,595.9 | |
| | | | |
Rate Matters (Note 4) | | | | |
Commitments and Contingencies (Note 5) | | | | |
| | | | |
COMMON SHAREHOLDER’S EQUITY | | | | |
Common Stock – NaN Par Value: | | | | |
Authorized – 30,000,000 Shares | | | | |
Outstanding – 13,499,500 Shares | | 260.4 | | | 260.4 | |
Paid-in Capital | | 1,828.7 | | | 1,828.7 | |
Retained Earnings | | 2,241.5 | | | 2,078.3 | |
Accumulated Other Comprehensive Income (Loss) | | (2.2) | | | 5.0 | |
TOTAL COMMON SHAREHOLDER’S EQUITY | | 4,328.4 | | | 4,172.4 | |
| | | | |
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY | | $ | 13,158.0 | | | $ | 12,768.3 | |
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134. | | | | |
|
| | | | | | | | |
| | September 30, | | December 31, |
| | 2019 | | 2018 |
| | (in millions) |
CURRENT LIABILITIES | | | | |
Advances from Affiliates | | $ | 40.4 |
| | $ | 205.6 |
|
Accounts Payable: | | |
| | |
|
General | | 298.5 |
| | 263.8 |
|
Affiliated Companies | | 90.8 |
| | 84.0 |
|
Long-term Debt Due Within One Year – Nonaffiliated | | 215.6 |
| | 430.7 |
|
Risk Management Liabilities | | 1.1 |
| | 0.4 |
|
Customer Deposits | | 85.1 |
| | 88.4 |
|
Accrued Taxes | | 58.2 |
| | 89.3 |
|
Accrued Interest | | 67.5 |
| | 41.5 |
|
Obligations Under Operating Leases | | 15.3 |
| | — |
|
Other Current Liabilities | | 107.6 |
| | 150.3 |
|
TOTAL CURRENT LIABILITIES | | 980.1 |
| | 1,354.0 |
|
| | | | |
NONCURRENT LIABILITIES | | | | |
Long-term Debt – Nonaffiliated | | 4,147.3 |
| | 3,631.9 |
|
Long-term Risk Management Liabilities | | 0.3 |
| | 0.2 |
|
Deferred Income Taxes | | 1,640.8 |
| | 1,625.8 |
|
Regulatory Liabilities and Deferred Investment Tax Credits | | 1,336.9 |
| | 1,449.7 |
|
Asset Retirement Obligations | | 108.2 |
| | 107.1 |
|
Employee Benefits and Pension Obligations | | 52.7 |
| | 57.1 |
|
Obligations Under Operating Leases | | 64.8 |
| | — |
|
Deferred Credits and Other Noncurrent Liabilities | | 57.5 |
| | 58.6 |
|
TOTAL NONCURRENT LIABILITIES | | 7,408.5 |
| | 6,930.4 |
|
| | | | |
TOTAL LIABILITIES | | 8,388.6 |
| | 8,284.4 |
|
| | | | |
Rate Matters (Note 4) | |
| |
|
Commitments and Contingencies (Note 5) | |
| |
|
| | | | |
COMMON SHAREHOLDER’S EQUITY | | | | |
Common Stock – No Par Value: | | | | |
Authorized – 30,000,000 Shares | | |
| | |
Outstanding – 13,499,500 Shares | | 260.4 |
| | 260.4 |
|
Paid-in Capital | | 1,828.7 |
| | 1,828.7 |
|
Retained Earnings | | 2,090.5 |
| | 1,922.0 |
|
Accumulated Other Comprehensive Income (Loss) | | (7.6 | ) | | (5.0 | ) |
TOTAL COMMON SHAREHOLDER’S EQUITY | | 4,172.0 |
| | 4,006.1 |
|
| | | | |
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY | | $ | 12,560.6 |
| | $ | 12,290.5 |
|
|
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 126.
|
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 20192020 and 20182019
(in millions)
(Unaudited)
| | | | | | | | | | | | | | |
| | Nine Months Ended September 30, | | |
| | 2020 | | 2019 |
OPERATING ACTIVITIES | | | | |
Net Income | | $ | 313.2 | | | $ | 293.5 | |
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | | | |
Depreciation and Amortization | | 366.0 | | | 348.3 | |
Deferred Income Taxes | | (28.2) | | | (101.9) | |
| | | | |
| | | | |
Allowance for Equity Funds Used During Construction | | (11.5) | | | (12.5) | |
Mark-to-Market of Risk Management Contracts | | 8.0 | | | 2.2 | |
Pension Contributions to Qualified Plan Trust | | (7.0) | | | 0 | |
| | | | |
Deferred Fuel Over/Under-Recovery, Net | | 38.8 | | | 60.8 | |
Change in Other Noncurrent Assets | | 5.4 | | | 6.7 | |
Change in Other Noncurrent Liabilities | | (26.0) | | | (29.6) | |
Changes in Certain Components of Working Capital: | | | | |
Accounts Receivable, Net | | 7.2 | | | 61.7 | |
Fuel, Materials and Supplies | | 12.4 | | | (49.2) | |
Accounts Payable | | (74.0) | | | 40.1 | |
Accrued Taxes, Net | | 1.9 | | | (30.2) | |
Other Current Assets | | 10.1 | | | 6.8 | |
Other Current Liabilities | | (9.7) | | | (25.1) | |
Net Cash Flows from Operating Activities | | 606.6 | | | 571.6 | |
| | | | |
INVESTING ACTIVITIES | | | | |
Construction Expenditures | | (566.6) | | | (607.1) | |
| | | | |
Change in Advances to Affiliates, Net | | (137.4) | | | 0.3 | |
| | | | |
Other Investing Activities | | 4.6 | | | 22.8 | |
Net Cash Flows Used for Investing Activities | | (699.4) | | | (584.0) | |
| | | | |
FINANCING ACTIVITIES | | | | |
Issuance of Long-term Debt – Nonaffiliated | | 557.2 | | | 478.2 | |
Change in Advances from Affiliates, Net | | (232.4) | | | (165.2) | |
Retirement of Long-term Debt – Nonaffiliated | | (90.3) | | | (180.4) | |
| | | | |
| | | | |
Principal Payments for Finance Lease Obligations | | (5.6) | | | (5.0) | |
Dividends Paid on Common Stock | | (150.0) | | | (125.0) | |
Other Financing Activities | | 0.3 | | | 0.6 | |
Net Cash Flows from Financing Activities | | 79.2 | | | 3.2 | |
| | | | |
Net Decrease in Cash, Cash Equivalents and Restricted Cash for Securitized Funding | | (13.6) | | | (9.2) | |
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at Beginning of Period | | 26.8 | | | 29.8 | |
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at End of Period | | $ | 13.2 | | | $ | 20.6 | |
| | | | |
SUPPLEMENTARY INFORMATION | | | | |
Cash Paid for Interest, Net of Capitalized Amounts | | $ | 130.0 | | | $ | 120.6 | |
Net Cash Paid (Received) for Income Taxes | | (10.7) | | | 58.7 | |
Noncash Acquisitions Under Finance Leases | | 3.0 | | | 7.1 | |
Construction Expenditures Included in Current Liabilities as of September 30, | | 90.0 | | | 134.2 | |
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134. | | | | |
|
| | | | | | | | |
| | Nine Months Ended September 30, |
| | 2019 | | 2018 |
OPERATING ACTIVITIES | | |
| | |
|
Net Income | | $ | 293.5 |
| | $ | 290.0 |
|
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | |
| | |
|
Depreciation and Amortization | | 348.3 |
| | 319.5 |
|
Deferred Income Taxes | | (101.9 | ) | | (83.8 | ) |
Allowance for Equity Funds Used During Construction | | (12.5 | ) | | (9.6 | ) |
Mark-to-Market of Risk Management Contracts | | 2.2 |
| | (43.7 | ) |
Deferred Fuel Over/Under-Recovery, Net | | 60.8 |
| | 12.8 |
|
Change in Other Noncurrent Assets | | 6.7 |
| | 94.8 |
|
Change in Other Noncurrent Liabilities | | (29.6 | ) | | 3.8 |
|
Changes in Certain Components of Working Capital: | | |
| | |
|
Accounts Receivable, Net | | 61.7 |
| | 39.4 |
|
Fuel, Materials and Supplies | | (49.2 | ) | | 53.0 |
|
Accounts Payable | | 40.1 |
| | (21.5 | ) |
Accrued Taxes, Net | | (30.2 | ) | | (20.2 | ) |
Other Current Assets | | 6.8 |
| | (7.9 | ) |
Other Current Liabilities | | (25.1 | ) | | 64.1 |
|
Net Cash Flows from Operating Activities | | 571.6 |
| | 690.7 |
|
| | | | |
INVESTING ACTIVITIES | | |
| | |
|
Construction Expenditures | | (607.1 | ) | | (575.8 | ) |
Change in Advances to Affiliates, Net | | 0.3 |
| | 0.4 |
|
Other Investing Activities | | 22.8 |
| | 10.0 |
|
Net Cash Flows Used for Investing Activities | | (584.0 | ) | | (565.4 | ) |
| | | | |
FINANCING ACTIVITIES | | |
| | |
|
Issuance of Long-term Debt – Nonaffiliated | | 478.2 |
| | 103.3 |
|
Change in Advances from Affiliates, Net | | (165.2 | ) | | (87.5 | ) |
Retirement of Long-term Debt – Nonaffiliated | | (180.4 | ) | | (24.0 | ) |
Principal Payments for Finance Lease Obligations | | (5.0 | ) | | (5.2 | ) |
Dividends Paid on Common Stock | | (125.0 | ) | | (120.0 | ) |
Other Financing Activities | | 0.6 |
| | 1.0 |
|
Net Cash Flows from (Used for) Financing Activities | | 3.2 |
| | (132.4 | ) |
| | | | |
Net Decrease in Cash, Cash Equivalents and Restricted Cash for Securitized Funding | | (9.2 | ) | | (7.1 | ) |
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at Beginning of Period | | 29.8 |
| | 19.2 |
|
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at End of Period | | $ | 20.6 |
| | $ | 12.1 |
|
| | | | |
SUPPLEMENTARY INFORMATION | | |
| | |
|
Cash Paid for Interest, Net of Capitalized Amounts | | $ | 120.6 |
| | $ | 104.5 |
|
Net Cash Paid for Income Taxes | | 58.7 |
| | 26.7 |
|
Noncash Acquisitions Under Finance Leases | | 7.1 |
| | 3.9 |
|
Construction Expenditures Included in Current Liabilities as of September 30, | | 134.2 |
| | 87.6 |
|
|
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page
126. |
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 | | |
| September 30, | | | | September 30, | | |
| 2020 | | 2019 | | 2020 | | 2019 |
| (in millions of KWhs) | | | | | | |
Retail: | | | | | | | |
Residential | 1,531 | | | 1,496 | | | 4,230 | | | 4,159 | |
Commercial | 1,219 | | | 1,312 | | | 3,362 | | | 3,555 | |
Industrial | 1,849 | | | 1,937 | | | 5,324 | | | 5,742 | |
Miscellaneous | 14 | | | 16 | | | 47 | | | 49 | |
Total Retail | 4,613 | | | 4,761 | | | 12,963 | | | 13,505 | |
| | | | | | | |
Wholesale | 1,536 | | | 2,398 | | | 5,552 | | | 6,842 | |
| | | | | | | |
Total KWhs | 6,149 | | | 7,159 | | | 18,515 | | | 20,347 | |
|
| | | | | | | | | | | |
| Three Months Ended | | Nine Months Ended |
| September 30, | | September 30, |
| 2019 | | 2018 | | 2019 | | 2018 |
| (in millions of KWhs) |
Retail: | |
| | |
| | |
| | |
|
Residential | 1,496 |
| | 1,562 |
| | 4,159 |
| | 4,430 |
|
Commercial | 1,312 |
| | 1,348 |
| | 3,555 |
| | 3,708 |
|
Industrial | 1,937 |
| | 2,018 |
| | 5,742 |
| | 5,920 |
|
Miscellaneous | 16 |
| | 15 |
| | 49 |
| | 50 |
|
Total Retail (a) | 4,761 |
| | 4,943 |
| | 13,505 |
| | 14,108 |
|
| | | | | | | |
Wholesale | 2,398 |
| | 2,613 |
| | 6,842 |
| | 7,927 |
|
| | | | | | | |
Total KWhs | 7,159 |
| | 7,556 |
| | 20,347 |
| | 22,035 |
|
| |
(a) | 2018 KWhs have been revised to reflect the reclassification of certain customer accounts between Retail classes. This reclassification did not impact previously reported Total Retail KWhs. Management concluded that these prior period disclosure only errors were immaterial individually and in the aggregate. |
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 | | |
| September 30, | | | | September 30, | | |
| 2020 | | 2019 | | 2020 | | 2019 |
| (in degree days) | | | | | | |
Actual – Heating (a) | 7 | | | — | | | 2,186 | | | 2,456 | |
Normal – Heating (b) | 10 | | | 11 | | | 2,429 | | | 2,412 | |
| | | | | | | |
Actual – Cooling (c) | 637 | | | 684 | | | 923 | | | 917 | |
Normal – Cooling (b) | 576 | | | 573 | | | 841 | | | 836 | |
(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.
|
| | | | | | | | | | | |
| Three Months Ended | | Nine Months Ended |
| September 30, | | September 30, |
| 2019 | | 2018 | | 2019 | | 2018 |
| (in degree days) |
Actual – Heating (a) | — |
| | 2 |
| | 2,456 |
| | 2,523 |
|
Normal – Heating (b) | 11 |
| | 10 |
| | 2,412 |
| | 2,413 |
|
| | | | | | | |
Actual – Cooling (c) | 684 |
| | 722 |
| | 917 |
| | 1,084 |
|
Normal – Cooling (b) | 573 |
| | 574 |
| | 836 |
| | 837 |
|
| |
(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 20192020 Compared to Third Quarter of 20182019
| | | | | | | | |
Reconciliation of Third Quarter of 2019 to Third Quarter of 2020 | | |
Net Income | | |
(in millions) | | |
| | |
Third Quarter of 2019 | | $ | 88.8 | |
| | |
Changes in Gross Margin: | | |
Retail Margins | | 9.0 | |
| | |
Margins from Off-system Sales | | (0.3) | |
Transmission Revenues | | 2.6 | |
Other Revenues | | (6.5) | |
Total Change in Gross Margin | | 4.8 | |
| | |
Changes in Expenses and Other: | | |
Other Operation and Maintenance | | 7.1 | |
| | |
Depreciation and Amortization | | (16.4) | |
Taxes Other Than Income Taxes | | (2.3) | |
Other Income | | (1.3) | |
| | |
| | |
Non-Service Cost Components of Net Periodic Benefit Cost | | (0.4) | |
Interest Expense | | 1.9 | |
Total Change in Expenses and Other | | (11.4) | |
| | |
Income Tax Expense | | (5.5) | |
| | |
Third Quarter of 2020 | | $ | 76.7 | |
|
| | | | |
Reconciliation of Third Quarter of 2018 to Third Quarter of 2019 |
Net Income |
(in millions) |
| | |
Third Quarter of 2018 | | $ | 72.7 |
|
| | |
|
Changes in Gross Margin: | | |
|
Retail Margins | | 17.5 |
|
Transmission Revenues | | (1.7 | ) |
Other Revenues | | 3.4 |
|
Total Change in Gross Margin | | 19.2 |
|
| | |
|
Changes in Expenses and Other: | | |
|
Other Operation and Maintenance | | (17.1 | ) |
Depreciation and Amortization | | (2.9 | ) |
Taxes Other Than Income Taxes | | (2.1 | ) |
Other Income | | (2.6 | ) |
Non-Service Cost Components of Net Periodic Benefit Cost | | (0.1 | ) |
Interest Expense | | 5.7 |
|
Total Change in Expenses and Other | | (19.1 | ) |
| | |
|
Income Tax Expense (Benefit) | | 16.0 |
|
| | |
|
Third Quarter of 2019 | | $ | 88.8 |
|
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 $9 million primarily due to the following: • increased $18 million primarily due to the following: |
A $19$38 million increase fromprimarily due to the Indiana and Michigan base rate proceedings.cases and increases in rate riders. This increase was partially offset in other expense items below.
An $8 million increase related to rider revenues, primarily due to the timing of the Indiana PJM/OSS rider recovery. This increase was partially offset in other expense items below.
These increases were partially offset by:
•A $6$20 million decrease in weather-normalized wholesale margins, across all retail classes.including the loss of a significant wholesale contract.
•A $3$6 million decrease in weather-related usage primarily due to a 5%7% decrease in cooling degree days.
| |
• | •A $3 million decrease in weather-normalized retail margins. •Transmission Revenues increased $3 million primarily due to a July 2019 adjustment to the annual transmission formula rate true-up. •Other Revenues decreased $7 million primarily due to a decrease in barging revenues by River Transportation Division (RTD). This decrease was partially offset in Other Operation and Maintenance expenses below.
increased $3 million primarily due to an increase in barging deliveries by River Transportation Division (RTD). The increase in RTD revenue was offset by a corresponding increase in Other Operation and Maintenance expenses for barging activities discussed below.
|
Expenses and Other and Income Tax Expense (Benefit) changed between years as follows:
| |
• | •Other Operation and Maintenance expenses decreased $7 million primarily due to the following: • expenses increased $17 million primarily due to the following: |
A $15$10 million decrease in nonutility operation expenses primarily due to a decrease in RTD expenses. This decrease was partially offset in Other Revenues above.
•A $4 million decrease in steam generation expense primarily due to 2019 NSR Consent Decree modifications.
•A $4 million decrease in nuclear generation expenses primarily due to a decrease in maintenance activities.
•A $3 million decrease in administrative and general expenses primarily due to a decrease in rate case and insurance expenses.
These decreases were partially offset by:
•A $12 million increase in employee-related expenses.
•A $2 million increase in transmission expenses primarily due to a $10 millionan increase in recoverable PJM expensesexpenses.
•Depreciation and Amortization expensesincreased $16 million primarily due to a $6 millionhigher depreciable base and an increase from the amortization of credits under the 2018 Regional Transmission Enhancement Plan settlement.in depreciation rates. This increase was partially offset in Retail Margins above.
A $4•Income Tax Expense increased $6 million primarily due to the recognition of a discrete tax adjustment, which was primarily attributable to the filing of the 2019 Federal Income Tax return in the third quarter of 2020, and an increase in RTD expenses for barging activities. The increase in RTD expenses was offset by a corresponding increase in Other Revenues from barging activities discussed above.state income tax expense.
| |
• | Depreciation and Amortizationexpensesincreased $3 million primarily due to a higher depreciable base. This increase was partially offset in Retail Margins above.
|
| |
• | Interest Expensedecreased $6 million primarily due to the reissuance of long-term debt at lower interest rates in 2018.
|
| |
• | Income Tax Expense (Benefit) decreased $16 million primarily due to increased amortization of Excess ADIT not subject to normalization requirements and a decrease in flow-through tax expense.
|
Nine Months Ended September 30, 20192020 Compared to Nine Months Ended September 30, 20182019
| | | | | | | | |
Reconciliation of Nine Months Ended September 30, 2019 to Nine Months Ended September 30, 2020 | | |
Net Income | | |
(in millions) | | |
| | |
Nine Months Ended September 30, 2019 | | $ | 248.0 | |
| | |
Changes in Gross Margin: | | |
Retail Margins | | 25.8 | |
| | |
Margins from Off-system Sales | | (0.3) | |
Transmission Revenues | | 10.0 | |
Other Revenues | | (13.7) | |
Total Change in Gross Margin | | 21.8 | |
| | |
Changes in Expenses and Other: | | |
Other Operation and Maintenance | | 27.4 | |
| | |
Depreciation and Amortization | | (42.0) | |
Taxes Other Than Income Taxes | | (0.9) | |
Other Income | | (7.5) | |
| | |
| | |
Non-Service Cost Components of Net Periodic Benefit Cost | | (0.8) | |
Interest Expense | | 0.2 | |
Total Change in Expenses and Other | | (23.6) | |
| | |
Income Tax Expense | | (13.4) | |
| | |
Nine Months Ended September 30, 2020 | | $ | 232.8 | |
|
| | | | |
Reconciliation of Nine Months Ended September 30, 2018 to Nine Months Ended September 30, 2019 |
Net Income |
(in millions) |
| | |
Nine Months Ended September 30, 2018 | | $ | 231.6 |
|
| | |
|
Changes in Gross Margin: | | |
|
Retail Margins | | 89.7 |
|
Margins from Off-system Sales | | (9.4 | ) |
Transmission Revenues | | (12.0 | ) |
Other Revenues | | 3.7 |
|
Total Change in Gross Margin | | 72.0 |
|
| | |
|
Changes in Expenses and Other: | | |
|
Other Operation and Maintenance | | (36.6 | ) |
Depreciation and Amortization | | (54.5 | ) |
Taxes Other Than Income Taxes | | (5.7 | ) |
Other Income | | (0.1 | ) |
Non-Service Cost Components of Net Periodic Benefit Cost | | (0.3 | ) |
Interest Expense | | 9.7 |
|
Total Change in Expenses and Other | | (87.5 | ) |
| | |
|
Income Tax Expense (Benefit) | | 31.9 |
|
| | |
|
Nine Months Ended September 30, 2019 | | $ | 248.0 |
|
The major components of the increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased electricity were as follows:
| |
• | Retail Margins increased $90•Retail Margins increased $26 million primarily due to the following: |
A $94 million increase from rate proceedings, inclusive of a $30 million decrease due to the impact of Tax Reform.following:
•A $72 million increase primarily due to the Indiana and Michigan base rate cases and increases in rider revenues. This increase was partially offset in other expense items below.
A $21 million increase related to rider revenues, primarily due to the timing of the Indiana PJM/OSS rider recovery. This increase was partially offset in other expense items below.by:
•A $6$37 million decrease in fuel-related expenses due to timingweather-normalized wholesale margins, including the loss of recovery for fuel and other variable production costs related toa significant wholesale contracts.contract.
These increases were partially offset by:
A $19•An $8 million decrease in weather-related usage primarily due to a 15% decrease in cooling degree days and a 3%an 11% decrease in heating degree days.
•A $16$6 million decrease in weather-normalized margins across all retail classes.margins.
| |
• | Margins from Off-system Salesdecreased $9 million primarily due to mid-year 2018 changes in the OSS sharing mechanism.•Transmission Revenues increased $10 million primarily due to the following: •A $6 million increase from the annual transmission formula rate true-up. •A $4 million increase from investment in transmission assets. This increase was partially offset in Other Operation and Maintenance expenses below. •Other Revenues decreased $14 million primarily due to a decrease in barging revenues by RTD. This decrease was partially offset in Other Operation and Maintenance expenses below.
|
| |
• | Transmission Revenues decreased $12 million primarily due to the 2018 PJM Transmission formula rate true-up.
|
| |
• | Other Revenues increased $4 million primarily due to an increase in barging deliveries by RTD. The increase in RTD revenue was offset by a corresponding increase in Other Operation and Maintenance expenses for barging activities discussed below.
|
Expenses and Other and Income Tax Expense (Benefit) changed between years as follows:
•Other Operation and Maintenance expenses increased $37decreased $27 million primarily due to the following:
•An $18 million decrease in nonutility operation expenses primarily due to a decrease in RTD expenses. This decrease was partially offset in Other Revenues above.
•An $8 million decrease in distribution expenses primarily due to a decrease in vegetation management expenses.
•A $32$7 million decrease due to an increased Nuclear Electric Insurance Limited distribution in 2020.
•A $7 million decrease in Cook Plant refueling outage amortization expense primarily due to decreased costs of outages and various maintenance activities.
•A $4 million decrease in steam generation expense primarily due to 2019 NSR Consent Decree modifications.
These decreases were partially offset by:
•A $12 million increase in transmission expenses primarily due to a $44$21 million increase in recoverable PJM expenses, partially offset by an $11 million decrease from the amortization of credits under the 2018 Regionalannual transmission formula rate true-up. This increase was partially offset in Transmission Enhancement Plan settlement.Revenues above.
•A $5 million increase in employee-related expenses.
•Depreciation and Amortization expensesincreased $42 million primarily due to a higher depreciable base and an increase in depreciation rates. This increase was partially offset in Retail Margins above.
A $6•Other Income decreased $8 million increase in RTD expenses for barging activities. The increase in RTD expenses was offset by a corresponding increase in Other Revenues from barging activities discussed above.
A $5 million increase in distribution costs primarily due to vegetation management expenses.
These increases were partially offset by:
A $9 milliona decrease in generation expenses at Cook Plantthe AFUDC base and the favorable impact of a FERC settlement agreement recorded in 2019.
•Income Tax Expense increased $13 million primarily due to decreased incremental refueling outage costs.
| |
• | Depreciation and Amortizationan increase in state income tax expense and a decrease in favorable flow-through tax benefits.expensesincreased $55 million primarily due to increased depreciation rates approved in 2018 and a higher depreciable base. This increase was partially offset in Retail Margins above.
|
| |
• | Taxes Other Than Income Taxes increased $6 million due to property taxes driven by an increase in utility plant.
|
| |
• | Interest Expense decreased $10 million primarily due to the reissuance of long-term debt at lower interest rates in 2018.
|
| |
• | Income Tax Expense (Benefit) decreased $32 million primarily due to increased amortization of Excess ADIT not subject to normalization requirements and a decrease in flow-through tax expense.
|
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 20192020 and 20182019
(in millions)
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | | | Nine Months Ended | | |
| | September 30, | | | | September 30, | | |
| | 2020 | | 2019 | | 2020 | | 2019 |
REVENUES | | | | | | | | |
Electric Generation, Transmission and Distribution | | $ | 570.1 | | | $ | 589.1 | | | $ | 1,648.4 | | | $ | 1,703.2 | |
Sales to AEP Affiliates | | 1.3 | | | 2.7 | | | 9.1 | | | 7.3 | |
Other Revenues – Affiliated | | 14.1 | | | 16.2 | | | 42.4 | | | 50.4 | |
Other Revenues – Nonaffiliated | | 1.2 | | | 3.1 | | | 3.7 | | | 7.6 | |
TOTAL REVENUES | | 586.7 | | | 611.1 | | | 1,703.6 | | | 1,768.5 | |
| | | | | | | | |
EXPENSES | | | | | | | | |
Fuel and Other Consumables Used for Electric Generation | | 44.4 | | | 61.2 | | | 146.0 | | | 161.2 | |
Purchased Electricity for Resale | | 37.5 | | | 44.8 | | | 128.1 | | | 163.3 | |
Purchased Electricity from AEP Affiliates | | 55.9 | | | 61.0 | | | 135.8 | | | 172.1 | |
Other Operation | | 165.5 | | | 172.7 | | | 459.7 | | | 467.7 | |
Maintenance | | 51.0 | | | 50.9 | | | 144.4 | | | 163.8 | |
| | | | | | | | |
Depreciation and Amortization | | 104.5 | | | 88.1 | | | 303.6 | | | 261.6 | |
Taxes Other Than Income Taxes | | 27.4 | | | 25.1 | | | 79.5 | | | 78.6 | |
TOTAL EXPENSES | | 486.2 | | | 503.8 | | | 1,397.1 | | | 1,468.3 | |
| | | | | | | | |
OPERATING INCOME | | 100.5 | | | 107.3 | | | 306.5 | | | 300.2 | |
| | | | | | | | |
Other Income (Expense): | | | | | | | | |
Other Income | | 2.2 | | | 3.5 | | | 7.8 | | | 15.3 | |
| | | | | | | | |
| | | | | | | | |
Non-Service Cost Components of Net Periodic Benefit Cost | | 4.1 | | | 4.5 | | | 12.5 | | | 13.3 | |
Interest Expense | | (26.9) | | | (28.8) | | | (85.7) | | | (85.9) | |
| | | | | | | | |
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) | | 79.9 | | | 86.5 | | | 241.1 | | | 242.9 | |
| | | | | | | | |
Income Tax Expense (Benefit) | | 3.2 | | | (2.3) | | | 8.3 | | | (5.1) | |
| | | | | | | | |
NET INCOME | | $ | 76.7 | | | $ | 88.8 | | | $ | 232.8 | | | $ | 248.0 | |
| | | | | | | | |
The common stock of I&M is wholly-owned by Parent. | | | | | | | | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134. | | | | | | | | |
|
| | | | | | | | | | | | | | | | |
| | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, |
| | 2019 | | 2018 | | 2019 | | 2018 |
REVENUES | | | | | | | | |
|
Electric Generation, Transmission and Distribution | | $ | 589.1 |
| | $ | 609.9 |
| | $ | 1,703.2 |
| | $ | 1,723.9 |
|
Sales to AEP Affiliates | | 2.7 |
| | 3.4 |
| | 7.3 |
| | 18.9 |
|
Other Revenues – Affiliated | | 16.2 |
| | 13.7 |
| | 50.4 |
| | 43.3 |
|
Other Revenues – Nonaffiliated | | 3.1 |
| | 2.7 |
| | 7.6 |
| | 10.1 |
|
TOTAL REVENUES | | 611.1 |
| | 629.7 |
| | 1,768.5 |
| | 1,796.2 |
|
| | | | | | | | |
EXPENSES | | |
| | |
| | |
| | |
|
Fuel and Other Consumables Used for Electric Generation | | 61.2 |
| | 95.9 |
| | 161.2 |
| | 246.8 |
|
Purchased Electricity for Resale | | 44.8 |
| | 48.9 |
| | 163.3 |
| | 167.7 |
|
Purchased Electricity from AEP Affiliates | | 61.0 |
| | 60.0 |
| | 172.1 |
| | 181.8 |
|
Other Operation | | 172.7 |
| | 149.3 |
| | 467.7 |
| | 425.8 |
|
Maintenance | | 50.9 |
| | 57.2 |
| | 163.8 |
| | 169.1 |
|
Depreciation and Amortization | | 88.1 |
| | 85.2 |
| | 261.6 |
| | 207.1 |
|
Taxes Other Than Income Taxes | | 25.1 |
| | 23.0 |
| | 78.6 |
| | 72.9 |
|
TOTAL EXPENSES | | 503.8 |
| | 519.5 |
| | 1,468.3 |
| | 1,471.2 |
|
| | | | | | | | |
OPERATING INCOME | | 107.3 |
| | 110.2 |
| | 300.2 |
| | 325.0 |
|
| | | | | | | | |
Other Income (Expense): | | |
| | |
| | |
| | |
|
Other Income | | 3.5 |
| | 6.1 |
| | 15.3 |
| | 15.4 |
|
Non-Service Cost Components of Net Periodic Benefit Cost | | 4.5 |
| | 4.6 |
| | 13.3 |
| | 13.6 |
|
Interest Expense | | (28.8 | ) | | (34.5 | ) | | (85.9 | ) | | (95.6 | ) |
| | | | | | | | |
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) | | 86.5 |
| | 86.4 |
| | 242.9 |
| | 258.4 |
|
| | | | | | | | |
Income Tax Expense (Benefit) | | (2.3 | ) | | 13.7 |
| | (5.1 | ) | | 26.8 |
|
| | | | | | | | |
NET INCOME | | $ | 88.8 |
| | $ | 72.7 |
| | $ | 248.0 |
| | $ | 231.6 |
|
|
|
The common stock of I&M is wholly-owned by Parent. |
|
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 126.
|
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 20192020 and 20182019
(in millions)
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | | | Nine Months Ended | | |
| | September 30, | | | | September 30, | | |
| | 2020 | | 2019 | | 2020 | | 2019 |
Net Income | | $ | 76.7 | | | $ | 88.8 | | | $ | 232.8 | | | $ | 248.0 | |
| | | | | | | | |
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, 2020 and 2019, Respectively, and $0.3 and $0.3 for the Nine Months Ended September 30, 2020 and 2019, Respectively | | 0.4 | | | 0.4 | | | 1.2 | | | 1.2 | |
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0 and $0 for the Three Months Ended September 30, 2020 and 2019, Respectively, and $0 and $0 for the Nine Months Ended September 30, 2020 and 2019, Respectively | | (0.1) | | | 0 | | | (0.1) | | | (0.1) | |
| | | | | | | | |
TOTAL OTHER COMPREHENSIVE INCOME | | 0.3 | | | 0.4 | | | 1.1 | | | 1.1 | |
| | | | | | | | |
TOTAL COMPREHENSIVE INCOME | | $ | 77.0 | | | $ | 89.2 | | | $ | 233.9 | | | $ | 249.1 | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134. | | | | | | | | |
|
| | | | | | | | | | | | | | | | |
| | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, |
| | 2019 | | 2018 | | 2019 | | 2018 |
Net Income | | $ | 88.8 |
| | $ | 72.7 |
| | $ | 248.0 |
| | $ | 231.6 |
|
| | | | | | | | |
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, 2019 and 2018, Respectively, and $0.3 and $0.3 for the Nine Months Ended September 30, 2019 and 2018, Respectively | | 0.4 |
| | 0.3 |
| | 1.2 |
| | 1.2 |
|
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0 and $0 for the Three Months Ended September 30, 2019 and 2018, Respectively, and $0 and $0 for the Nine Months Ended September 30, 2019 and 2018, Respectively | | — |
| | — |
| | (0.1 | ) | | — |
|
| | | | | | | | |
TOTAL OTHER COMPREHENSIVE INCOME | | 0.4 |
| | 0.3 |
| | 1.1 |
| | 1.2 |
|
| | | | | | | | |
TOTAL COMPREHENSIVE INCOME | | $ | 89.2 |
| | $ | 73.0 |
| | $ | 249.1 |
| | $ | 232.8 |
|
|
|
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 126.
|
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Nine Months Ended September 30, 20192020 and 20182019
(in millions)
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Common Stock | | Paid-in Capital | | Retained Earnings | | Accumulated Other Comprehensive Income (Loss) | | Total |
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2018 | | $ | 56.6 | | | $ | 980.9 | | | $ | 1,329.1 | | | $ | (13.8) | | | $ | 2,352.8 | |
| | | | | | | | | | |
Common Stock Dividends | | | | | | (20.0) | | | | | (20.0) | |
| | | | | | | | | | |
Net Income | | | | | | 98.9 | | | | | 98.9 | |
Other Comprehensive Income | | | | | | | | 0.4 | | | 0.4 | |
TOTAL COMMON SHAREHOLDER’S EQUITY - MARCH 31, 2019 | | 56.6 | | | 980.9 | | | 1,408.0 | | | (13.4) | | | 2,432.1 | |
| | | | | | | | | | |
Common Stock Dividends | | | | | | (20.0) | | | | | (20.0) | |
Net Income | | | | | | 60.3 | | | | | 60.3 | |
Other Comprehensive Income | | | | | | | | 0.3 | | | 0.3 | |
TOTAL COMMON SHAREHOLDER’S EQUITY - JUNE 30, 2019 | | 56.6 | | | 980.9 | | | 1,448.3 | | | (13.1) | | | 2,472.7 | |
| | | | | | | | | | |
Common Stock Dividends | | | | | | (20.0) | | | | | (20.0) | |
Net Income | | | | | | 88.8 | | | | | 88.8 | |
Other Comprehensive Income | | | | | | | | 0.4 | | | 0.4 | |
TOTAL COMMON SHAREHOLDER’S EQUITY - SEPTEMBER 30, 2019 | | $ | 56.6 | | | $ | 980.9 | | | $ | 1,517.1 | | | $ | (12.7) | | | $ | 2,541.9 | |
| | | | | | | | | | |
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 | |
| | | | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134. | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | |
| | Common Stock | | Paid-in Capital | | Retained Earnings | | Accumulated Other Comprehensive Income (Loss) | | Total |
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2017 | | $ | 56.6 |
| | $ | 980.9 |
| | $ | 1,192.2 |
| | $ | (12.1 | ) | | $ | 2,217.6 |
|
| | | | | | | | | | |
Common Stock Dividends | | |
| | |
| | (33.5 | ) | | |
| | (33.5 | ) |
ASU 2018-02 Adoption | | | | | | 0.3 |
| | (2.7 | ) | | (2.4 | ) |
Net Income | | |
| | |
| | 64.2 |
| | |
| | 64.2 |
|
Other Comprehensive Income | | |
| | |
| | |
| | 0.4 |
| | 0.4 |
|
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2018 | | 56.6 |
| | 980.9 |
| | 1,223.2 |
| | (14.4 | ) | | 2,246.3 |
|
| | | | | | | | | | |
Common Stock Dividends | | | | | | (33.5 | ) | | | | (33.5 | ) |
Net Income | | | | | | 94.7 |
| | | | 94.7 |
|
Other Comprehensive Income | | | | | | | | 0.5 |
| | 0.5 |
|
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2018 | | 56.6 |
| | 980.9 |
| | 1,284.4 |
| | (13.9 | ) | | 2,308.0 |
|
| | | | | | | | | | |
Common Stock Dividends | | | | | | (38.5 | ) | | | | (38.5 | ) |
Net Income | | | | | | 72.7 |
| | | | 72.7 |
|
Other Comprehensive Income | | | | | | | | 0.3 |
| | 0.3 |
|
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2018 | | $ | 56.6 |
| | $ | 980.9 |
| | $ | 1,318.6 |
| | $ | (13.6 | ) | | $ | 2,342.5 |
|
| | |
| | |
| | |
| | |
| | |
|
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2018 | | $ | 56.6 |
| | $ | 980.9 |
| | $ | 1,329.1 |
| | $ | (13.8 | ) | | $ | 2,352.8 |
|
| | | | | | | | | | |
Common Stock Dividends | | | | | | (20.0 | ) | | | | (20.0 | ) |
Net Income | | | | | | 98.9 |
| | | | 98.9 |
|
Other Comprehensive Income | | | | | | | | 0.4 |
| | 0.4 |
|
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2019 | | 56.6 |
| | 980.9 |
| | 1,408.0 |
| | (13.4 | ) | | 2,432.1 |
|
| | | | | | | | | | |
Common Stock Dividends | | |
| | |
| | (20.0 | ) | | |
| | (20.0 | ) |
Net Income | | |
| | |
| | 60.3 |
| | |
| | 60.3 |
|
Other Comprehensive Income | | |
| | |
| | |
| | 0.3 |
| | 0.3 |
|
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2019 | | 56.6 |
| | 980.9 |
| | 1,448.3 |
| | (13.1 | ) | | 2,472.7 |
|
| | | | | | | | | | |
Common Stock Dividends | | | | | | (20.0 | ) | | | | (20.0 | ) |
Net Income | | | | | | 88.8 |
| | | | 88.8 |
|
Other Comprehensive Income | | | | | | | | 0.4 |
| | 0.4 |
|
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2019 | | $ | 56.6 |
| | $ | 980.9 |
| | $ | 1,517.1 |
| | $ | (12.7 | ) | | $ | 2,541.9 |
|
|
|
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 126.
|
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 20192020 and December 31, 20182019
(in millions)
(Unaudited)
| | | | | | | | | | | | | | |
| | September 30, | | December 31, |
| | 2020 | | 2019 |
CURRENT ASSETS | | | | |
Cash and Cash Equivalents | | $ | 2.8 | | | $ | 2.0 | |
Advances to Affiliates | | 13.3 | | | 13.2 | |
Accounts Receivable: | | | | |
Customers | | 34.7 | | | 53.6 | |
Affiliated Companies | | 43.5 | | | 53.7 | |
Accrued Unbilled Revenues | | 0 | | | 2.5 | |
Miscellaneous | | 0.9 | | | 0.3 | |
Allowance for Uncollectible Accounts | | (0.3) | | | (0.6) | |
Total Accounts Receivable | | 78.8 | | | 109.5 | |
Fuel | | 71.3 | | | 56.2 | |
Materials and Supplies | | 171.4 | | | 171.3 | |
Risk Management Assets | | 4.1 | | | 9.8 | |
Accrued Tax Benefits | | 29.8 | | | 0 | |
Regulatory Asset for Under-Recovered Fuel Costs | | 4.2 | | | 3.0 | |
Accrued Reimbursement of Spent Nuclear Fuel Costs | | 14.7 | | | 24.0 | |
| | | | |
Prepayments and Other Current Assets | | 17.0 | | | 14.0 | |
TOTAL CURRENT ASSETS | | 407.4 | | | 403.0 | |
| | | | |
PROPERTY, PLANT AND EQUIPMENT | | | | |
Electric: | | | | |
Generation | | 5,239.8 | | | 5,099.7 | |
Transmission | | 1,665.8 | | | 1,641.8 | |
Distribution | | 2,549.5 | | | 2,437.6 | |
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel) | | 665.8 | | | 632.6 | |
Construction Work in Progress | | 383.3 | | | 382.3 | |
Total Property, Plant and Equipment | | 10,504.2 | | | 10,194.0 | |
Accumulated Depreciation, Depletion and Amortization | | 3,502.4 | | | 3,294.3 | |
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | 7,001.8 | | | 6,899.7 | |
| | | | |
OTHER NONCURRENT ASSETS | | | | |
Regulatory Assets | | 450.2 | | | 482.1 | |
Spent Nuclear Fuel and Decommissioning Trusts | | 3,075.9 | | | 2,975.7 | |
Long-term Risk Management Assets | | 0 | | | 0.1 | |
Operating Lease Assets | | 228.8 | | | 294.9 | |
Deferred Charges and Other Noncurrent Assets | | 160.7 | | | 181.9 | |
TOTAL OTHER NONCURRENT ASSETS | | 3,915.6 | | | 3,934.7 | |
| | | | |
TOTAL ASSETS | | $ | 11,324.8 | | | $ | 11,237.4 | |
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134. | | | | |
|
| | | | | | | | |
| | September 30, | | December 31, |
| | 2019 | | 2018 |
CURRENT ASSETS | | | | |
Cash and Cash Equivalents | | $ | 2.5 |
| | $ | 2.4 |
|
Advances to Affiliates | | 13.2 |
| | 12.7 |
|
Accounts Receivable: | | | | |
Customers | | 45.0 |
| | 63.1 |
|
Affiliated Companies | | 45.3 |
| | 75.0 |
|
Accrued Unbilled Revenues | | 2.7 |
| | 3.6 |
|
Miscellaneous | | 1.0 |
| | 1.4 |
|
Allowance for Uncollectible Accounts | | (0.1 | ) | | (0.1 | ) |
Total Accounts Receivable | | 93.9 |
| | 143.0 |
|
Fuel | | 39.8 |
| | 37.3 |
|
Materials and Supplies | | 169.9 |
| | 167.3 |
|
Risk Management Assets | | 10.5 |
| | 8.6 |
|
Accrued Tax Benefits | | 43.2 |
| | 26.6 |
|
Accrued Reimbursement of Spent Nuclear Fuel Costs | | 24.2 |
| | 7.9 |
|
Prepayments and Other Current Assets | | 16.9 |
| | 24.6 |
|
TOTAL CURRENT ASSETS | | 414.1 |
| | 430.4 |
|
| | | | |
PROPERTY, PLANT AND EQUIPMENT | | | | |
Electric: | | | | |
Generation | | 5,002.0 |
| | 4,887.2 |
|
Transmission | | 1,614.5 |
| | 1,576.8 |
|
Distribution | | 2,373.3 |
| | 2,249.7 |
|
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel) | | 607.2 |
| | 583.8 |
|
Construction Work in Progress | | 516.2 |
| | 465.3 |
|
Total Property, Plant and Equipment | | 10,113.2 |
| | 9,762.8 |
|
Accumulated Depreciation, Depletion and Amortization | | 3,280.5 |
| | 3,151.6 |
|
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | 6,832.7 |
| | 6,611.2 |
|
| | | | |
OTHER NONCURRENT ASSETS | | | | |
Regulatory Assets | | 490.2 |
| | 512.5 |
|
Spent Nuclear Fuel and Decommissioning Trusts | | 2,835.2 |
| | 2,474.9 |
|
Long-term Risk Management Assets | | 0.1 |
| | 0.6 |
|
Operating Lease Assets | | 295.3 |
| | — |
|
Deferred Charges and Other Noncurrent Assets | | 129.6 |
| | 193.0 |
|
TOTAL OTHER NONCURRENT ASSETS | | 3,750.4 |
| | 3,181.0 |
|
| | | | |
TOTAL ASSETS | | $ | 10,997.2 |
| | $ | 10,222.6 |
|
|
|
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 126.
|
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
September 30, 20192020 and December 31, 20182019
(dollars in millions)
(Unaudited)
| | | | | | | | | | | | | | |
| | September 30, | | December 31, |
| | 2020 | | 2019 |
CURRENT LIABILITIES | | | | |
Advances from Affiliates | | $ | 159.1 | | | $ | 114.4 | |
Accounts Payable: | | | | |
General | | 133.3 | | | 169.4 | |
Affiliated Companies | | 79.7 | | | 68.4 | |
Long-term Debt Due Within One Year – Nonaffiliated (September 30, 2020 and December 31, 2019 Amounts Include $54.9 and $86.1, Respectively, Related to DCC Fuel) | | 348.7 | | | 139.7 | |
Risk Management Liabilities | | 0.2 | | | 0.5 | |
Customer Deposits | | 40.2 | | | 39.4 | |
Accrued Taxes | | 57.8 | | | 112.4 | |
Accrued Interest | | 19.9 | | | 36.2 | |
Obligations Under Operating Leases | | 83.8 | | | 87.3 | |
Regulatory Liability for Over-Recovered Fuel Costs | | 30.6 | | | 6.1 | |
Other Current Liabilities | | 91.0 | | | 109.6 | |
TOTAL CURRENT LIABILITIES | | 1,044.3 | | | 883.4 | |
| | | | |
NONCURRENT LIABILITIES | | | | |
Long-term Debt – Nonaffiliated | | 2,633.2 | | | 2,910.5 | |
Long-term Risk Management Liabilities | | 0.1 | | | 0 | |
Deferred Income Taxes | | 1,024.0 | | | 979.7 | |
Regulatory Liabilities and Deferred Investment Tax Credits | | 1,879.6 | | | 1,891.4 | |
Asset Retirement Obligations | | 1,796.1 | | | 1,748.6 | |
Obligations Under Operating Leases | | 165.4 | | | 211.6 | |
Deferred Credits and Other Noncurrent Liabilities | | 67.1 | | | 67.8 | |
TOTAL NONCURRENT LIABILITIES | | 7,565.5 | | | 7,809.6 | |
| | | | |
TOTAL LIABILITIES | | 8,609.8 | | | 8,693.0 | |
| | | | |
Rate Matters (Note 4) | | | | |
Commitments and Contingencies (Note 5) | | | | |
| | | | |
COMMON SHAREHOLDER’S EQUITY | | | | |
Common Stock – NaN Par Value: | | | | |
Authorized – 2,500,000 Shares | | | | |
Outstanding – 1,400,000 Shares | | 56.6 | | | 56.6 | |
Paid-in Capital | | 980.9 | | | 980.9 | |
Retained Earnings | | 1,688.0 | | | 1,518.5 | |
Accumulated Other Comprehensive Income (Loss) | | (10.5) | | | (11.6) | |
TOTAL COMMON SHAREHOLDER’S EQUITY | | 2,715.0 | | | 2,544.4 | |
| | | | |
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY | | $ | 11,324.8 | | | $ | 11,237.4 | |
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134. | | | | |
|
| | | | | | | | |
| | September 30, | | December 31, |
| | 2019 | | 2018 |
CURRENT LIABILITIES | | | | |
Advances from Affiliates | | $ | 102.4 |
| | $ | 1.1 |
|
Accounts Payable: | | | | |
General | | 148.4 |
| | 174.7 |
|
Affiliated Companies | | 71.6 |
| | 70.2 |
|
Long-term Debt Due Within One Year – Nonaffiliated (September 30, 2019 and December 31, 2018 Amounts Include $68.8 and $76.8, Respectively, Related to DCC Fuel) | | 147.4 |
| | 155.4 |
|
Risk Management Liabilities | | 0.2 |
| | 0.3 |
|
Customer Deposits | | 37.9 |
| | 38.0 |
|
Accrued Taxes | | 57.9 |
| | 90.7 |
|
Accrued Interest | | 20.5 |
| | 37.3 |
|
Obligations Under Operating Leases | | 82.0 |
| | — |
|
Regulatory Liability for Over-Recovered Fuel Costs | | 7.3 |
| | 27.4 |
|
Other Current Liabilities | | 85.5 |
| | 103.0 |
|
TOTAL CURRENT LIABILITIES | | 761.1 |
| | 698.1 |
|
| | | | |
NONCURRENT LIABILITIES | | | | |
Long-term Debt – Nonaffiliated | | 2,884.1 |
| | 2,880.0 |
|
Long-term Risk Management Liabilities | | — |
| | 0.1 |
|
Deferred Income Taxes | | 970.0 |
| | 948.0 |
|
Regulatory Liabilities and Deferred Investment Tax Credits | | 1,809.0 |
| | 1,574.5 |
|
Asset Retirement Obligations | | 1,731.5 |
| | 1,681.3 |
|
Obligations Under Operating Leases | | 234.0 |
| | — |
|
Deferred Credits and Other Noncurrent Liabilities | | 65.6 |
| | 87.8 |
|
TOTAL NONCURRENT LIABILITIES | | 7,694.2 |
| | 7,171.7 |
|
| | | | |
TOTAL LIABILITIES | | 8,455.3 |
| | 7,869.8 |
|
| | | | |
Rate Matters (Note 4) | |
| |
|
Commitments and Contingencies (Note 5) | |
| |
|
| | | | |
COMMON SHAREHOLDER’S EQUITY | | | | |
Common Stock – No Par Value: | | | | |
Authorized – 2,500,000 Shares | | | | |
Outstanding – 1,400,000 Shares | | 56.6 |
| | 56.6 |
|
Paid-in Capital | | 980.9 |
| | 980.9 |
|
Retained Earnings | | 1,517.1 |
| | 1,329.1 |
|
Accumulated Other Comprehensive Income (Loss) | | (12.7 | ) | | (13.8 | ) |
TOTAL COMMON SHAREHOLDER’S EQUITY | | 2,541.9 |
| | 2,352.8 |
|
| | | | |
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY | | $ | 10,997.2 |
| | $ | 10,222.6 |
|
|
|
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 126.
|
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 20192020 and 20182019
(in millions)
(Unaudited)
| | | | | | | | | | | | | | |
| | Nine Months Ended September 30, | | |
| | 2020 | | 2019 |
OPERATING ACTIVITIES | | | | |
Net Income | | $ | 232.8 | | | $ | 248.0 | |
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | | | |
Depreciation and Amortization | | 303.6 | | | 261.6 | |
Rockport Plant, Unit 2 Operating Lease Amortization | | 51.9 | | | 58.9 | |
Deferred Income Taxes | | (6.1) | | | (29.9) | |
Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net | | 21.3 | | | (11.6) | |
| | | | |
| | | | |
Allowance for Equity Funds Used During Construction | | (8.8) | | | (16.4) | |
Mark-to-Market of Risk Management Contracts | | 5.6 | | | (1.6) | |
Amortization of Nuclear Fuel | | 67.2 | | | 71.6 | |
Pension Contributions to Qualified Plan Trust | | (6.4) | | | 0 | |
Deferred Fuel Over/Under-Recovery, Net | | 23.4 | | | (20.0) | |
Change in Other Noncurrent Assets | | 40.8 | | | 46.0 | |
Change in Other Noncurrent Liabilities | | 30.2 | | | 13.8 | |
Changes in Certain Components of Working Capital: | | | | |
Accounts Receivable, Net | | 32.2 | | | 50.5 | |
Fuel, Materials and Supplies | | (15.4) | | | (4.6) | |
| | | | |
Accounts Payable | | (0.9) | | | (7.3) | |
| | | | |
Accrued Taxes, Net | | (84.4) | | | (49.4) | |
| | | | |
Rockport Plant, Unit 2 Operating Lease Payments | | (36.9) | | | (36.9) | |
Other Current Assets | | 6.6 | | | 7.8 | |
Other Current Liabilities | | (59.1) | | | (49.7) | |
Net Cash Flows from Operating Activities | | 597.6 | | | 530.8 | |
| | | | |
INVESTING ACTIVITIES | | | | |
Construction Expenditures | | (409.1) | | | (431.7) | |
Change in Advances to Affiliates, Net | | (0.1) | | | (0.5) | |
Purchases of Investment Securities | | (1,290.0) | | | (915.7) | |
Sales of Investment Securities | | 1,257.1 | | | 871.4 | |
Acquisitions of Nuclear Fuel | | (68.4) | | | (91.9) | |
| | | | |
Other Investing Activities | | 8.3 | | | 10.5 | |
Net Cash Flows Used for Investing Activities | | (502.2) | | | (557.9) | |
| | | | |
FINANCING ACTIVITIES | | | | |
Issuance of Long-term Debt – Nonaffiliated | | 0 | | | 62.9 | |
Change in Advances from Affiliates, Net | | 44.7 | | | 101.3 | |
Retirement of Long-term Debt – Nonaffiliated | | (71.1) | | | (73.6) | |
Principal Payments for Finance Lease Obligations | | (4.8) | | | (4.0) | |
Dividends Paid on Common Stock | | (63.7) | | | (60.0) | |
Other Financing Activities | | 0.3 | | | 0.6 | |
Net Cash Flows from (Used for) Financing Activities | | (94.6) | | | 27.2 | |
| | | | |
Net Increase in Cash and Cash Equivalents | | 0.8 | | | 0.1 | |
Cash and Cash Equivalents at Beginning of Period | | 2.0 | | | 2.4 | |
Cash and Cash Equivalents at End of Period | | $ | 2.8 | | | $ | 2.5 | |
| | | | |
SUPPLEMENTARY INFORMATION | | | | |
Cash Paid for Interest, Net of Capitalized Amounts | | $ | 97.5 | | | $ | 98.7 | |
Net Cash Paid for Income Taxes | | 59.7 | | | 40.2 | |
Noncash Acquisitions Under Finance Leases | | 1.9 | | | 8.1 | |
Construction Expenditures Included in Current Liabilities as of September 30, | | 57.6 | | | 76.3 | |
Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30, | | 1.0 | | | 0 | |
Expected Reimbursement for Capital Cost of Spent Nuclear Fuel Dry Cask Storage | | 2.4 | | | 0 | |
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134. | | | | |
|
| | | | | | | | |
| | Nine Months Ended September 30, |
| | 2019 | | 2018 |
OPERATING ACTIVITIES | | |
| | |
|
Net Income | | $ | 248.0 |
| | $ | 231.6 |
|
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | |
| | |
Depreciation and Amortization | | 261.6 |
| | 207.1 |
|
Rent - Rockport Plant, Unit 2 | | 58.9 |
| | — |
|
Deferred Income Taxes | | (29.9 | ) | | 28.1 |
|
Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net | | (11.6 | ) | | 13.5 |
|
Allowance for Equity Funds Used During Construction | | (16.4 | ) | | (8.0 | ) |
Mark-to-Market of Risk Management Contracts | | (1.6 | ) | | (0.3 | ) |
Amortization of Nuclear Fuel | | 71.6 |
| | 82.6 |
|
Deferred Fuel Over/Under-Recovery, Net | | (20.0 | ) | | 29.6 |
|
Change in Other Noncurrent Assets | | 46.0 |
| | (12.0 | ) |
Change in Other Noncurrent Liabilities | | 13.8 |
| | 46.3 |
|
Changes in Certain Components of Working Capital: | | |
| | |
|
Accounts Receivable, Net | | 50.5 |
| | 6.5 |
|
Fuel, Materials and Supplies | | (4.6 | ) | | (1.1 | ) |
Accounts Payable | | (7.3 | ) | | (34.7 | ) |
Accrued Taxes, Net | | (49.4 | ) | | (7.1 | ) |
Payments for Rockport Plant, Unit 2 Operating Lease | | (36.9 | ) | | — |
|
Other Current Assets | | 7.8 |
| | 4.9 |
|
Other Current Liabilities | | (49.7 | ) | | (15.7 | ) |
Net Cash Flows from Operating Activities | | 530.8 |
| | 571.3 |
|
| | | | |
INVESTING ACTIVITIES | | |
| | |
|
Construction Expenditures | | (431.7 | ) | | (434.5 | ) |
Change in Advances to Affiliates, Net | | (0.5 | ) | | (60.1 | ) |
Purchases of Investment Securities | | (915.7 | ) | | (1,589.0 | ) |
Sales of Investment Securities | | 871.4 |
| | 1,550.9 |
|
Acquisitions of Nuclear Fuel | | (91.9 | ) | | (26.1 | ) |
Other Investing Activities | | 10.5 |
| | 9.2 |
|
Net Cash Flows Used for Investing Activities | | (557.9 | ) | | (549.6 | ) |
| | | | |
FINANCING ACTIVITIES | | |
| | |
|
Issuance of Long-term Debt – Nonaffiliated | | 62.9 |
| | 1,168.1 |
|
Change in Advances from Affiliates, Net | | 101.3 |
| | (211.6 | ) |
Retirement of Long-term Debt – Nonaffiliated | | (73.6 | ) | | (856.1 | ) |
Principal Payments for Finance Lease Obligations | | (4.0 | ) | | (7.3 | ) |
Dividends Paid on Common Stock | | (60.0 | ) | | (105.5 | ) |
Other Financing Activities | | 0.6 |
| | (9.0 | ) |
Net Cash Flows from (Used for) Financing Activities | | 27.2 |
| | (21.4 | ) |
| | | | |
Net Increase in Cash and Cash Equivalents | | 0.1 |
| | 0.3 |
|
Cash and Cash Equivalents at Beginning of Period | | 2.4 |
| | 1.3 |
|
Cash and Cash Equivalents at End of Period | | $ | 2.5 |
| | $ | 1.6 |
|
| | | | |
SUPPLEMENTARY INFORMATION | | |
| | |
|
Cash Paid for Interest, Net of Capitalized Amounts | | $ | 98.7 |
| | $ | 104.4 |
|
Net Cash Paid (Received) for Income Taxes | | 40.2 |
| | (26.5 | ) |
Noncash Acquisitions Under Finance Leases | | 8.1 |
| | 4.4 |
|
Construction Expenditures Included in Current Liabilities as of September 30, | | 76.3 |
| | 66.4 |
|
Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30, | | — |
| | 12.1 |
|
Expected Reimbursement for Capital Cost of Spent Nuclear Fuel Dry Cask Storage | | — |
| | 2.1 |
|
|
|
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page
126. |
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 | | |
| September 30, | | | | September 30, | | |
| 2020 | | 2019 | | 2020 | | 2019 |
| (in millions of KWhs) | | | | | | |
Retail: | | | | | | | |
Residential | 4,165 | | | 4,120 | | | 11,140 | | | 11,034 | |
Commercial | 3,781 | | | 4,067 | | | 10,454 | | | 11,072 | |
Industrial | 3,380 | | | 3,689 | | | 9,855 | | | 10,936 | |
Miscellaneous | 22 | | | 26 | | | 82 | | | 83 | |
Total Retail (a) | 11,348 | | | 11,902 | | | 31,531 | | | 33,125 | |
| | | | | | | |
Wholesale (b) | 502 | | | 453 | | | 1,347 | | | 1,531 | |
| | | | | | | |
Total KWhs | 11,850 | | | 12,355 | | | 32,878 | | | 34,656 | |
|
| | | | | | | | | | | |
| Three Months Ended | | Nine Months Ended |
| September 30, | | September 30, |
| 2019 | | 2018 | | 2019 | | 2018 |
| (in millions of KWhs) |
Retail: | |
| | |
| | |
| | |
|
Residential | 4,120 |
| | 4,055 |
| | 11,034 |
| | 11,475 |
|
Commercial | 4,067 |
| | 3,971 |
| | 11,072 |
| | 11,146 |
|
Industrial | 3,689 |
| | 3,688 |
| | 10,936 |
| | 11,066 |
|
Miscellaneous | 26 |
| | 27 |
| | 83 |
| | 84 |
|
Total Retail (a)(b) | 11,902 |
| | 11,741 |
| | 33,125 |
| | 33,771 |
|
| | | | | | | |
Wholesale (c) | 453 |
| | 634 |
| | 1,531 |
| | 1,835 |
|
| | | | | | | |
Total KWhs | 12,355 |
| | 12,375 |
| | 34,656 |
| | 35,606 |
|
(a)Represents energy delivered to distribution customers.
(b)Primarily Ohio’s contractually obligated purchases of OVEC power sold to PJM.
| |
(a) | 2018 KWhs have been revised to reflect the reclassification of certain customer accounts between Retail classes. This reclassification did not impact previously reported Total Retail KWhs. Management concluded that these prior period disclosure only errors were immaterial individually and in the aggregate. |
| |
(b) | Represents energy delivered to distribution customers. |
| |
(c) | 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 | | |
| September 30, | | | | September 30, | | |
| 2020 | | 2019 | | 2020 | | 2019 |
| (in degree days) | | | | | | |
Actual – Heating (a) | 2 | | | — | | | 1,767 | | | 2,006 | |
Normal – Heating (b) | 6 | | | 6 | | | 2,086 | | | 2,072 | |
| | | | | | | |
Actual – Cooling (c) | 809 | | | 872 | | | 1,126 | | | 1,176 | |
Normal – Cooling (b) | 682 | | | 672 | | | 986 | | | 973 | |
(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.
|
| | | | | | | | | | | | |
| | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, |
| | 2019 | | 2018 | | 2019 | | 2018 |
| | (in degree days) |
Actual – Heating (a) | | — |
| | — |
| | 2,006 |
| | 2,158 |
|
Normal – Heating (b) | | 6 |
| | 6 |
| | 2,072 |
| | 2,076 |
|
| | | | | | | | |
Actual – Cooling (c) | | 872 |
| | 864 |
| | 1,176 |
| | 1,322 |
|
Normal – Cooling (b) | | 672 |
| | 670 |
| | 973 |
| | 964 |
|
| |
(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 20192020 Compared to Third Quarter of 20182019
|
| | | | |
Reconciliation of Third Quarter of 2018 to Third Quarter of 2019 |
Net Income |
(in millions) |
| | |
Third Quarter of 2018 | | $ | 88.7 |
|
| | |
|
Changes in Gross Margin: | | |
|
Retail Margins | | (2.9 | ) |
Margins from Off-system Sales | | (12.2 | ) |
Transmission Revenues | | 0.5 |
|
Other Revenues | | 1.7 |
|
Total Change in Gross Margin | | (12.9 | ) |
| | |
|
Changes in Expenses and Other: | | |
|
Other Operation and Maintenance | | 23.7 |
|
Depreciation and Amortization | | 13.0 |
|
Taxes Other Than Income Taxes | | (5.1 | ) |
Carrying Costs Income | | 0.1 |
|
Allowance for Equity Funds Used During Construction | | 2.8 |
|
Non-Service Cost Components of Net Periodic Benefit Cost | | (0.1 | ) |
Interest Expense | | (1.8 | ) |
Total Change in Expenses and Other | | 32.6 |
|
| | |
|
Income Tax Expense (Benefit) | | (39.3 | ) |
| | |
|
Third Quarter of 2019 | | $ | 69.1 |
|
The major components of the decrease in Gross Margin, defined as revenues less the related direct cost of purchased electricity and amortization of generation deferrals were as follows:
| | | | | | | | |
• | Retail Margins decreased $3 million primarily dueReconciliation of Third Quarter of 2019 to the following:Third Quarter of 2020
|
A $28 million net decrease in Basic Transmission Cost Rider revenues and recoverable PJM expenses. This decrease was partially offset in Other Operation and Maintenance expenses below.
A $13 million decrease in Deferred Asset Phase-In-Recovery Rider revenues which ended in the second quarter of 2019. This decrease was offset in Depreciation and Amortization expenses below.
An $8 million net decrease in margin for the Rate Stability Rider including associated amortizations which ended in the third quarter of 2019.
A $6 million decrease in revenues associated with a vegetation management rider. This decrease was offset in Other Operation and Maintenance expenses below.
A $6 million net decrease in margin for the Phase-In-Recovery Rider including associated amortizations which ended in the first quarter of 2019.
These decreases were partially offset by:
A $27 million net increase primarily due to 2018 adjustments to the distribution decoupling under-recovery balance as a result of the 2018 Ohio Tax Reform settlement and changes in tax riders. This increase was partially offset in Income Tax Expense (Benefit) below.
A $12 million increase due to the recovery of higher current year losses from a power contract with OVEC. This increase was offset in Margins from Off-system Sales below.
A $9 million increase in revenues associated with smart grid riders. This increase was partially offset in other expense items below.
A $4 million increase in rider revenues associated with the DIR. This decrease was partially offset in other expense items below.
A $3 million increase in Energy Efficiency/Peak Demand Reduction rider revenues. This increase was offset in Other Operation and Maintenance expenses below.
| |
•Net Income | | |
(in millions) | | |
| | |
Third Quarter of 2019 | | $ | 69.1 | |
| | |
Changes in Gross Margin: | | |
Retail Margins | | 56.3 | |
Margins from Off-system Sales | | decreased $12 million primarily due to higher current year losses from a power contract with OVEC and lower deferrals as a result of the OVEC PPA rider. This decrease was offset in Retail Margins above.0.5 |
Expenses and Other and Income Tax Expense (Benefit) changed between years as follows:
| |
•Transmission Revenues | | 4.4 | |
Other Revenues | | 3.5 | |
Total Change in Gross Margin | | 64.7 | |
| | |
Changes in Expenses and Other: | | |
Other Operation and Maintenance | | expenses decreased $24 million primarily due to the following:(43.4) |
A $26 million decrease in recoverable PJM expenses. This decrease was offset in Gross Margin above.
A $5 million decrease in recoverable distribution expenses related to vegetation management. This decrease was partially offset in Retail Margins above.
A $4 million decrease due to higher charitable contributions in 2018.
These decreases were partially offset by:
A $13 million increase in PJM expenses primarily related to the annual formula rate true-up.
| |
• | Depreciation and Amortization | | expenses(16.7)decreased $13 million primarily due to the following: |
An $8 million decrease in amortizations associated with the Deferred Asset Phase-In-Recovery Rider which ended in the second quarter of 2019. This decrease was offset in Retail Margins above.
A $6 million decrease in recoverable DIR depreciation expense. This decrease was partially offset in Retail Margins above.
These decreases were partially offset by:
A $4 million increase in depreciation expense due to an increase in the depreciable base of transmission and distribution assets.
| |
• | Taxes Other Than Income Taxes | | increased(5.8) $5 million primarily due to an increase in property taxes driven by additional investments in transmission and distribution assets and higher tax rates. | |
Interest Income | | (0.4) | |
| | |
•Allowance for Equity Funds Used During Construction | | (0.2) | |
Non-Service Cost Components of Net Periodic Benefit Cost | | 0.1 | |
Interest Expense | | (1.5) | |
Total Change in Expenses and Other | | (67.9) | |
| | |
Income Tax Expense (Benefit) | | (6.9) | |
increased $39 million primarily due to a one-time recognition | | |
Third Quarter of increased amortization of Excess ADIT not subject to normalization requirements as a result of the 2018 Ohio Tax Reform Settlement. This increase was partially offset in Retail Margins above.2020 | | $ | 59.0 | |
Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018
|
| | | | |
Reconciliation of Nine Months Ended September 30, 2018 to Nine Months Ended September 30, 2019 |
Net Income |
(in millions) |
| | |
Nine Months Ended September 30, 2018 | | $ | 237.1 |
|
| | |
|
Changes in Gross Margin: | | |
|
Retail Margins | | 9.2 |
|
Margins from Off-system Sales | | (20.8 | ) |
Transmission Revenues | | 5.9 |
|
Other Revenues | | 6.0 |
|
Total Change in Gross Margin | | 0.3 |
|
| | |
|
Changes in Expenses and Other: | | |
|
Other Operation and Maintenance | | 28.7 |
|
Depreciation and Amortization | | 23.5 |
|
Taxes Other Than Income Taxes | | (15.9 | ) |
Interest Income | | 0.1 |
|
Carrying Costs Income | | (0.8 | ) |
Allowance for Equity Funds Used During Construction | | 6.3 |
|
Non-Service Cost Components of Net Periodic Benefit Cost | | (0.6 | ) |
Interest Expense | | (1.5 | ) |
Total Change in Expenses and Other | | 39.8 |
|
| | |
|
Income Tax Expense (Benefit) | | (29.5 | ) |
| | |
|
Nine Months Ended September 30, 2019 | | $ | 247.7 |
|
The major components of the increase in Gross Margin, defined as revenues less the related direct cost of purchased electricity and amortization of generation deferrals were as follows:
| |
• | Retail Margins increased $9•Retail Margins increased $56 million primarily due to the following: |
A $58 million increase due to a reversal of a regulatory provision.the following:
•A $33$52 million net increase due to 2018 adjustments to the distribution decoupling under-recovery balance as a result of the 2018 Ohio Tax Reform settlementin Basic Transmission Cost Rider revenues and changes in tax riders.recoverable PJM expenses. This increase was partially offset in Income Tax Expense (Benefit)Other Operation and Maintenance expenses below.
•An $18 million increase in rider revenues associated with the DIR. This increase was partially offset in other expense items below.
•A $31$5 million increase in revenues associated with the Universal Service Fund (USF). This increase was offset in Other Operation and Maintenance expenses below.
•A $3 million increase in revenues associated with smart grid riders. This increase was partially offset in other expense items below.
These increases were partially offset by:
•A $21$10 million increasedecrease in usage primarily in the commercial and residential classes.
•A $6 million decrease due to the recovery of higher current year losses from a power contract with OVEC.OVEC PPA rider which was replaced by the Legacy Generation Resource Rider (LGRR). This increasedecrease was offset in Margins from Off-system Sales and Other Revenues below.
•A $9 million increase in Energy Efficiency/Peak Demand Reduction rider revenues. This increase was offset in Other Operation and Maintenance expenses below.
These increases were partially offset by:
A $71 million net decrease in Basic Transmission Cost Rider revenues and recoverable PJM expenses. This decrease was partially offset in Other Operation and Maintenance expenses below.
An $18$3 million decrease in revenues associated with a vegetation management rider. This decrease was partially offset in Other Operation and Maintenance expenses below.
•Transmission Revenues increased $4 million primarily due to increased investment in transmission assets.
•Other Revenues increased $4 million primarily due to third-party LGRR revenue related to the recovery of OVEC costs. This increase was offset in Retail Margins above.
Expenses and Other and Income Tax Expense changed between years as follows:
•Other Operation and Maintenance expenses increased $43 million primarily due to the following:
•A $16$43 million increase in transmission expenses primarily due to an increase in recoverable PJM expenses. This increase was offset in Gross Margin above.
•A $5 million increase in remitted USF 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.
These increases were partially offset by:
•A $5 million decrease in recoverable distribution expenses related to vegetation management. This decrease was offset in Retail Margins above.
•Depreciation and Amortization expensesincreased $17 million primarily due to the following:
•A $9 million increase in recoverable DIR depreciation expense. This increase was partially offset in Retail Margins above.
•A $5 million increase in depreciation expense due to an increase in the depreciable base of transmission and distribution assets.
•Taxes Other Than Income Taxes increased $6 million primarily due to property taxes driven by additional investments in transmission and distribution assets and higher tax rates.
•Income Tax Expense increased $7 million primarily due to the recognition of a discrete tax adjustment which was primarily attributable to the filing of the 2019 Federal Income Tax return in the third quarter of 2020.
Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019
| | | | | | | | |
Reconciliation of Nine Months Ended September 30, 2019 to Nine Months Ended September 30, 2020 | | |
Net Income | | |
(in millions) | | |
| | |
Nine Months Ended September 30, 2019 | | $ | 247.7 | |
| | |
Changes in Gross Margin: | | |
Retail Margins | | 6.0 | |
Margins from Off-system Sales | | 7.3 | |
Transmission Revenues | | 22.8 | |
Other Revenues | | 12.2 | |
Total Change in Gross Margin | | 48.3 | |
| | |
Changes in Expenses and Other: | | |
Other Operation and Maintenance | | (28.3) | |
Depreciation and Amortization | | (27.6) | |
Taxes Other Than Income Taxes | | (10.9) | |
Interest Income | | (1.9) | |
Carrying Costs Income | | 0.6 | |
Allowance for Equity Funds Used During Construction | | (4.8) | |
Non-Service Cost Components of Net Periodic Benefit Cost | | 0.3 | |
Interest Expense | | (10.3) | |
Total Change in Expenses and Other | | (82.9) | |
| | |
Income Tax Expense | | 1.9 | |
| | |
Nine Months Ended September 30, 2020 | | $ | 215.0 | |
The major components of the increase in Gross Margin, defined as revenues less the related direct cost of purchased electricity and amortization of generation deferrals were as follows:
•Retail Margins increased $6 million primarily due to the following:
•A $74 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 $48 million increase in rider revenues associated with the DIR. This increase was partially offset in other expense items below.
•A $15 million increase in revenues associated with smart grid riders. This increase was partially offset in other expense items below.
•A $15 million increase in revenues associated with the USF. This increase was offset in Other Operation and Maintenance expenses below.
These increases were partially offset by:
•A $58 million decrease in margin for the Phase-In-Recovery Rider including associated amortizations which endeddue to a reversal of a regulatory provision in the first quarter of 2019.
•A $13$23 million decrease in Deferred Asset Phase-In-Recovery Rider revenues which ended in the second quarter of 2019. This decrease was partially offset in Depreciation and Amortization expenses below.
•A $21 million decrease due to the OVEC PPA rider which was replaced by the LGRR. This decrease was offset in Margins from Off-system Sales and Other Revenues below.
•A $12$17 million net decrease in margin for the Rate Stability Rider including associated amortizations which ended in the third quarter of 2019.
An $8•A $12 million decrease in usage primarily in the residential and commercial classes.class.
•A $4$9 million decrease in rider revenues associated with the DIR.a vegetation management rider. This decrease was partially offset in other expense itemsOther Operation and Maintenance expenses below.
| |
• | •A $5 million decrease due to a PUCO order to refund unused 2018 major storm reserve collections to customers. This decrease was offset in Other Operation and Maintenance expenses below.
•Margins from Off-system Sales increased $7 million primarily due to: •An $18 million increase due to higher OVEC PPA deferrals. This increase was offset in Retail Margins above. This increase was partially offset by: •A $12 million decrease in sales due to lower market prices and decreased sales volumes in 2020. This decrease was offset in Retail Margins above. •Transmission Revenues increased $23 million primarily due to the following: •A $16 million increase from the annual transmission formula rate true-up. •A $6 million increase due to additional investment in transmission assets. •Other Revenues increased $12 million primarily due to third-party LGRR revenue related to the recovery of OVEC costs. This increase was offset in Retail Margins above.
decreased $21 million primarily due to higher current year losses from a power contract with OVEC as a result of the OVEC PPA rider. This decrease was offset in Retail Margins above.
|
| |
• | Transmission Revenues increased $6 million primarily due to 2018 provisions for refunds, partially offset by the annual PJM Transmission formula rate true-up.
|
| |
• | Other Revenues increased $6 million primarily due to distribution connection fees and pole attachment revenues.
|
Expenses and Other and Income Tax Expense (Benefit) changed between years as follows:
| |
• | •Other Operation and Maintenance expenses increased $28 million primarily due to the following: • expenses decreased $29 million primarily due to the following: |
A $78$29 million decreaseincrease in transmission expenses primarily due to a $57 million increase in recoverable PJM expenses.expenses partially offset by a $28 million decrease related to the annual transmission formula rate true-up. This decreaseincrease was offset in Gross Margin above.
•A $10$15 million increase in remitted USF 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.
These increases were partially offset by:
•A $6 million decrease in recoverable distribution expenses related to vegetation management. This decrease was partially offset in Retail Margins above.
These decreases were partially•A $5 million decrease due to a PUCO order to refund unused 2018 major storm reserve collections to customers. This decrease was offset by:in Retail Margins above.
•Depreciation and Amortization expensesincreased $28 million primarily due to the following:
•A $57$16 million increase in PJM expenses primarily related to the annual formula rate true-up.
| |
• | Depreciation and Amortization expensesdecreased $24 million primarily due to the following:
|
A $30 million decrease in recoverable DIR depreciation expense. This decreaseincrease was partially offset in Retail Margins above.
•A $14 million increase in depreciation expense due to an increase in the depreciable base of transmission and distribution assets.
•An $11 million increase due to lower deferred equity amortizations associated with the Deferred Asset Phase-In-Recovery Rider which ended in the second quarter of 2019.
•A $6 million increase in recoverable smart grid expense. This increase was offset in Retail Margins above.
These increases were partially offset by:
•A $24 million decrease in amortizations associated with the Deferred Asset Phase-In-Recovery Rider which ended in the second quarter of 2019. This decrease was offset in Retail Margins above.
•Taxes Other Than Income Taxes increased $11 million primarily due to the following:
•A $16 million increase in property taxes driven by additional investments in transmission and distribution assets and higher tax rates.
This increase was partially offset by:
•A $4 million decrease in excise taxes due to lower demand in 2020. This decrease was offset by:in Retail Margins above.
A $17•Allowance for Equity Funds Used During Construction decreased $5 million increase in depreciation expenseprimarily due to an increaseadjustments that resulted from 2019 FERC audit findings and a decrease in AFUDC base.
•Interest Expense increased $10 million primarily due to higher long-term debt balances.
•Income Tax Expense decreased $2 million due to a decrease in pretax book income, partially offset by the depreciable baserecognition of transmission and distribution assets.
| |
• | Taxes Other Than Income Taxes a discrete tax adjustment.increased $16 million primarily due to an increase in property taxes driven by additional investments in transmission and distribution assets and higher tax rates.
|
| |
• | Allowance for Equity Funds Used During Construction increased $6 million primarily due to adjustments that resulted from 2019 FERC audit findings.
|
| |
• | Income Tax Expense (Benefit) increased $30 million primarily due to a one-time recognition of increased amortization of Excess ADIT not subject to normalization requirements as a result of the 2018 Ohio Tax Reform Settlement. This increase was partially offset in Retail Margins above.
|
OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 20192020 and 20182019
(in millions)
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | | | Nine Months Ended | | |
| | September 30, | | | | September 30, | | |
| | 2020 | | 2019 | | 2020 | | 2019 |
REVENUES | | | | | | | | |
Electricity, Transmission and Distribution | | $ | 730.4 | | | $ | 698.6 | | | $ | 2,031.4 | | | $ | 2,127.4 | |
Sales to AEP Affiliates | | 8.3 | | | 9.0 | | | 33.0 | | | 18.2 | |
Other Revenues | | 2.3 | | | 3.0 | | | 7.3 | | | 8.4 | |
TOTAL REVENUES | | 741.0 | | | 710.6 | | | 2,071.7 | | | 2,154.0 | |
| | | | | | | | |
EXPENSES | | | | | | | | |
Purchased Electricity for Resale | | 149.3 | | | 158.3 | | | 412.3 | | | 454.0 | |
Purchased Electricity from AEP Affiliates | | 24.1 | | | 40.6 | | | 96.8 | | | 120.4 | |
Amortization of Generation Deferrals | | 0 | | | 8.8 | | | 0 | | | 65.3 | |
Other Operation | | 244.6 | | | 194.9 | | | 608.5 | | | 565.7 | |
Maintenance | | 33.7 | | | 40.0 | | | 92.2 | | | 106.7 | |
Depreciation and Amortization | | 74.1 | | | 57.4 | | | 204.4 | | | 176.8 | |
Taxes Other Than Income Taxes | | 117.8 | | | 112.0 | | | 337.8 | | | 326.9 | |
TOTAL EXPENSES | | 643.6 | | | 612.0 | | | 1,752.0 | | | 1,815.8 | |
| | | | | | | | |
OPERATING INCOME | | 97.4 | | | 98.6 | | | 319.7 | | | 338.2 | |
| | | | | | | | |
Other Income (Expense): | | | | | | | | |
Interest Income | | 0.4 | | | 0.8 | | | 0.8 | | | 2.7 | |
Carrying Costs Income | | 0.3 | | | 0.3 | | | 1.3 | | | 0.7 | |
Allowance for Equity Funds Used During Construction | | 4.6 | | | 4.8 | | | 9.3 | | | 14.1 | |
Non-Service Cost Components of Net Periodic Benefit Cost | | 3.8 | | | 3.7 | | | 11.3 | | | 11.0 | |
Interest Expense | | (29.4) | | | (27.9) | | | (88.4) | | | (78.1) | |
| | | | | | | | |
INCOME BEFORE INCOME TAX EXPENSE | | 77.1 | | | 80.3 | | | 254.0 | | | 288.6 | |
| | | | | | | | |
Income Tax Expense | | 18.1 | | | 11.2 | | | 39.0 | | | 40.9 | |
| | | | | | | | |
NET INCOME | | $ | 59.0 | | | $ | 69.1 | | | $ | 215.0 | | | $ | 247.7 | |
| | | | | | | | |
The common stock of OPCo is wholly-owned by Parent. | | | | | | | | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134. | | | | | | | | |
|
| | | | | | | | | | | | | | | | |
| | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, |
| | 2019 | | 2018 | | 2019 | | 2018 |
REVENUES | | | | | | | | |
|
Electricity, Transmission and Distribution | | $ | 698.6 |
| | $ | 772.6 |
| | $ | 2,127.4 |
| | $ | 2,294.8 |
|
Sales to AEP Affiliates | | 9.0 |
| | 3.3 |
| | 18.2 |
| | 17.9 |
|
Other Revenues | | 3.0 |
| | 2.4 |
| | 8.4 |
| | 5.3 |
|
TOTAL REVENUES | | 710.6 |
| | 778.3 |
| | 2,154.0 |
| | 2,318.0 |
|
| | | | | | | | |
EXPENSES | | |
| | |
| | |
| | |
|
Purchased Electricity for Resale | | 158.3 |
| | 166.3 |
| | 454.0 |
| | 534.7 |
|
Purchased Electricity from AEP Affiliates | | 40.6 |
| | 39.3 |
| | 120.4 |
| | 97.4 |
|
Amortization of Generation Deferrals | | 8.8 |
| | 56.9 |
| | 65.3 |
| | 171.9 |
|
Other Operation | | 194.9 |
| | 215.2 |
| | 565.7 |
| | 586.4 |
|
Maintenance | | 40.0 |
| | 43.4 |
| | 106.7 |
| | 114.7 |
|
Depreciation and Amortization | | 57.4 |
| | 70.4 |
| | 176.8 |
| | 200.3 |
|
Taxes Other Than Income Taxes | | 112.0 |
| | 106.9 |
| | 326.9 |
| | 311.0 |
|
TOTAL EXPENSES | | 612.0 |
| | 698.4 |
| | 1,815.8 |
| | 2,016.4 |
|
| | | | | | | | |
OPERATING INCOME | | 98.6 |
| | 79.9 |
| | 338.2 |
| | 301.6 |
|
| | | | | | | | |
Other Income (Expense): | | |
| | |
| | |
| | |
|
Interest Income | | 0.8 |
| | 0.8 |
| | 2.7 |
| | 2.6 |
|
Carrying Costs Income | | 0.3 |
| | 0.2 |
| | 0.7 |
| | 1.5 |
|
Allowance for Equity Funds Used During Construction | | 4.8 |
| | 2.0 |
| | 14.1 |
| | 7.8 |
|
Non-Service Cost Components of Net Periodic Benefit Cost | | 3.7 |
| | 3.8 |
| | 11.0 |
| | 11.6 |
|
Interest Expense | | (27.9 | ) | | (26.1 | ) | | (78.1 | ) | | (76.6 | ) |
| | | | | | | | |
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) | | 80.3 |
| | 60.6 |
| | 288.6 |
| | 248.5 |
|
| | | | | | | | |
Income Tax Expense (Benefit) | | 11.2 |
| | (28.1 | ) | | 40.9 |
| | 11.4 |
|
| | | | | | | | |
NET INCOME | | $ | 69.1 |
| | $ | 88.7 |
| | $ | 247.7 |
| | $ | 237.1 |
|
|
| | | | |
The common stock of OPCo is wholly-owned by Parent. |
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 126.
|
OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 20192020 and 20182019
(in millions)
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | | | Nine Months Ended | | |
| | September 30, | | | | September 30, | | |
| | 2020 | | 2019 | | 2020 | | 2019 |
Net Income | | $ | 59.0 | | | $ | 69.1 | | | $ | 215.0 | | | $ | 247.7 | |
| | | | | | | | |
OTHER COMPREHENSIVE LOSS, NET OF TAXES | | | | | | | | |
Cash Flow Hedges, Net of Tax of $0 and $(0.1) for the Three Months Ended September 30, 2020 and 2019, Respectively, and $0 and $(0.3) for the Nine Months Ended September 30, 2020 and 2019, Respectively | | 0 | | | (0.3) | | | 0 | | | (1.0) | |
| | | | | | | | |
TOTAL COMPREHENSIVE INCOME | | $ | 59.0 | | | $ | 68.8 | | | $ | 215.0 | | | $ | 246.7 | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134. | | | | | | | | |
|
| | | | | | | | | | | | | | | | |
| | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, |
| | 2019 | | 2018 | | 2019 | | 2018 |
Net Income | | $ | 69.1 |
| | $ | 88.7 |
| | $ | 247.7 |
| | $ | 237.1 |
|
| | | | | | | | |
OTHER COMPREHENSIVE LOSS, NET OF TAXES | | |
| | |
| | |
| | |
|
Cash Flow Hedges, Net of Tax of $(0.1) and $(0.1) for the Three Months Ended September 30, 2019 and 2018, Respectively, and $(0.3) and $(0.3) for the Nine Months Ended September 30, 2019 and 2018, Respectively | | (0.3 | ) | | (0.4 | ) | | (1.0 | ) | | (1.0 | ) |
| | | | | | | | |
TOTAL COMPREHENSIVE INCOME | | $ | 68.8 |
| | $ | 88.3 |
| | $ | 246.7 |
| | $ | 236.1 |
|
|
|
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 126.
|
OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Nine Months Ended September 30, 20192020 and 20182019
(in millions)
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Common Stock | | Paid-in Capital | | Retained Earnings | | Accumulated Other Comprehensive Income (Loss) | | Total |
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2018 | | $ | 321.2 | | | $ | 838.8 | | | $ | 1,136.4 | | | $ | 1.0 | | | $ | 2,297.4 | |
| | | | | | | | | | |
Common Stock Dividends | | | | | | (25.0) | | | | | (25.0) | |
Net Income | | | | | | 128.0 | | | | | 128.0 | |
Other Comprehensive Loss | | | | | | | | (0.3) | | | (0.3) | |
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2019 | | 321.2 | | | 838.8 | | | 1,239.4 | | | 0.7 | | | 2,400.1 | |
| | | | | | | | | | |
Common Stock Dividends | | | | | | (60.0) | | | | | (60.0) | |
Net Income | | | | | | 50.6 | | | | | 50.6 | |
Other Comprehensive Loss | | | | | | | | (0.4) | | | (0.4) | |
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2019 | | 321.2 | | | 838.8 | | | 1,230.0 | | | 0.3 | | | 2,390.3 | |
| | | | | | | | | | |
| | | | | | | | | | |
Net Income | | | | | | 69.1 | | | | | 69.1 | |
Other Comprehensive Loss | | | | | | | | (0.3) | | | (0.3) | |
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2019 | | $ | 321.2 | | | $ | 838.8 | | | $ | 1,299.1 | | | $ | 0 | | | $ | 2,459.1 | |
| | | | | | | | | | |
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2019 | | $ | 321.2 | | | $ | 838.8 | | | $ | 1,348.5 | | | $ | 0 | | | $ | 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 | | | 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 | | | 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 | | | $ | 0 | | | $ | 2,658.2 | |
| | | | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134. | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | |
| | Common Stock | | Paid-in Capital | | Retained Earnings | | Accumulated Other Comprehensive Income (Loss) | | Total |
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2017 | | $ | 321.2 |
| | $ | 838.8 |
| | $ | 1,148.4 |
| | $ | 1.9 |
| | $ | 2,310.3 |
|
| | | | | | | | | | |
Common Stock Dividends | | | | | | (112.5 | ) | | | | (112.5 | ) |
ASU 2018-02 Adoption | | | | | | | | 0.4 |
| | 0.4 |
|
Net Income | | | | | | 79.6 |
| | | | 79.6 |
|
Other Comprehensive Loss | | | | | | | | (0.3 | ) | | (0.3 | ) |
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2018 | | 321.2 |
| | 838.8 |
| | 1,115.5 |
| | 2.0 |
| | 2,277.5 |
|
| | | | | | | | | | |
Common Stock Dividends | | |
| | |
| | (112.5 | ) | | |
| | (112.5 | ) |
Net Income | | |
| | |
| | 68.8 |
| | |
| | 68.8 |
|
Other Comprehensive Loss | | |
| | |
| | |
| | (0.3 | ) | | (0.3 | ) |
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2018 | | 321.2 |
| | 838.8 |
| | 1,071.8 |
| | 1.7 |
| | 2,233.5 |
|
| | | | | | | | | | |
Common Stock Dividends | | | | | | (112.5 | ) | | | | (112.5 | ) |
Net Income | | | | | | 88.7 |
| | | | 88.7 |
|
Other Comprehensive Loss | | | | | | | | (0.4 | ) | | (0.4 | ) |
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2018 | | $ | 321.2 |
| | $ | 838.8 |
| | $ | 1,048.0 |
| | $ | 1.3 |
| | $ | 2,209.3 |
|
| | |
| | |
| | |
| | |
| | |
|
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2018 | | $ | 321.2 |
| | $ | 838.8 |
| | $ | 1,136.4 |
| | $ | 1.0 |
| | $ | 2,297.4 |
|
| | | | | | | | | | |
Common Stock Dividends | | | | | | (25.0 | ) | | | | (25.0 | ) |
Net Income | | | | | | 128.0 |
| | | | 128.0 |
|
Other Comprehensive Loss | | | | | | | | (0.3 | ) | | (0.3 | ) |
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2019 | | 321.2 |
| | 838.8 |
| | 1,239.4 |
| | 0.7 |
| | 2,400.1 |
|
| | | | | | | | | | |
Common Stock Dividends | | |
| | |
| | (60.0 | ) | | |
| | (60.0 | ) |
Net Income | | |
| | |
| | 50.6 |
| | |
| | 50.6 |
|
Other Comprehensive Loss | | |
| | |
| | |
| | (0.4 | ) | | (0.4 | ) |
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2019 | | 321.2 |
| | 838.8 |
| | 1,230.0 |
| | 0.3 |
| | 2,390.3 |
|
| | | | | | | | | | |
Net Income | | | | | | 69.1 |
| | | | 69.1 |
|
Other Comprehensive Loss | | | | | | | | (0.3 | ) | | (0.3 | ) |
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2019 | | $ | 321.2 |
| | $ | 838.8 |
| | $ | 1,299.1 |
| | $ | — |
| | $ | 2,459.1 |
|
|
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 126.
|
OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 20192020 and December 31, 20182019
(in millions)
(Unaudited)
| | | | | | | | | | | | | | |
| | September 30, | | December 31, |
| | 2020 | | 2019 |
CURRENT ASSETS | | | | |
Cash and Cash Equivalents | | $ | 6.6 | | | $ | 3.7 | |
| | | | |
Accounts Receivable: | | | | |
Customers | | 18.4 | | | 53.0 | |
Affiliated Companies | | 61.0 | | | 59.3 | |
Accrued Unbilled Revenues | | 20.1 | | | 20.3 | |
Miscellaneous | | 3.9 | | | 0.5 | |
Allowance for Uncollectible Accounts | | (0.7) | | | (0.7) | |
Total Accounts Receivable | | 102.7 | | | 132.4 | |
Materials and Supplies | | 67.0 | | | 52.3 | |
Renewable Energy Credits | | 28.7 | | | 30.9 | |
| | | | |
Accrued Tax Benefits | | 4.3 | | | 11.5 | |
| | | | |
Prepayments and Other Current Assets | | 13.2 | | | 7.7 | |
TOTAL CURRENT ASSETS | | 222.5 | | | 238.5 | |
| | | | |
PROPERTY, PLANT AND EQUIPMENT | | | | |
Electric: | | | | |
Transmission | | 2,768.1 | | | 2,686.3 | |
Distribution | | 5,545.8 | | | 5,323.5 | |
Other Property, Plant and Equipment | | 882.4 | | | 765.8 | |
Construction Work in Progress | | 455.9 | | | 394.4 | |
Total Property, Plant and Equipment | | 9,652.2 | | | 9,170.0 | |
Accumulated Depreciation and Amortization | | 2,350.1 | | | 2,263.0 | |
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | 7,302.1 | | | 6,907.0 | |
| | | | |
OTHER NONCURRENT ASSETS | | | | |
Regulatory Assets | | 401.7 | | | 351.8 | |
| | | | |
Deferred Charges and Other Noncurrent Assets | | 340.6 | | | 546.3 | |
TOTAL OTHER NONCURRENT ASSETS | | 742.3 | | | 898.1 | |
| | | | |
TOTAL ASSETS | | $ | 8,266.9 | | | $ | 8,043.6 | |
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134. | | | | |
|
| | | | | | | | |
| | September 30, | | December 31, |
| | 2019 | | 2018 |
CURRENT ASSETS | | | | |
Cash and Cash Equivalents | | $ | 4.7 |
| | $ | 4.9 |
|
Restricted Cash for Securitized Funding | | — |
| | 27.6 |
|
Accounts Receivable: | | | | |
Customers | | 35.4 |
| | 111.1 |
|
Affiliated Companies | | 56.2 |
| | 70.8 |
|
Accrued Unbilled Revenues | | 26.5 |
| | 21.4 |
|
Miscellaneous | | 0.3 |
| | 0.3 |
|
Allowance for Uncollectible Accounts | | (2.1 | ) | | (1.0 | ) |
Total Accounts Receivable | | 116.3 |
| | 202.6 |
|
Materials and Supplies | | 48.5 |
| | 42.9 |
|
Renewable Energy Credits | | 41.5 |
| | 25.9 |
|
Prepayments and Other Current Assets | | 19.8 |
| | 15.7 |
|
TOTAL CURRENT ASSETS | | 230.8 |
| | 319.6 |
|
| | | | |
PROPERTY, PLANT AND EQUIPMENT | | | | |
Electric: | | | | |
Transmission | | 2,613.0 |
| | 2,544.3 |
|
Distribution | | 5,192.8 |
| | 4,942.3 |
|
Other Property, Plant and Equipment | | 662.3 |
| | 574.8 |
|
Construction Work in Progress | | 485.3 |
| | 432.1 |
|
Total Property, Plant and Equipment | | 8,953.4 |
| | 8,493.5 |
|
Accumulated Depreciation and Amortization | | 2,256.1 |
| | 2,218.6 |
|
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | 6,697.3 |
| | 6,274.9 |
|
| | | | |
OTHER NONCURRENT ASSETS | | | | |
Regulatory Assets | | 372.2 |
| | 387.5 |
|
Securitized Assets | | — |
| | 12.9 |
|
Deferred Charges and Other Noncurrent Assets | | 320.3 |
| | 441.0 |
|
TOTAL OTHER NONCURRENT ASSETS | | 692.5 |
| | 841.4 |
|
| | | | |
TOTAL ASSETS | | $ | 7,620.6 |
| | $ | 7,435.9 |
|
|
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 126.
|
OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
September 30, 20192020 and December 31, 20182019
(dollars in millions)
(Unaudited)
| | | | | | | | | | | | | | |
| | September 30, | | December 31, |
| | 2020 | | 2019 |
CURRENT LIABILITIES | | | | |
Advances from Affiliates | | $ | 215.9 | | | $ | 131.0 | |
Accounts Payable: | | | | |
General | | 184.5 | | | 233.7 | |
Affiliated Companies | | 90.7 | | | 103.6 | |
Long-term Debt Due Within One Year – Nonaffiliated | | 0.1 | | | 0.1 | |
Risk Management Liabilities | | 8.2 | | | 7.3 | |
Customer Deposits | | 58.2 | | | 70.6 | |
Accrued Taxes | | 314.5 | | | 587.9 | |
| | | | |
Obligations Under Operating Leases | | 12.5 | | | 12.5 | |
Other Current Liabilities | | 141.1 | | | 151.2 | |
TOTAL CURRENT LIABILITIES | | 1,025.7 | | | 1,297.9 | |
| | | | |
NONCURRENT LIABILITIES | | | | |
Long-term Debt – Nonaffiliated | | 2,429.8 | | | 2,081.9 | |
Long-term Risk Management Liabilities | | 105.1 | | | 96.3 | |
Deferred Income Taxes | | 904.6 | | | 849.4 | |
Regulatory Liabilities and Deferred Investment Tax Credits | | 1,018.5 | | | 1,090.9 | |
| | | | |
Obligations Under Operating Leases | | 76.7 | | | 76.0 | |
Deferred Credits and Other Noncurrent Liabilities | | 48.3 | | | 42.7 | |
TOTAL NONCURRENT LIABILITIES | | 4,583.0 | | | 4,237.2 | |
| | | | |
TOTAL LIABILITIES | | 5,608.7 | | | 5,535.1 | |
| | | | |
Rate Matters (Note 4) | | | | |
Commitments and Contingencies (Note 5) | | | | |
| | | | |
COMMON SHAREHOLDER’S EQUITY | | | | |
Common Stock –NaN Par Value: | | | | |
Authorized – 40,000,000 Shares | | | | |
Outstanding – 27,952,473 Shares | | 321.2 | | | 321.2 | |
Paid-in Capital | | 838.8 | | | 838.8 | |
Retained Earnings | | 1,498.2 | | | 1,348.5 | |
| | | | |
TOTAL COMMON SHAREHOLDER’S EQUITY | | 2,658.2 | | | 2,508.5 | |
| | | | |
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY | | $ | 8,266.9 | | | $ | 8,043.6 | |
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134. | | | | |
|
| | | | | | | | |
| | September 30, | | December 31, |
| | 2019 | | 2018 |
CURRENT LIABILITIES | | | | |
Advances from Affiliates | | $ | 17.6 |
| | $ | 114.1 |
|
Accounts Payable: | | |
| | |
|
General | | 203.1 |
| | 211.9 |
|
Affiliated Companies | | 100.2 |
| | 102.9 |
|
Long-term Debt Due Within One Year – Nonaffiliated (September 30, 2019 and December 31, 2018 Amounts Include $0 and $47.8, Respectively, Related to Ohio Phase-in-Recovery Funding) | | 0.1 |
| | 47.9 |
|
Risk Management Liabilities | | 7.2 |
| | 5.8 |
|
Customer Deposits | | 88.2 |
| | 113.1 |
|
Accrued Taxes | | 294.3 |
| | 537.8 |
|
Accrued Interest | | 44.7 |
| | 31.4 |
|
Obligations Under Operating Leases | | 12.8 |
| | — |
|
Other Current Liabilities | | 99.4 |
| | 182.8 |
|
TOTAL CURRENT LIABILITIES | | 867.6 |
| | 1,347.7 |
|
| | | | |
NONCURRENT LIABILITIES | | | | |
Long-term Debt – Nonaffiliated | | 2,113.8 |
| | 1,668.7 |
|
Long-term Risk Management Liabilities | | 105.7 |
| | 93.8 |
|
Deferred Income Taxes | | 805.0 |
| | 763.3 |
|
Regulatory Liabilities and Deferred Investment Tax Credits | | 1,143.6 |
| | 1,221.2 |
|
Obligations Under Operating Leases | | 75.9 |
| | — |
|
Deferred Credits and Other Noncurrent Liabilities | | 49.9 |
| | 43.8 |
|
TOTAL NONCURRENT LIABILITIES | | 4,293.9 |
| | 3,790.8 |
|
| | | | |
TOTAL LIABILITIES | | 5,161.5 |
| | 5,138.5 |
|
| | | | |
Rate Matters (Note 4) | |
| |
|
Commitments and Contingencies (Note 5) | |
| |
|
| | | | |
COMMON SHAREHOLDER’S EQUITY | | | | |
Common Stock – No Par Value: | | | | |
Authorized – 40,000,000 Shares | | |
| | |
Outstanding – 27,952,473 Shares | | 321.2 |
| | 321.2 |
|
Paid-in Capital | | 838.8 |
| | 838.8 |
|
Retained Earnings | | 1,299.1 |
| | 1,136.4 |
|
Accumulated Other Comprehensive Income (Loss) | | — |
| | 1.0 |
|
TOTAL COMMON SHAREHOLDER’S EQUITY | | 2,459.1 |
| | 2,297.4 |
|
| | | | |
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY | | $ | 7,620.6 |
| | $ | 7,435.9 |
|
|
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 126.
|
OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 20192020 and 20182019
(in millions)
(Unaudited)
| | | | | | | | | | | | | | |
| | Nine Months Ended September 30, | | |
| | 2020 | | 2019 |
OPERATING ACTIVITIES | | | | |
Net Income | | $ | 215.0 | | | $ | 247.7 | |
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | | | |
Depreciation and Amortization | | 204.4 | | | 176.8 | |
Amortization of Generation Deferrals | | 0 | | | 65.3 | |
Deferred Income Taxes | | 35.6 | | | 16.8 | |
| | | | |
Allowance for Equity Funds Used During Construction | | (9.3) | | | (14.1) | |
Mark-to-Market of Risk Management Contracts | | 9.7 | | | 13.3 | |
| | | | |
Property Taxes | | 225.1 | | | 197.7 | |
Refund of Global Settlement | | 0 | | | (12.4) | |
Reversal of Regulatory Provision | | 0 | | | (56.2) | |
| | | | |
Change in Other Noncurrent Assets | | (93.8) | | | (47.5) | |
Change in Other Noncurrent Liabilities | | (58.3) | | | (51.1) | |
Changes in Certain Components of Working Capital: | | | | |
Accounts Receivable, Net | | 33.4 | | | 90.0 | |
Materials and Supplies | | (19.8) | | | (9.6) | |
Accounts Payable | | (19.9) | | | (12.3) | |
Accrued Taxes, Net | | (266.2) | | | (245.9) | |
Other Current Assets | | (2.5) | | | (9.0) | |
Other Current Liabilities | | (23.3) | | | (40.0) | |
Net Cash Flows from Operating Activities | | 230.1 | | | 309.5 | |
| | | | |
INVESTING ACTIVITIES | | | | |
Construction Expenditures | | (604.6) | | | (570.6) | |
| | | | |
Other Investing Activities | | 14.1 | | | 20.0 | |
Net Cash Flows Used for Investing Activities | | (590.5) | | | (550.6) | |
| | | | |
FINANCING ACTIVITIES | | | | |
Issuance of Long-term Debt – Nonaffiliated | | 347.0 | | | 444.3 | |
Change in Advances from Affiliates, Net | | 84.9 | | | (96.5) | |
Retirement of Long-term Debt – Nonaffiliated | | (0.1) | | | (48.0) | |
Principal Payments for Finance Lease Obligations | | (3.5) | | | (2.6) | |
Dividends Paid on Common Stock | | (65.6) | | | (85.0) | |
Other Financing Activities | | 0.6 | | | 1.1 | |
Net Cash Flows from Financing Activities | | 363.3 | | | 213.3 | |
| | | | |
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash for Securitized Funding | | 2.9 | | | (27.8) | |
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at Beginning of Period | | 3.7 | | | 32.5 | |
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at End of Period | | $ | 6.6 | | | $ | 4.7 | |
| | | | |
SUPPLEMENTARY INFORMATION | | | | |
Cash Paid for Interest, Net of Capitalized Amounts | | $ | 69.7 | | | $ | 61.3 | |
Net Cash Paid (Received) for Income Taxes | | (6.0) | | | 25.7 | |
Noncash Acquisitions Under Finance Leases | | 5.2 | | | 8.6 | |
Construction Expenditures Included in Current Liabilities as of September 30, | | 75.9 | | | 99.9 | |
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134. | | | | |
|
| | | | | | | | |
| | Nine Months Ended September 30, |
| | 2019 | | 2018 |
OPERATING ACTIVITIES | | |
| | |
|
Net Income | | $ | 247.7 |
| | $ | 237.1 |
|
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | |
| | |
|
Depreciation and Amortization | | 176.8 |
| | 200.3 |
|
Amortization of Generation Deferrals | | 65.3 |
| | 171.9 |
|
Deferred Income Taxes | | 16.8 |
| | (71.9 | ) |
Allowance for Equity Funds Used During Construction | | (14.1 | ) | | (7.8 | ) |
Mark-to-Market of Risk Management Contracts | | 13.3 |
| | (37.1 | ) |
Property Taxes | | 197.7 |
| | 191.1 |
|
Refund of Global Settlement | | (12.4 | ) | | (5.5 | ) |
Reversal of Regulatory Provision | | (56.2 | ) | | — |
|
Change in Regulatory Assets | | (28.1 | ) | | 180.9 |
|
Change in Other Noncurrent Assets | | (19.4 | ) | | 0.8 |
|
Change in Other Noncurrent Liabilities | | (51.1 | ) | | 62.5 |
|
Changes in Certain Components of Working Capital: | | |
| | |
|
Accounts Receivable, Net | | 90.0 |
| | 21.3 |
|
Materials and Supplies | | (9.6 | ) | | (3.7 | ) |
Accounts Payable | | (12.3 | ) | | (31.8 | ) |
Accrued Taxes, Net | | (245.9 | ) | | (210.6 | ) |
Other Current Assets | | (9.0 | ) | | 7.6 |
|
Other Current Liabilities | | (40.0 | ) | | (4.3 | ) |
Net Cash Flows from Operating Activities | | 309.5 |
| | 700.8 |
|
| | | | |
INVESTING ACTIVITIES | | |
| | |
|
Construction Expenditures | | (570.6 | ) | | (538.5 | ) |
Other Investing Activities | | 20.0 |
| | 15.5 |
|
Net Cash Flows Used for Investing Activities | | (550.6 | ) | | (523.0 | ) |
| | | | |
FINANCING ACTIVITIES | | |
| | |
|
Issuance of Long-term Debt – Nonaffiliated | | 444.3 |
| | 392.8 |
|
Change in Advances from Affiliates, Net | | (96.5 | ) | | 155.1 |
|
Retirement of Long-term Debt – Nonaffiliated | | (48.0 | ) | | (397.0 | ) |
Principal Payments for Finance Lease Obligations | | (2.6 | ) | | (2.9 | ) |
Dividends Paid on Common Stock | | (85.0 | ) | | (337.5 | ) |
Other Financing Activities | | 1.1 |
| | 0.7 |
|
Net Cash Flows from (Used for) Financing Activities | | 213.3 |
| | (188.8 | ) |
| | | | |
Net Decrease in Cash, Cash Equivalents and Restricted Cash for Securitized Funding | | (27.8 | ) | | (11.0 | ) |
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at Beginning of Period | | 32.5 |
| | 29.7 |
|
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at End of Period | | $ | 4.7 |
| | $ | 18.7 |
|
| | | | |
SUPPLEMENTARY INFORMATION | | |
| | |
|
Cash Paid for Interest, Net of Capitalized Amounts | | $ | 61.3 |
| | $ | 67.3 |
|
Net Cash Paid for Income Taxes | | 25.7 |
| | 54.1 |
|
Noncash Acquisitions Under Finance Leases | | 8.6 |
| | 3.0 |
|
Construction Expenditures Included in Current Liabilities as of September 30, | | 99.9 |
| | 66.0 |
|
|
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page
126. |
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 | | |
| September 30, | | | | September 30, | | |
| 2020 | | 2019 | | 2020 | | 2019 |
| (in millions of KWhs) | | | | | | |
Retail: | | | | | | | |
Residential | 2,019 | | | 2,172 | | | 4,838 | | | 4,981 | |
Commercial | 1,358 | | | 1,497 | | | 3,549 | | | 3,818 | |
Industrial | 1,461 | | | 1,642 | | | 4,299 | | | 4,665 | |
Miscellaneous | 347 | | | 378 | | | 912 | | | 950 | |
Total Retail | 5,185 | | | 5,689 | | | 13,598 | | | 14,414 | |
| | | | | | | |
Wholesale | 130 | | | 224 | | | 261 | | | 617 | |
| | | | | | | |
Total KWhs | 5,315 | | | 5,913 | | | 13,859 | | | 15,031 | |
|
| | | | | | | | | | | |
| Three Months Ended | | Nine Months Ended |
| September 30, | | September 30, |
| 2019 | | 2018 | | 2019 | | 2018 |
| (in millions of KWhs) |
Retail: | |
| | |
| | |
| | |
|
Residential | 2,172 |
| | 2,005 |
| | 4,981 |
| | 5,133 |
|
Commercial | 1,497 |
| | 1,433 |
| | 3,818 |
| | 3,864 |
|
Industrial | 1,642 |
| | 1,604 |
| | 4,665 |
| | 4,559 |
|
Miscellaneous | 378 |
| | 362 |
| | 950 |
| | 973 |
|
Total Retail (a) | 5,689 |
| | 5,404 |
| | 14,414 |
| | 14,529 |
|
| | | | | | | |
Wholesale | 224 |
| | 182 |
| | 617 |
| | 544 |
|
| | | | | | | |
Total KWhs | 5,913 |
| | 5,586 |
| | 15,031 |
| | 15,073 |
|
| |
(a) | 2018 KWhs have been revised to reflect the reclassification of certain customer accounts between Retail classes. This reclassification did not impact previously reported Total Retail KWhs. Management concluded that these prior period disclosure only errors were immaterial individually and in the aggregate. |
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 | | |
| September 30, | | | | September 30, | | |
| 2020 | | 2019 | | 2020 | | 2019 |
| (in degree days) | | | | | | |
Actual – Heating (a) | 1 | | | — | | | 874 | | | 1,199 | |
Normal – Heating (b) | 1 | | | 1 | | | 1,078 | | | 1,077 | |
| | | | | | | |
Actual – Cooling (c) | 1,274 | | | 1,593 | | | 1,979 | | | 2,206 | |
Normal – Cooling (b) | 1,412 | | | 1,397 | | | 2,088 | | | 2,072 | |
(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.
|
| | | | | | | | | | | |
| Three Months Ended | | Nine Months Ended |
| September 30, | | September 30, |
| 2019 | | 2018 | | 2019 | | 2018 |
| (in degree days) |
Actual – Heating (a) | — |
| | — |
| | 1,199 |
| | 1,161 |
|
Normal – Heating (b) | 1 |
| | 1 |
| | 1,077 |
| | 1,082 |
|
| | | | | | | |
Actual – Cooling (c) | 1,593 |
| | 1,433 |
| | 2,206 |
| | 2,352 |
|
Normal – Cooling (b) | 1,397 |
| | 1,396 |
| | 2,072 |
| | 2,063 |
|
| |
(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 20192020 Compared to Third Quarter of 20182019
|
| | | | |
Reconciliation of Third Quarter of 2018 to Third Quarter of 2019 |
Net Income |
(in millions) |
| | |
Third Quarter of 2018 | | $ | 60.4 |
|
| | |
Changes in Gross Margin: | | |
Retail Margins (a) | | 22.0 |
|
Margins from Off-system Sales | | 0.8 |
|
Transmission Revenues | | (3.7 | ) |
Total Change in Gross Margin | | 19.1 |
|
| | |
Changes in Expenses and Other: | | |
|
Other Operation and Maintenance | | 19.5 |
|
Depreciation and Amortization | | 3.2 |
|
Taxes Other Than Income Taxes | | (0.3 | ) |
Other Income (Expense) | | 1.4 |
|
Interest Expense | | 0.3 |
|
Total Change in Expenses and Other | | 24.1 |
|
| | |
|
Income Tax Expense | | (3.3 | ) |
| | |
|
Third Quarter of 2019 | | $ | 100.3 |
|
| | | | | | | | |
(a)Reconciliation of Third Quarter of 2019 to Third Quarter of 2020 | Includes firm wholesale sales to municipals | |
Net Income | | |
(in millions) | | |
| | |
Third Quarter of 2019 | | $ | 100.3 | |
| | |
Changes in Gross Margin: | | |
Retail Margins (a) | | (20.7) | |
Margins from Off-system Sales | | (1.3) | |
Transmission Revenues | | (0.5) | |
Other Revenues | | (0.2) | |
Total Change in Gross Margin | | (22.7) | |
| | |
Changes in Expenses and cooperatives.Other: | | |
Other Operation and Maintenance | | (2.5) | |
Depreciation and Amortization | | (1.0) | |
Taxes Other Than Income Taxes | | (1.0) | |
Interest Income | | (0.4) | |
| | |
Allowance for Equity Funds Used During Construction | | 0.5 | |
| | |
| | |
Interest Expense | | 1.5 | |
Total Change in Expenses and Other | | (2.9) | |
| | |
Income Tax Expense | | 5.6 | |
| | |
Third Quarter of 2020 | | $ | 80.3 | |
(a)Includes firm wholesale sales to municipals and cooperatives.
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, and purchased electricity were as follows:
•Retail Margins decreased $21 million primarily due to the following:
•An $18 million decrease in weather-related usage due to a 20% decrease in cooling degree-days.
•A $4 million decrease in revenue from rate riders. This decrease was partially offset in other expense items below.
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 $4 million increase in transmission expenses due to an increase in recoverable SPP expenses. This increase was partially offset in Retail Margins above.
•A $2 million increase in customer-related expenses primarily related to energy efficiency programs. This increase was partially offset in Retail Margins above.
These increases were partially offset by:
•A $4 million decrease in distribution expenses.
•Income Tax Expense decreased $6 million primarily due to a decrease in pretax book income.
Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019
| | | | | | | | |
Reconciliation of Nine Months Ended September 30, 2019 to Nine Months Ended September 30, 2020 | | |
Net Income | | |
(in millions) | | |
| | |
Nine Months Ended September 30, 2019 | | $ | 148.4 | |
| | |
Changes in Gross Margin: | | |
Retail Margins (a) | | (15.1) | |
Margin from Off-system Sales | | (1.7) | |
Transmission Revenues | | (0.8) | |
Other Revenues | | 3.4 | |
Total Change in Gross Margin | | (14.2) | |
| | |
Changes in Expenses and Other: | | |
Other Operation and Maintenance | | (21.3) | |
Depreciation and Amortization | | (4.4) | |
Taxes Other Than Income Taxes | | (2.8) | |
Interest Income | | (0.5) | |
| | |
Allowance for Equity Funds Used During Construction | | 1.7 | |
| | |
| | |
Interest Expense | | 4.4 | |
Total Change in Expenses and Other | | (22.9) | |
| | |
Income Tax Expense | | 5.1 | |
| | |
Nine Months Ended September 30, 2020 | | $ | 116.4 | |
(a)Includes firm wholesale sales to municipals and cooperatives.
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, and purchased electricity were as follows:
•Retail Margins decreased $15 million primarily due to the following:
•A $15 million decrease in weather-related usage due to a 10% decrease in cooling degree-days.
•A $10 million decrease in revenue from rate riders. This decrease was partially offset in other expense items below.
•A $7 million decrease due to customer refunds related to Tax Reform. This decrease is partially offset in Income Tax Expense below.
These decreases were partially offset by:
•A $10 million increase due to new base rates implemented in April 2019.
•A $7 million increase in weather-normalized margins.
•Other Revenues increased $3 million primarily due to business development revenue. This increase was offset in other expense items below.
Expenses and Other and Income Tax Expense changed between years as follows:
•Other Operation and Maintenance expenses increased $21 million primarily due to the following:
•A $20 million increase in transmission expenses primarily due to the annual transmission formula rate true-up. This increase was partially offset in Retail Margins above.
•A $5 million increase in customer-related expenses primarily related to energy efficiency programs. This increase was partially offset in Retail Margins above.
•A $4 million increase in business development expenses. This increase was partially offset in Other Revenues above.
•A $4 million increase in maintenance of overhead lines for non-storm related expenses.
These increases were partially offset by:
•A $7 million decrease in expenses at various generation plants.
•A $5 million decrease due to the capitalization of previously expensed North Central Wind Energy Facilities costs.
•Depreciation and Amortization expenses increased $4 million primarily due to a higher depreciable base.
•Interest Expense decreased $4 million primarily due to lower interest rates on long-term debt.
•Income Tax Expense decreased $5 million primarily due to a decrease in pretax book income, partially offset by a decrease in amortization of Excess ADIT. The decrease in amortization of Excess ADIT is partially offset in Retail Margins above.
PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2020 and 2019
(in millions)
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | | | Nine Months Ended | | |
| | September 30, | | | | September 30, | | |
| | 2020 | | 2019 | | 2020 | | 2019 |
REVENUES | | | | | | | | |
Electric Generation, Transmission and Distribution | | $ | 379.8 | | | $ | 490.5 | | | $ | 976.3 | | | $ | 1,164.3 | |
Sales to AEP Affiliates | | 1.4 | | | 1.3 | | | 3.8 | | | 5.0 | |
Other Revenues | | 1.0 | | | 1.2 | | | 8.0 | | | 4.6 | |
TOTAL REVENUES | | 382.2 | | | 493.0 | | | 988.1 | | | 1,173.9 | |
| | | | | | | | |
EXPENSES | | | | | | | | |
Fuel and Other Consumables Used for Electric Generation | | 20.9 | | | 98.4 | | | 36.2 | | | 181.2 | |
Purchased Electricity for Resale | | 104.7 | | | 115.3 | | | 314.1 | | | 340.7 | |
| | | | | | | | |
Other Operation | | 91.7 | | | 87.6 | | | 248.5 | | | 226.0 | |
Maintenance | | 19.9 | | | 21.5 | | | 68.9 | | | 70.1 | |
Depreciation and Amortization | | 40.1 | | | 39.1 | | | 129.8 | | | 125.4 | |
Taxes Other Than Income Taxes | | 12.1 | | | 11.1 | | | 35.8 | | | 33.0 | |
TOTAL EXPENSES | | 289.4 | | | 373.0 | | | 833.3 | | | 976.4 | |
| | | | | | | | |
OPERATING INCOME | | 92.8 | | | 120.0 | | | 154.8 | | | 197.5 | |
| | | | | | | | |
Other Income (Expense): | | | | | | | | |
Interest Income | | 0 | | | 0.4 | | | 0.1 | | | 0.6 | |
| | | | | | | | |
Allowance for Equity Funds Used During Construction | | 1.3 | | | 0.8 | | | 3.2 | | | 1.5 | |
| | | | | | | | |
Non-Service Cost Components of Net Periodic Benefit Cost | | 2.1 | | | 2.1 | | | 6.3 | | | 6.3 | |
Interest Expense | | (14.6) | | | (16.1) | | | (45.9) | | | (50.3) | |
| | | | | | | | |
INCOME BEFORE INCOME TAX EXPENSE | | 81.6 | | | 107.2 | | | 118.5 | | | 155.6 | |
| | | | | | | | |
Income Tax Expense | | 1.3 | | | 6.9 | | | 2.1 | | | 7.2 | |
| | | | | | | | |
NET INCOME | | $ | 80.3 | | | $ | 100.3 | | | $ | 116.4 | | | $ | 148.4 | |
| | | | | | | | |
The common stock of PSO is wholly-owned by Parent. | | | | | | | | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134. | | | | | | | | |
PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 2020 and 2019
(in millions)
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | | | Nine Months Ended | | |
| | September 30, | | | | September 30, | | |
| | 2020 | | 2019 | | 2020 | | 2019 |
Net Income | | $ | 80.3 | | | $ | 100.3 | | | $ | 116.4 | | | $ | 148.4 | |
| | | | | | | | |
OTHER COMPREHENSIVE LOSS, NET OF TAXES | | | | | | | | |
Cash Flow Hedges, Net of Tax of $0 and $0 for the Three Months Ended September 30, 2020 and 2019, Respectively, and $(0.2) and $(0.2) for the Nine Months Ended September 30, 2020 and 2019, Respectively. | | (0.3) | | | (0.2) | | | (0.8) | | | (0.7) | |
| | | | | | | | |
TOTAL COMPREHENSIVE INCOME | | $ | 80.0 | | | $ | 100.1 | | | $ | 115.6 | | | $ | 147.7 | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134. | | | | | | | | |
PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Nine Months Ended September 30, 2020 and 2019
(in millions)
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Common Stock | | Paid-in Capital | | Retained Earnings | | Accumulated Other Comprehensive Income (Loss) | | Total |
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2018 | | $ | 157.2 | | | $ | 364.0 | | | $ | 724.7 | | | $ | 2.1 | | | $ | 1,248.0 | |
| | | | | | | | | | |
Common Stock Dividends | | | | | | (11.3) | | | | | (11.3) | |
| | | | | | | | | | |
Net Income | | | | | | 6.2 | | | | | 6.2 | |
Other Comprehensive Loss | | | | | | | | (0.2) | | | (0.2) | |
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2019 | | 157.2 | | | 364.0 | | | 719.6 | | | 1.9 | | | 1,242.7 | |
| | | | | | | | | | |
| | | | | | | | | | |
Net Income | | | | | | 41.9 | | | | | 41.9 | |
Other Comprehensive Loss | | | | | | | | (0.3) | | | (0.3) | |
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2019 | | 157.2 | | | 364.0 | | | 761.5 | | | 1.6 | | | 1,284.3 | |
| | | | | | | | | | |
| | | | | | | | | | |
Net Income | | | | | | 100.3 | | | | | 100.3 | |
Other Comprehensive Loss | | | | | | | | (0.2) | | | (0.2) | |
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2019 | | $ | 157.2 | | | $ | 364.0 | | | $ | 861.8 | | | $ | 1.4 | | | $ | 1,384.4 | |
| | | | | | | | | | |
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2019 | | $ | 157.2 | | | $ | 364.0 | | | $ | 851.0 | | | $ | 1.1 | | | $ | 1,373.3 | |
| | | | | | | | | | |
| | | | | | | | | | |
ASU 2016-13 Adoption | | | | | | 0.3 | | | | | 0.3 | |
Net Loss | | | | | | (10.3) | | | | | (10.3) | |
Other Comprehensive Loss | | | | | | | | (0.2) | | | (0.2) | |
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2020 | | 157.2 | | | 364.0 | | | 841.0 | | | 0.9 | | | 1,363.1 | |
| | | | | | | | | | |
| | | | | | | | | | |
Net Income | | | | | | 46.4 | | | | | 46.4 | |
Other Comprehensive Loss | | | | | | | | (0.3) | | | (0.3) | |
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2020 | | 157.2 | | | 364.0 | | | 887.4 | | | 0.6 | | | 1,409.2 | |
| | | | | | | | | | |
| | | | | | | | | | |
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 | |
| | | | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134. | | | | | | | | | | |
PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
ASSETS
September 30, 2020 and December 31, 2019
(in millions)
(Unaudited)
| | | | | | | | | | | | | | |
| | September 30, | | December 31, |
| | 2020 | | 2019 |
CURRENT ASSETS | | | | |
Cash and Cash Equivalents | | $ | 3.0 | | | $ | 1.5 | |
Advances to Affiliates | | 0 | | | 38.8 | |
Accounts Receivable: | | | | |
Customers | | 25.2 | | | 28.9 | |
Affiliated Companies | | 27.1 | | | 20.6 | |
Miscellaneous | | 3.1 | | | 0.6 | |
Allowance for Uncollectible Accounts | | 0 | | | (0.3) | |
Total Accounts Receivable | | 55.4 | | | 49.8 | |
Fuel | | 22.8 | | | 12.2 | |
Materials and Supplies | | 53.4 | | | 46.8 | |
Risk Management Assets | | 16.6 | | | 15.8 | |
| | | | |
Accrued Tax Benefits | | 0.6 | | | 11.3 | |
| | | | |
Prepayments and Other Current Assets | | 11.8 | | | 12.0 | |
TOTAL CURRENT ASSETS | | 163.6 | | | 188.2 | |
| | | | |
PROPERTY, PLANT AND EQUIPMENT | | | | |
Electric: | | | | |
Generation | | 1,474.1 | | | 1,574.6 | |
Transmission | | 981.2 | | | 948.5 | |
Distribution | | 2,799.5 | | | 2,684.8 | |
Other Property, Plant and Equipment | | 381.8 | | | 342.1 | |
Construction Work in Progress | | 147.2 | | | 133.4 | |
Total Property, Plant and Equipment | | 5,783.8 | | | 5,683.4 | |
Accumulated Depreciation and Amortization | | 1,578.3 | | | 1,580.1 | |
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | 4,205.5 | | | 4,103.3 | |
| | | | |
OTHER NONCURRENT ASSETS | | | | |
Regulatory Assets | | 388.9 | | | 375.2 | |
| | | | |
Employee Benefits and Pension Assets | | 44.8 | | | 43.9 | |
Operating Lease Assets | | 40.5 | | | 36.8 | |
Deferred Charges and Other Noncurrent Assets | | 15.9 | | | 4.1 | |
TOTAL OTHER NONCURRENT ASSETS | | 490.1 | | | 460.0 | |
| | | | |
TOTAL ASSETS | | $ | 4,859.2 | | | $ | 4,751.5 | |
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134. | | | | |
PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
September 30, 2020 and December 31, 2019
(Unaudited)
| | | | | | | | | | | | | | |
| | September 30, | | December 31, |
| | 2020 | | 2019 |
| | (in millions) | | |
CURRENT LIABILITIES | | | | |
Advances from Affiliates | | $ | 77.8 | | | $ | 0 | |
Accounts Payable: | | | | |
General | | 106.7 | | | 134.3 | |
Affiliated Companies | | 41.0 | | | 59.3 | |
Long-term Debt Due Within One Year – Nonaffiliated | | 250.5 | | | 13.2 | |
Risk Management Liabilities | | 0.5 | | | 0 | |
Customer Deposits | | 56.2 | | | 58.9 | |
Accrued Taxes | | 49.1 | | | 22.9 | |
| | | | |
Obligations Under Operating Leases | | 6.2 | | | 5.8 | |
Regulatory Liability for Over-Recovered Fuel Costs | | 17.3 | | | 63.9 | |
| | | | |
Other Current Liabilities | | 72.8 | | | 87.5 | |
TOTAL CURRENT LIABILITIES | | 678.1 | | | 445.8 | |
| | | | |
NONCURRENT LIABILITIES | | | | |
Long-term Debt – Nonaffiliated | | 1,123.2 | | | 1,373.0 | |
| | | | |
Deferred Income Taxes | | 649.6 | | | 628.3 | |
Regulatory Liabilities and Deferred Investment Tax Credits | | 816.4 | | | 837.2 | |
Asset Retirement Obligations | | 46.4 | | | 44.5 | |
| | | | |
Obligations Under Operating Leases | | 34.3 | | | 31.0 | |
Deferred Credits and Other Noncurrent Liabilities | | 22.0 | | | 18.4 | |
TOTAL NONCURRENT LIABILITIES | | 2,691.9 | | | 2,932.4 | |
| | | | |
TOTAL LIABILITIES | | 3,370.0 | | | 3,378.2 | |
| | | | |
Rate Matters (Note 4) | | | | |
Commitments and Contingencies (Note 5) | | | | |
| | | | |
COMMON SHAREHOLDER’S EQUITY | | | | |
Common Stock – Par Value – $15 Per Share: | | | | |
Authorized – 11,000,000 Shares | | | | |
Issued – 10,482,000 Shares | | | | |
Outstanding – 9,013,000 Shares | | 157.2 | | | 157.2 | |
Paid-in Capital | | 364.0 | | | 364.0 | |
Retained Earnings | | 967.7 | | | 851.0 | |
Accumulated Other Comprehensive Income (Loss) | | 0.3 | | | 1.1 | |
TOTAL COMMON SHAREHOLDER’S EQUITY | | 1,489.2 | | | 1,373.3 | |
| | | | |
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY | | $ | 4,859.2 | | | $ | 4,751.5 | |
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134. | | | | |
PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2020 and 2019
(in millions)
(Unaudited)
| | | | | | | | | | | | | | |
| | Nine Months Ended September 30, | | |
| | 2020 | | 2019 |
OPERATING ACTIVITIES | | | | |
Net Income | | $ | 116.4 | | | $ | 148.4 | |
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | | | |
Depreciation and Amortization | | 129.8 | | | 125.4 | |
Deferred Income Taxes | | (3.2) | | | (9.7) | |
| | | | |
Allowance for Equity Funds Used During Construction | | (3.2) | | | (1.5) | |
Mark-to-Market of Risk Management Contracts | | (0.3) | | | (12.0) | |
| | | | |
Property Taxes | | (10.6) | | | (9.6) | |
Deferred Fuel Over/Under-Recovery, Net | | (46.6) | | | 49.8 | |
| | | | |
Change in Other Noncurrent Assets | | (7.2) | | | 4.6 | |
Change in Other Noncurrent Liabilities | | 6.1 | | | (0.2) | |
Changes in Certain Components of Working Capital: | | | | |
Accounts Receivable, Net | | (5.6) | | | 9.1 | |
Fuel, Materials and Supplies | | (17.2) | | | (1.9) | |
Accounts Payable | | (26.1) | | | (5.8) | |
Accrued Taxes, Net | | 36.9 | | | 19.0 | |
Other Current Assets | | (0.1) | | | (2.4) | |
Other Current Liabilities | | (16.4) | | | 1.1 | |
Net Cash Flows from Operating Activities | | 152.7 | | | 314.3 | |
| | | | |
INVESTING ACTIVITIES | | | | |
Construction Expenditures | | (256.4) | | | (198.7) | |
Change in Advances to Affiliates, Net | | 38.8 | | | (95.1) | |
Other Investing Activities | | 3.9 | | | 2.1 | |
Net Cash Flows Used for Investing Activities | | (213.7) | | | (291.7) | |
| | | | |
FINANCING ACTIVITIES | | | | |
Issuance of Long-term Debt – Nonaffiliated | | 0 | | | 349.8 | |
Change in Advances from Affiliates, Net | | 77.8 | | | (105.5) | |
Retirement of Long-term Debt – Nonaffiliated | | (13.0) | | | (250.4) | |
| | | | |
Principal Payments for Finance Lease Obligations | | (2.7) | | | (2.2) | |
Dividends Paid on Common Stock | | 0 | | | (11.3) | |
Other Financing Activities | | 0.4 | | | (2.1) | |
Net Cash Flows from (Used for) Financing Activities | | 62.5 | | | (21.7) | |
| | | | |
Net Increase in Cash and Cash Equivalents | | 1.5 | | | 0.9 | |
Cash and Cash Equivalents at Beginning of Period | | 1.5 | | | 2.0 | |
Cash and Cash Equivalents at End of Period | | $ | 3.0 | | | $ | 2.9 | |
| | | | |
SUPPLEMENTARY INFORMATION | | | | |
Cash Paid for Interest, Net of Capitalized Amounts | | $ | 45.5 | | | $ | 46.5 | |
Net Cash Paid (Received) for Income Taxes | | (9.5) | | | 16.0 | |
Noncash Acquisitions Under Finance Leases | | 3.0 | | | 3.4 | |
Construction Expenditures Included in Current Liabilities as of September 30, | | 23.5 | | | 31.5 | |
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134. | | | | |
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 | | |
| September 30, | | | | September 30, | | |
| 2020 | | 2019 | | 2020 | | 2019 |
| (in millions of KWhs) | | | | | | |
Retail: | | | | | | | |
Residential | 1,950 | | | 2,071 | | | 4,702 | | | 4,896 | |
Commercial | 1,552 | | | 1,746 | | | 4,016 | | | 4,430 | |
Industrial | 1,185 | | | 1,414 | | | 3,614 | | | 4,020 | |
Miscellaneous | 19 | | | 19 | | | 59 | | | 59 | |
Total Retail | 4,706 | | | 5,250 | | | 12,391 | | | 13,405 | |
| | | | | | | |
Wholesale | 1,571 | | | 1,831 | | | 4,081 | | | 5,317 | |
| | | | | | | |
Total KWhs | 6,277 | | | 7,081 | | | 16,472 | | | 18,722 | |
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 | | |
| September 30, | | | | September 30, | | |
| 2020 | | 2019 | | 2020 | | 2019 |
| (in degree days) | | | | | | |
Actual – Heating (a) | — | | | — | | | 522 | | | 732 | |
Normal – Heating (b) | 1 | | | 1 | | | 724 | | | 725 | |
| | | | | | | |
Actual – Cooling (c) | 1,308 | | | 1,552 | | | 2,051 | | | 2,263 | |
Normal – Cooling (b) | 1,420 | | | 1,408 | | | 2,200 | | | 2,187 | |
(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 2020 Compared to Third Quarter of 2019
| | | | | | | | |
Reconciliation of Third Quarter of 2019 to Third Quarter of 2020 | | |
Earnings Attributable to SWEPCo Common Shareholder | | |
(in millions) | | |
| | |
Third Quarter of 2019 | | $ | 110.5 | |
| | |
Changes in Gross Margin: | | |
Retail Margins (a) | | (8.9) | |
Margins from Off-system Sales | | (0.3) | |
Transmission Revenues | | 2.5 | |
Other Revenues | | (0.6) | |
Total Change in Gross Margin | | (7.3) | |
| | |
Changes in Expenses and Other: | | |
Other Operation and Maintenance | | 0.3 | |
| | |
Depreciation and Amortization | | (5.3) | |
Taxes Other Than Income Taxes | | (0.5) | |
| | |
Allowance for Equity Funds Used During Construction | | 1.8 | |
| | |
| | |
Interest Expense | | (0.1) | |
Total Change in Expenses and Other | | (3.8) | |
| | |
Income Tax Expense | | (11.5) | |
Equity Earnings of Unconsolidated Subsidiary | | (0.1) | |
Net Income Attributable to Noncontrolling Interest | | 0.1 | |
| | |
Third Quarter of 2020 | | $ | 87.9 | |
(a)Includes firm wholesale sales to municipals and cooperatives.
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, and purchased electricity were as follows:
•Retail Margins decreased $9 million primarily due to the following:
•A $17 million decrease in weather-related usage primarily due to a 16% decrease in cooling degree days.
•An $8 million decrease in weather-normalized margins.
These decreases were partially offset by:
•A $14 million increase primarily due to a base rate revenue increase in Arkansas.
Expenses and Other and Income Tax Expense changed between years as follows:
•Depreciation and Amortization expenses increased $5 million primarily due to a higher depreciable base and an increase in Arkansas depreciation rates beginning in January 2020. This increase was partially offset in Retail Margins above.
•Income Tax Expense increased $12 million primarily due to a decrease in amortization of Excess ADIT, partially offset by a decrease in pretax book income. The decrease in amortization of Excess ADIT was partially offset in Retail Margins above.
Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019
| | | | | | | | |
Reconciliation of Nine Months Ended September 30, 2019 to Nine Months Ended September 30, 2020 | | |
Earnings Attributable to SWEPCo Common Shareholder | | |
(in millions) | | |
| | |
Nine Months Ended September 30, 2019 | | $ | 144.5 | |
| | |
Changes in Gross Margin: | | |
Retail Margins (a) | | 4.4 | |
Margins from Off-system Sales | | (2.5) | |
Transmission Revenues | | 55.8 | |
Other Revenues | | (2.4) | |
Total Change in Gross Margin | | 55.3 | |
| | |
Changes in Expenses and Other: | | |
Other Operation and Maintenance | | (9.7) | |
| | |
Depreciation and Amortization | | (16.8) | |
Taxes Other Than Income Taxes | | (1.0) | |
Interest Income | | (0.3) | |
Allowance for Equity Funds Used During Construction | | 1.2 | |
Non-Service Cost Components of Net Periodic Benefit Cost | | (0.1) | |
| | |
Interest Expense | | 0.3 | |
Total Change in Expenses and Other | | (26.4) | |
| | |
Income Tax Expense | | (12.5) | |
Equity Earnings of Unconsolidated Subsidiary | | (0.1) | |
Net Income Attributable to Noncontrolling Interest | | 1.0 | |
| | |
Nine Months Ended September 30, 2020 | | $ | 161.8 | |
(a)Includes firm wholesale sales to municipals and cooperatives.
The major components of the increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased electricity were as follows:
| |
• | •Retail Margins increased $4 million primarily due to the following: • increased $22 million primarily due to the following: |
A $14$35 million increase primarily due to newrider increases in all jurisdictions and a base rates implementedrate revenue increase in April 2019.Arkansas. This increase was partially offset in other expense items below.
•A $9$6 million increase in weather-related usagemunicipal and cooperative revenues primarily due to an 11% increase in cooling degree days.formula rate true-ups.
•A $5$4 million increase in weather-normalized margins.recoverable fuel costs primarily due to timing of recovery.
These increases were partially offset by:
•A $7$23 million decrease in weather-related usage primarily due to customer refunds relateda 9% decrease in cooling degree days and a 29% decrease in heating degree days.
•A $17 million decrease in weather-normalized margins.
•Transmission Revenues increased $56 million primarily due to Tax Reform.the following:
•A $36 million increase as a result of the annual transmission formula rate true-up. This decreaseincrease was partially offset by an increase in Income Tax Expense below.transmission expenses in SPP.
| |
• | Transmission Revenues decreased $4 million primarily due to a decrease in SPP Base Plan Funding revenues.•A $14 million increase due to continued investment in transmission projects.
|
Expenses and Other and Income Tax Expense changed between years as follows:
| |
• | •Other Operation and Maintenance expenses increased $10 million primarily due to the following: • expenses decreased $20 million primarily due the following: |
A $9$20 million decreaseincrease in SPP transmission expenses primarily due to decreased SPPthe annual transmission services.
A $5 million decrease in Energy Efficiency program costs due to a change in amortizations of costs approved by the OCC.formula rate true-up. This decreaseincrease was offset in Retail MarginsTransmission Revenues above.
•A $3 million decrease due to Wind Catcher Project expenses incurred in 2018.
| |
• | Depreciation and Amortization expenses decreased $3 million primarily due to the refund of Excess ADIT.
|
| |
• | Income Tax Expense increased $3 million primarily due to an increase in pretax book income partially offset by an increase in amortization of Excess ADIT. The amortization of Excess ADIT was partially offset in Gross Margin above.
|
Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018
|
| | | | |
Reconciliation of Nine Months Ended September 30, 2018 to Nine Months Ended September 30, 2019 |
Net Income |
(in millions) |
| | |
Nine Months Ended September 30, 2018 | | $ | 89.8 |
|
| | |
|
Changes in Gross Margin: | | |
|
Retail Margins (a) | | 2.2 |
|
Margin from Off-system Sales | | 0.9 |
|
Transmission Revenues | | (5.6 | ) |
Other Revenues | | 1.8 |
|
Total Change in Gross Margin | | (0.7 | ) |
| | |
|
Changes in Expenses and Other: | | |
|
Other Operation and Maintenance | | 63.9 |
|
Depreciation and Amortization | | (4.9 | ) |
Taxes Other Than Income Taxes | | (0.4 | ) |
Other Income (Expense) | | 2.4 |
|
Non-Service Cost Components of Net Periodic Benefit Cost | | (0.2 | ) |
Interest Expense | | (2.9 | ) |
Total Change in Expenses and Other | | 57.9 |
|
| | |
|
Income Tax Expense | | 1.4 |
|
| | |
|
Nine Months Ended September 30, 2019 | | $ | 148.4 |
|
| |
(a) | Includes firm wholesale sales to municipals and cooperatives. |
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, and purchased electricity were as follows:
| |
• | Retail Margins increased $2 million primarily due to the following:
|
A $35$9 million increase due to new base rates implemented in April 2019administrative and March 2018.general expenses and employee-related expenses.
This increase wasThese increases were partially offset by:
A $13 million decrease due to customer refunds related to Tax Reform. This decrease was partially offset in Income Tax Expense below.
An $11 million decrease in weather-related usage due to a 6% decrease in cooling degree days.
A $10 million decrease in weather-normalized margins.
| |
• | Transmission Revenues decreased $6 million primarily due to a decrease in SPP Base Plan Funding revenues.
|
Expenses and Other and Income Tax Expense changed between years as follows:
| |
• | Other Operation and Maintenance expenses decreased $64 million primarily due to the following:
|
A $31 million decrease in transmission expenses primarily due to decreased SPP transmission services.
A $17 million decrease in Energy Efficiency program costs due to a change in amortizations of costs approved by the OCC. This decrease was offset in Retail Margins above.
A $12 million decrease due to Wind Catcher Project expenses incurred in 2018.
| |
• | Depreciation and Amortization expenses increased $5 million primarily due to the following:
|
•An $8 million increasedecrease due to the capitalization of previously expensed North Central Wind Energy Facilities costs.
•A $6 million decrease in generation plant maintenance expenses.
•A $4 million decrease in customer-related expenses primarily in energy efficiency programs. This decrease is offset in Retail Margins above.
•Depreciation and Amortization expenses increased $17 million primarily due to a higher depreciable base and newan increase in Arkansas depreciation rates implementedbeginning in March 2018.
January 2020. This increase was partially offset by:in Retail Margins above.
•A $3Income Tax Expense increased $13 million decreaseprimarily due to the refunda decrease in amortization of Excess ADIT.
| |
• | Income Tax Expense decreased $1 million primarily due to an increase in amortization of Excess ADIT partially offset by an increase in pretax book income. This decrease was partially offset in Gross MarginADIT and an increase in pretax book income. The decrease in amortization of Excess ADIT is partially offset in Retail Margins above.
|
PUBLIC SERVICE COMPANY OF OKLAHOMA
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 20192020 and 20182019
(in millions)
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | | | Nine Months Ended | | |
| | September 30, | | | | September 30, | | |
| | 2020 | | 2019 | | 2020 | | 2019 |
REVENUES | | | | | | | | |
Electric Generation, Transmission and Distribution | | $ | 505.7 | | | $ | 536.5 | | | $ | 1,284.3 | | | $ | 1,344.8 | |
Sales to AEP Affiliates | | 8.5 | | | 8.8 | | | 33.5 | | | 21.6 | |
Provision for Refund – Affiliated | | 2.4 | | | (0.1) | | | (2.0) | | | (25.3) | |
Other Revenues | | 0.7 | | | 0.3 | | | 2.4 | | | 1.0 | |
TOTAL REVENUES | | 517.3 | | | 545.5 | | | 1,318.2 | | | 1,342.1 | |
| | | | | | | | |
EXPENSES | | | | | | | | |
Fuel and Other Consumables Used for Electric Generation | | 131.7 | | | 148.8 | | | 306.4 | | | 400.2 | |
Purchased Electricity for Resale | | 41.0 | | | 44.8 | | | 125.1 | | | 110.5 | |
| | | | | | | | |
Other Operation | | 96.8 | | | 91.9 | | | 259.0 | | | 242.4 | |
Maintenance | | 30.7 | | | 35.9 | | | 97.2 | | | 104.1 | |
| | | | | | | | |
Depreciation and Amortization | | 68.5 | | | 63.2 | | | 203.9 | | | 187.1 | |
Taxes Other Than Income Taxes | | 26.7 | | | 26.2 | | | 77.0 | | | 76.0 | |
TOTAL EXPENSES | | 395.4 | | | 410.8 | | | 1,068.6 | | | 1,120.3 | |
| | | | | | | | |
OPERATING INCOME | | 121.9 | | | 134.7 | | | 249.6 | | | 221.8 | |
| | | | | | | | |
Other Income (Expense): | | | | | | | | |
Interest Income | | 0.6 | | | 0.6 | | | 1.7 | | | 2.0 | |
Allowance for Equity Funds Used During Construction | | 3.4 | | | 1.6 | | | 5.7 | | | 4.5 | |
Non-Service Cost Components of Net Periodic Benefit Cost | | 2.1 | | | 2.1 | | | 6.3 | | | 6.4 | |
| | | | | | | | |
Interest Expense | | (29.3) | | | (29.2) | | | (89.1) | | | (89.4) | |
| | | | | | | | |
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS | | 98.7 | | | 109.8 | | | 174.2 | | | 145.3 | |
| | | | | | | | |
Income Tax Expense (Benefit) | | 10.8 | | | (0.7) | | | 12.5 | | | 0 | |
Equity Earnings of Unconsolidated Subsidiary | | 0.7 | | | 0.8 | | | 2.2 | | | 2.3 | |
| | | | | | | | |
NET INCOME | | 88.6 | | | 111.3 | | | 163.9 | | | 147.6 | |
| | | | | | | | |
Net Income Attributable to Noncontrolling Interest | | 0.7 | | | 0.8 | | | 2.1 | | | 3.1 | |
| | | | | | | | |
EARNINGS ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER | | $ | 87.9 | | | $ | 110.5 | | | $ | 161.8 | | | $ | 144.5 | |
| | | | | | | | |
The common stock of SWEPCo is wholly-owned by Parent. | | | | | | | | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134. | | | | | | | | |
|
| | | | | | | | | | | | | | | | |
| | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, |
| | 2019 | | 2018 | | 2019 | | 2018 |
REVENUES | | | | | | | | |
|
Electric Generation, Transmission and Distribution | | $ | 490.5 |
| | $ | 479.1 |
| | $ | 1,164.3 |
| | $ | 1,209.5 |
|
Sales to AEP Affiliates | | 1.3 |
| | 1.1 |
| | 5.0 |
| | 3.7 |
|
Other Revenues | | 1.2 |
| | 1.2 |
| | 4.6 |
| | 3.3 |
|
TOTAL REVENUES | | 493.0 |
| | 481.4 |
| | 1,173.9 |
| | 1,216.5 |
|
| | | | | | | | |
EXPENSES | | |
| | |
| | |
| | |
|
Fuel and Other Consumables Used for Electric Generation | | 98.4 |
| | 104.4 |
| | 181.2 |
| | 211.5 |
|
Purchased Electricity for Resale | | 115.3 |
| | 116.8 |
| | 340.7 |
| | 352.3 |
|
Other Operation | | 87.6 |
| | 106.3 |
| | 226.0 |
| | 286.8 |
|
Maintenance | | 21.5 |
| | 22.3 |
| | 70.1 |
| | 73.2 |
|
Depreciation and Amortization | | 39.1 |
| | 42.3 |
| | 125.4 |
| | 120.5 |
|
Taxes Other Than Income Taxes | | 11.1 |
| | 10.8 |
| | 33.0 |
| | 32.6 |
|
TOTAL EXPENSES | | 373.0 |
| | 402.9 |
| | 976.4 |
| | 1,076.9 |
|
| | | | | | | | |
OPERATING INCOME | | 120.0 |
| | 78.5 |
| | 197.5 |
| | 139.6 |
|
| | | | | | | | |
Other Income (Expense): | | |
| | |
| | |
| | |
|
Other Income (Expense) | | 1.2 |
| | (0.2 | ) | | 2.1 |
| | (0.3 | ) |
Non-Service Cost Components of Net Periodic Benefit Cost | | 2.1 |
| | 2.1 |
| | 6.3 |
| | 6.5 |
|
Interest Expense | | (16.1 | ) | | (16.4 | ) | | (50.3 | ) | | (47.4 | ) |
| | | | | | | | |
INCOME BEFORE INCOME TAX EXPENSE | | 107.2 |
| | 64.0 |
| | 155.6 |
| | 98.4 |
|
| | | | | | | | |
Income Tax Expense | | 6.9 |
| | 3.6 |
| | 7.2 |
| | 8.6 |
|
| | | | | | | | |
NET INCOME | | $ | 100.3 |
| | $ | 60.4 |
| | $ | 148.4 |
| | $ | 89.8 |
|
|
| | | | |
The common stock of PSO is wholly-owned by Parent. |
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 126. |
PUBLIC SERVICESOUTHWESTERN ELECTRIC POWER COMPANY OF OKLAHOMACONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 20192020 and 20182019
(in millions)
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | | | Nine Months Ended | | |
| | September 30, | | | | September 30, | | |
| | 2020 | | 2019 | | 2020 | | 2019 |
Net Income | | $ | 88.6 | | | $ | 111.3 | | | $ | 163.9 | | | $ | 147.6 | |
| | | | | | | | |
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, 2020 and 2019, Respectively, and $0.3 and $0.3 for the Nine Months Ended September 30, 2020 and 2019, Respectively | | 0.4 | | | 0.3 | | | 1.1 | | | 1.1 | |
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.1) and $0 for the Three Months Ended September 30, 2020 and 2019, Respectively, and $(0.3) and $(0.2) for the Nine Months Ended September 30, 2020 and 2019, Respectively | | (0.4) | | | (0.3) | | | (1.1) | | | (0.9) | |
| | | | | | | | |
TOTAL OTHER COMPREHENSIVE INCOME | | 0 | | | 0 | | | 0 | | | 0.2 | |
| | | | | | | | |
TOTAL COMPREHENSIVE INCOME | | 88.6 | | | 111.3 | | | 163.9 | | | 147.8 | |
| | | | | | | | |
Total Comprehensive Income Attributable to Noncontrolling Interest | | 0.7 | | | 0.8 | | | 2.1 | | | 3.1 | |
| | | | | | | | |
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER | | $ | 87.9 | | | $ | 110.5 | | | $ | 161.8 | | | $ | 144.7 | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134. | | | | | | | | |
|
| | | | | | | | | | | | | | | | |
| | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, |
| | 2019 | | 2018 | | 2019 | | 2018 |
Net Income | | $ | 100.3 |
| | $ | 60.4 |
| | $ | 148.4 |
| | $ | 89.8 |
|
| | | | | | | | |
OTHER COMPREHENSIVE LOSS, NET OF TAXES | | |
| | |
| | |
| | |
|
Cash Flow Hedges, Net of Tax of $0 and $0 for the Three Months Ended September 30, 2019 and 2018, Respectively, and $(0.2) and $(0.2) for the Nine Months Ended September 30, 2019 and 2018, Respectively | | (0.2 | ) | | (0.2 | ) | | (0.7 | ) | | (0.7 | ) |
| | |
| | |
| | |
| | |
|
TOTAL COMPREHENSIVE INCOME | | $ | 100.1 |
| | $ | 60.2 |
|
| $ | 147.7 |
| | $ | 89.1 |
|
|
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page
126. |
PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Nine Months Ended September 30, 2019 and 2018
(in millions)
(Unaudited)
|
| | | | | | | | | | | | | | | | | | | | |
| | Common Stock | | Paid-in Capital | | Retained Earnings | | Accumulated Other Comprehensive Income (Loss) | | Total |
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2017 | | $ | 157.2 |
| | $ | 364.0 |
| | $ | 691.5 |
| | $ | 2.6 |
| | $ | 1,215.3 |
|
| | | | | | | | | | |
Common Stock Dividends | | | | | | (12.5 | ) | | | | (12.5 | ) |
ASU 2018-02 Adoption | | | | | | | | 0.5 |
| | 0.5 |
|
Net Loss | | | | | | (7.2 | ) | | | | (7.2 | ) |
Other Comprehensive Loss | | | | | | | | (0.2 | ) | | (0.2 | ) |
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2018 | | 157.2 |
| | 364.0 |
| | 671.8 |
| | 2.9 |
| | 1,195.9 |
|
| | | | | | | | | | |
Common Stock Dividends | | | | | | (12.5 | ) | | | | (12.5 | ) |
Net Income | | |
| | |
| | 36.6 |
| | |
| | 36.6 |
|
Other Comprehensive Loss | | |
| | |
| | |
| | (0.3 | ) | | (0.3 | ) |
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2018 | | 157.2 |
| | 364.0 |
| | 695.9 |
| | 2.6 |
| | 1,219.7 |
|
| | |
| | |
| | |
| | |
| | |
|
Common Stock Dividends | | | | | | (12.5 | ) | | | | (12.5 | ) |
Net Income | | | | | | 60.4 |
| | | | 60.4 |
|
Other Comprehensive Loss | | | | | | | | (0.2 | ) | | (0.2 | ) |
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2018 | | $ | 157.2 |
| | $ | 364.0 |
| | $ | 743.8 |
| | $ | 2.4 |
| | $ | 1,267.4 |
|
| | | | | | | | | | |
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2018 | | $ | 157.2 |
| | $ | 364.0 |
| | $ | 724.7 |
| | $ | 2.1 |
| | $ | 1,248.0 |
|
| | | | | | | | | | |
Common Stock Dividends | | | | | | (11.3 | ) | | | | (11.3 | ) |
Net Income | | | | | | 6.2 |
| | | | 6.2 |
|
Other Comprehensive Loss | | | | | | | | (0.2 | ) | | (0.2 | ) |
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2019 | | 157.2 |
| | 364.0 |
| | 719.6 |
| | 1.9 |
| | 1,242.7 |
|
| | | | | | | | | | |
Net Income | | |
| | |
| | 41.9 |
| | |
| | 41.9 |
|
Other Comprehensive Loss | | |
| | |
| | |
| | (0.3 | ) | | (0.3 | ) |
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2019 | | 157.2 |
| | 364.0 |
| | 761.5 |
| | 1.6 |
| | 1,284.3 |
|
| | | | | | | | | | |
Net Income | | | | | | 100.3 |
| | | | 100.3 |
|
Other Comprehensive Loss | | | | | | | | (0.2 | ) | | (0.2 | ) |
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2019 | | $ | 157.2 |
| | $ | 364.0 |
| | $ | 861.8 |
| | $ | 1.4 |
| | $ | 1,384.4 |
|
|
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page
126. |
PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
ASSETS
September 30, 2019 and December 31, 2018
(in millions)
(Unaudited)
|
| | | | | | | | |
| | September 30, | | December 31, |
| | 2019 | | 2018 |
CURRENT ASSETS | | | | |
Cash and Cash Equivalents | | $ | 2.9 |
| | $ | 2.0 |
|
Advances to Affiliates | | 95.1 |
| | — |
|
Accounts Receivable: | | | | |
Customers | | 25.2 |
| | 32.5 |
|
Affiliated Companies | | 27.3 |
| | 26.2 |
|
Miscellaneous | | 4.0 |
| | 5.7 |
|
Allowance for Uncollectible Accounts | | (0.4 | ) | | (0.1 | ) |
Total Accounts Receivable | | 56.1 |
| | 64.3 |
|
Fuel | | 12.8 |
| | 12.3 |
|
Materials and Supplies | | 46.2 |
| | 44.8 |
|
Risk Management Assets | | 21.7 |
| | 10.4 |
|
Accrued Tax Benefits | | 17.0 |
| | 14.7 |
|
Prepayments and Other Current Assets | | 11.5 |
| | 9.4 |
|
TOTAL CURRENT ASSETS | | 263.3 |
| | 157.9 |
|
| | | | |
PROPERTY, PLANT AND EQUIPMENT | | | | |
Electric: | | | | |
Generation | | 1,569.9 |
| | 1,577.0 |
|
Transmission | | 928.4 |
| | 892.3 |
|
Distribution | | 2,650.1 |
| | 2,572.8 |
|
Other Property, Plant and Equipment | | 319.6 |
| | 303.5 |
|
Construction Work in Progress | | 128.8 |
| | 94.0 |
|
Total Property, Plant and Equipment | | 5,596.8 |
| | 5,439.6 |
|
Accumulated Depreciation and Amortization | | 1,558.5 |
| | 1,472.9 |
|
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | 4,038.3 |
| | 3,966.7 |
|
| | | | |
OTHER NONCURRENT ASSETS | | | | |
Regulatory Assets | | 380.7 |
| | 369.0 |
|
Employee Benefits and Pension Assets | | 32.6 |
| | 31.7 |
|
Operating Lease Assets | | 37.1 |
| | — |
|
Deferred Charges and Other Noncurrent Assets | | 17.2 |
| | 7.1 |
|
TOTAL OTHER NONCURRENT ASSETS | | 467.6 |
| | 407.8 |
|
| | | | |
TOTAL ASSETS | | $ | 4,769.2 |
| | $ | 4,532.4 |
|
|
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 126.
|
PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
September 30, 2019 and December 31, 2018
(Unaudited)
|
| | | | | | | | |
| | September 30, | | December 31, |
| | 2019 | | 2018 |
| | (in millions) |
CURRENT LIABILITIES | | | | |
Advances from Affiliates | | $ | — |
| | $ | 105.5 |
|
Accounts Payable: | | |
| | |
|
General | | 128.6 |
| | 126.9 |
|
Affiliated Companies | | 38.6 |
| | 47.1 |
|
Long-term Debt Due Within One Year – Nonaffiliated | | 138.2 |
| | 375.5 |
|
Risk Management Liabilities | | 0.3 |
| | 1.0 |
|
Customer Deposits | | 59.0 |
| | 58.6 |
|
Accrued Taxes | | 43.7 |
| | 22.4 |
|
Obligations Under Operating Leases | | 6.0 |
| | — |
|
Regulatory Liability for Over-Recovered Fuel Costs | | 69.9 |
| | 20.1 |
|
Other Current Liabilities | | 67.7 |
| | 64.5 |
|
TOTAL CURRENT LIABILITIES | | 552.0 |
| | 821.6 |
|
| | | | |
NONCURRENT LIABILITIES | | | | |
Long-term Debt – Nonaffiliated | | 1,248.2 |
| | 911.5 |
|
Deferred Income Taxes | | 617.5 |
| | 607.8 |
|
Regulatory Liabilities and Deferred Investment Tax Credits | | 858.9 |
| | 864.7 |
|
Asset Retirement Obligations | | 50.9 |
| | 46.3 |
|
Obligations Under Operating Leases | | 31.2 |
| | — |
|
Deferred Credits and Other Noncurrent Liabilities | | 26.1 |
| | 32.5 |
|
TOTAL NONCURRENT LIABILITIES | | 2,832.8 |
| | 2,462.8 |
|
| | | | |
TOTAL LIABILITIES | | 3,384.8 |
| | 3,284.4 |
|
| | | | |
Rate Matters (Note 4) | |
| |
|
Commitments and Contingencies (Note 5) | |
| |
|
| | | | |
COMMON SHAREHOLDER’S EQUITY | | | | |
Common Stock – Par Value – $15 Per Share: | | | | |
Authorized – 11,000,000 Shares | | |
| | |
Issued – 10,482,000 Shares | | |
| | |
Outstanding – 9,013,000 Shares | | 157.2 |
| | 157.2 |
|
Paid-in Capital | | 364.0 |
| | 364.0 |
|
Retained Earnings | | 861.8 |
| | 724.7 |
|
Accumulated Other Comprehensive Income (Loss) | | 1.4 |
| | 2.1 |
|
TOTAL COMMON SHAREHOLDER’S EQUITY | | 1,384.4 |
| | 1,248.0 |
|
| | | | |
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY | | $ | 4,769.2 |
| | $ | 4,532.4 |
|
|
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 126. |
PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2019 and 2018
(in millions)
(Unaudited)
|
| | | | | | | | |
| | Nine Months Ended September 30, |
| | 2019 | | 2018 |
OPERATING ACTIVITIES | | |
| | |
|
Net Income | | $ | 148.4 |
| | $ | 89.8 |
|
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | |
| | |
|
Depreciation and Amortization | | 125.4 |
| | 120.5 |
|
Deferred Income Taxes | | (9.7 | ) | | (13.4 | ) |
Allowance for Equity Funds Used During Construction | | (1.5 | ) | | 0.3 |
|
Mark-to-Market of Risk Management Contracts | | (12.0 | ) | | (11.5 | ) |
Property Taxes | | (9.6 | ) | | (9.6 | ) |
Deferred Fuel Over/Under-Recovery, Net | | 49.8 |
| | 73.3 |
|
Change in Other Noncurrent Assets | | 4.6 |
| | 6.9 |
|
Change in Other Noncurrent Liabilities | | (0.2 | ) | | 14.6 |
|
Changes in Certain Components of Working Capital: | | |
| | |
|
Accounts Receivable, Net | | 9.1 |
| | (3.4 | ) |
Fuel, Materials and Supplies | | (1.9 | ) | | (1.5 | ) |
Accounts Payable | | (5.8 | ) | | 6.9 |
|
Accrued Taxes, Net | | 19.0 |
| | 38.4 |
|
Other Current Assets | | (2.4 | ) | | 0.3 |
|
Other Current Liabilities | | 1.1 |
| | 15.1 |
|
Net Cash Flows from Operating Activities | | 314.3 |
| | 326.7 |
|
| | | | |
INVESTING ACTIVITIES | | |
| | |
|
Construction Expenditures | | (198.7 | ) | | (162.8 | ) |
Change in Advances to Affiliates, Net | | (95.1 | ) | | — |
|
Other Investing Activities | | 2.1 |
| | 3.9 |
|
Net Cash Flows Used for Investing Activities | | (291.7 | ) | | (158.9 | ) |
| | | | |
FINANCING ACTIVITIES | | |
| | |
|
Issuance of Long-term Debt – Nonaffiliated | | 349.8 |
| | — |
|
Change in Advances from Affiliates, Net | | (105.5 | ) | | (127.6 | ) |
Retirement of Long-term Debt – Nonaffiliated | | (250.4 | ) | | (0.3 | ) |
Make Whole Premium on Extinguishment of Long-term Debt | | (3.0 | ) | | — |
|
Principal Payments for Finance Lease Obligations | | (2.2 | ) | | (2.5 | ) |
Dividends Paid on Common Stock | | (11.3 | ) | | (37.5 | ) |
Other Financing Activities | | 0.9 |
| | 0.4 |
|
Net Cash Flows Used for Financing Activities | | (21.7 | ) | | (167.5 | ) |
| | | | |
Net Increase in Cash and Cash Equivalents | | 0.9 |
| | 0.3 |
|
Cash and Cash Equivalents at Beginning of Period | | 2.0 |
| | 1.6 |
|
Cash and Cash Equivalents at End of Period | | $ | 2.9 |
| | $ | 1.9 |
|
| | | | |
SUPPLEMENTARY INFORMATION | | |
| | |
|
Cash Paid for Interest, Net of Capitalized Amounts | | $ | 46.5 |
| | $ | 42.0 |
|
Net Cash Paid for Income Taxes | | 16.0 |
| | 1.6 |
|
Noncash Acquisitions Under Finance Leases | | 3.4 |
| | 2.3 |
|
Construction Expenditures Included in Current Liabilities as of September 30, | | 31.5 |
| | 24.3 |
|
|
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 126. |
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 |
| September 30, | | September 30, |
| 2019 | | 2018 | | 2019 | | 2018 |
| (in millions of KWhs) |
Retail: | |
| | |
| | |
| | |
|
Residential | 2,071 |
| | 1,992 |
| | 4,896 |
| | 5,156 |
|
Commercial | 1,746 |
| | 1,675 |
| | 4,430 |
| | 4,548 |
|
Industrial | 1,414 |
| | 1,366 |
| | 4,020 |
| | 4,033 |
|
Miscellaneous | 19 |
| | 19 |
| | 59 |
| | 59 |
|
Total Retail (a) | 5,250 |
| | 5,052 |
| | 13,405 |
| | 13,796 |
|
| | | | | | | |
Wholesale | 1,831 |
| | 1,881 |
| | 5,317 |
| | 5,352 |
|
| | | | | | | |
Total KWhs | 7,081 |
| | 6,933 |
| | 18,722 |
| | 19,148 |
|
| |
(a) | 2018 KWhs have been revised to reflect the reclassification of certain customer accounts between Retail classes. This reclassification did not impact previously reported Total Retail KWhs. Management concluded that these prior period disclosure only errors were immaterial individually and in the aggregate. |
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 |
| September 30, | | September 30, |
| 2019 | | 2018 | | 2019 | | 2018 |
| (in degree days) |
Actual – Heating (a) | — |
| | — |
| | 732 |
| | 784 |
|
Normal – Heating (b) | 1 |
| | 1 |
| | 725 |
| | 733 |
|
| | | | | | | |
Actual – Cooling (c) | 1,552 |
| | 1,453 |
| | 2,263 |
| | 2,408 |
|
Normal – Cooling (b) | 1,408 |
| | 1,408 |
| | 2,187 |
| | 2,179 |
|
| |
(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 2019 Compared to Third Quarter of 2018
|
| | | | |
Reconciliation of Third Quarter of 2018 to Third Quarter of 2019 |
Earnings Attributable to SWEPCo Common Shareholder |
(in millions) |
| | |
Third Quarter of 2018 | | $ | 88.2 |
|
| | |
|
Changes in Gross Margin: | | |
|
Retail Margins (a) | | 10.7 |
|
Off-system Sales | | (0.2 | ) |
Transmission Revenues | | (4.8 | ) |
Other Revenues | | (0.4 | ) |
Total Change in Gross Margin | | 5.3 |
|
| | |
|
Changes in Expenses and Other: | | |
|
Other Operation and Maintenance | | 4.9 |
|
Depreciation and Amortization | | (3.3 | ) |
Taxes Other Than Income Taxes | | 0.7 |
|
Interest Income | | (0.5 | ) |
Allowance for Equity Funds Used During Construction | | 1.0 |
|
Non-Service Cost Components of Net Periodic Benefit Cost | | (0.2 | ) |
Interest Expense | | 3.5 |
|
Total Change in Expenses and Other | | 6.1 |
|
| | |
|
Income Tax Expense (Benefit) | | 10.3 |
|
Net Income Attributable to Noncontrolling Interest | | 0.6 |
|
| | |
|
Third Quarter of 2019 | | $ | 110.5 |
|
| |
(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 $11 million primarily due to the following:
|
A $6 million increase in weather-normalized margins.
A $5 million increase in weather-related usage primarily due to a 7% increase in cooling degree days.
| |
• | Transmission Revenues decreased $5 million primarily due to a decrease in SPP Base Plan Funding revenues and a decrease in nonaffiliated transmission services.
|
Expenses and Other and Income Tax Expense (Benefit) changed between years as follows:
| |
• | Other Operation and Maintenance expenses decreased $5 million primarily due to Wind Catcher Project expenses incurred in 2018.
|
| |
• | Depreciation and Amortization expenses increased $3 million primarily due to a higher depreciable base.
|
| |
• | Interest Expense decreased $4 million primarily due to lower interest rates on outstanding long-term debt.
|
| |
• | Income Tax Expense (Benefit) decreased $10 million primarily due to an increase in amortization of Excess ADIT not subject to normalization requirements. This decrease was partially offset in Gross Margin above.
|
Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018
|
| | | | |
Reconciliation of Nine Months Ended September 30, 2018 to Nine Months Ended September 30, 2019 |
Earnings Attributable to SWEPCo Common Shareholder |
(in millions) |
| | |
Nine Months Ended September 30, 2018 | | $ | 137.6 |
|
| | |
|
Changes in Gross Margin: | | |
|
Retail Margins (a) | | (18.3 | ) |
Off-system Sales | | (0.1 | ) |
Transmission Revenues | | (35.6 | ) |
Other Revenues | | (0.3 | ) |
Total Change in Gross Margin | | (54.3 | ) |
| | |
|
Changes in Expenses and Other: | | |
|
Other Operation and Maintenance | | 47.7 |
|
Depreciation and Amortization | | (11.2 | ) |
Taxes Other Than Income Taxes | | 0.4 |
|
Interest Income | | (1.5 | ) |
Allowance for Equity Funds Used During Construction | | 0.7 |
|
Non-Service Cost Components of Net Periodic Benefit Cost | | (0.5 | ) |
Interest Expense | | 6.4 |
|
Total Change in Expenses and Other | | 42.0 |
|
| | |
|
Income Tax Expense (Benefit) | | 17.9 |
|
Equity Earnings of Unconsolidated Subsidiary | | 0.3 |
|
Net Income Attributable to Noncontrolling Interest | | 1.0 |
|
| | |
|
Nine Months Ended September 30, 2019 | | $ | 144.5 |
|
| |
(a) | Includes firm wholesale sales to municipals and cooperatives. |
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, and purchased electricity were as follows:
| |
• | Retail Margins decreased $18 million primarily due to the following:
|
A $14 million decrease in weather-related usage primarily due to a 6% decrease in cooling degree days and a 7% decrease in heating degree days.
A $10 million decrease in weather-normalized margins.
These decreases were partially offset by:
A $7 million increase primarily due to rider and base rate revenue increases in Louisiana. This increase was offset in other expense items below.
| |
• | Transmission Revenues decreased $36 million primarily due to the following:
|
A $40 million decrease in the annual SPP formula rate true-up.
A $7 million decrease primarily due to a reduction in SPP Base Plan Funding revenues.
These decreases were partially offset by:
An $11 million increase due to a provision for refund recorded in 2018 related to certain transmission assets that management believes should not have been included in the SPP formula rate.
Expenses and Other and Income Tax Expense (Benefit) changed between years as follows:
| |
• | Other Operation and Maintenance expenses decreased $48 million primarily due to the following:
|
A $28 million decrease due to Wind Catcher Project expenses incurred in 2018.
A $24 million decrease in affiliated SPP transmission expenses primarily due to the annual formula rate true-up.
These decreases were partially offset by:
A $7 million increase in overhead line expenses primarily related to storm restoration.
| |
• | Depreciation and Amortization expenses increased $11 million primarily due to higher depreciation rates implemented in the third quarter of 2018 and a higher depreciable base.
|
| |
• | Interest Expense decreased $6 million primarily due to lower interest rates on outstanding long-term debt.
|
| |
• | Income Tax Expense (Benefit) decreased $18 million primarily due to an increase in amortization of Excess ADIT not subject to normalization requirements and a decrease in pretax book income. This decrease was partially offset in Gross Margin above.
|
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2019 and 2018
(in millions)
(Unaudited)
|
| | | | | | | | | | | | | | | | |
| | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, |
| | 2019 | | 2018 | | 2019 | | 2018 |
REVENUES | | | | | | | | |
|
Electric Generation, Transmission and Distribution | | $ | 536.5 |
| | $ | 526.0 |
| | $ | 1,344.8 |
| | $ | 1,390.4 |
|
Sales to AEP Affiliates | | 8.8 |
| | 8.7 |
| | 21.6 |
| | 20.2 |
|
Provision for Refund – Affiliated | | (0.1 | ) | | — |
| | (25.3 | ) | | — |
|
Other Revenues | | 0.3 |
| | 0.6 |
| | 1.0 |
| | 1.2 |
|
TOTAL REVENUES | | 545.5 |
| | 535.3 |
| | 1,342.1 |
| | 1,411.8 |
|
| | | | | | | | |
EXPENSES | | |
| | |
| | |
| | |
|
Fuel and Other Consumables Used for Electric Generation | | 148.8 |
| | 152.1 |
| | 400.2 |
| | 393.4 |
|
Purchased Electricity for Resale | | 44.8 |
| | 36.6 |
| | 110.5 |
| | 132.7 |
|
Other Operation | | 91.9 |
| | 99.1 |
| | 242.4 |
| | 292.0 |
|
Maintenance | | 35.9 |
| | 33.6 |
| | 104.1 |
| | 102.2 |
|
Depreciation and Amortization | | 63.2 |
| | 59.9 |
| | 187.1 |
| | 175.9 |
|
Taxes Other Than Income Taxes | | 26.2 |
| | 26.9 |
| | 76.0 |
| | 76.4 |
|
TOTAL EXPENSES | | 410.8 |
| | 408.2 |
| | 1,120.3 |
| | 1,172.6 |
|
| | | | | | | | |
OPERATING INCOME | | 134.7 |
| | 127.1 |
| | 221.8 |
| | 239.2 |
|
| | | | | | | | |
Other Income (Expense): | | |
| | |
| | | | |
|
Interest Income | | 0.6 |
| | 1.1 |
| | 2.0 |
| | 3.5 |
|
Allowance for Equity Funds Used During Construction | | 1.6 |
| | 0.6 |
| | 4.5 |
| | 3.8 |
|
Non-Service Cost Components of Net Periodic Benefit Cost | | 2.1 |
| | 2.3 |
| | 6.4 |
| | 6.9 |
|
Interest Expense | | (29.2 | ) | | (32.7 | ) | | (89.4 | ) | | (95.8 | ) |
| | | | | | | | |
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS | | 109.8 |
| | 98.4 |
| | 145.3 |
| | 157.6 |
|
| | | | | | | | |
Income Tax Expense (Benefit) | | (0.7 | ) | | 9.6 |
| | — |
| | 17.9 |
|
Equity Earnings of Unconsolidated Subsidiary | | 0.8 |
| | 0.8 |
| | 2.3 |
| | 2.0 |
|
| | | | | | | | |
NET INCOME | | 111.3 |
| | 89.6 |
| | 147.6 |
| | 141.7 |
|
| | | | | | | | |
Net Income Attributable to Noncontrolling Interest | | 0.8 |
| | 1.4 |
| | 3.1 |
| | 4.1 |
|
| | | | | | | | |
EARNINGS ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER | | $ | 110.5 |
| | $ | 88.2 |
| | $ | 144.5 |
| | $ | 137.6 |
|
|
| | | | |
The common stock of SWEPCo is wholly-owned by Parent. |
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 126. |
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 2019 and 2018
(in millions)
(Unaudited)
|
| | | | | | | | | | | | | | | | |
| | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, |
| | 2019 | | 2018 | | 2019 | | 2018 |
Net Income | | $ | 111.3 |
| | $ | 89.6 |
| | $ | 147.6 |
| | $ | 141.7 |
|
| | | | | | | | |
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES | | |
| | |
| | |
| | |
|
Cash Flow Hedges, Net of Tax of $0.1 and $0.8 for the Three Months Ended September 30, 2019 and 2018, Respectively, and $0.3 and $1 for the Nine Months Ended September 30, 2019 and 2018, Respectively | | 0.3 |
| | 2.7 |
| | 1.1 |
| | 3.6 |
|
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0 and $(0.1) for the Three Months Ended September 30, 2019 and 2018, Respectively, and $(0.2) and $(0.3) for the Nine Months Ended September 30, 2019 and 2018, Respectively | | (0.3 | ) | | (0.3 | ) | | (0.9 | ) | | (1.0 | ) |
| | | | | | | | |
TOTAL OTHER COMPREHENSIVE INCOME | | — |
| | 2.4 |
| | 0.2 |
| | 2.6 |
|
| | | | | | | | |
TOTAL COMPREHENSIVE INCOME | | 111.3 |
| | 92.0 |
| | 147.8 |
| | 144.3 |
|
| | | | | | | | |
Total Comprehensive Income Attributable to Noncontrolling Interest | | 0.8 |
| | 1.4 |
| | 3.1 |
| | 4.1 |
|
| | | | | | | | |
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER | | $ | 110.5 |
| | $ | 90.6 |
| | $ | 144.7 |
| | $ | 140.2 |
|
|
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 126. |
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Nine Months Ended September 30, 20192020 and 20182019
(in millions)
(Unaudited)
|
| | | | | | | | | | | | | | | | | | | | | | | |
| SWEPCo Common Shareholder | | | | |
| Common Stock | | Paid-in Capital | | Retained Earnings | | Accumulated Other Comprehensive Income (Loss) | | Noncontrolling Interest | | Total |
TOTAL EQUITY – DECEMBER 31, 2017 | $ | 135.7 |
| | $ | 676.6 |
| | $ | 1,426.6 |
| | $ | (4.0 | ) | | $ | (0.4 | ) | | $ | 2,234.5 |
|
| | | | | | | | | | | |
Common Stock Dividends | | | | | (20.0 | ) | | | | | | (20.0 | ) |
Common Stock Dividends – Nonaffiliated | | | | | | | | | (0.8 | ) | | (0.8 | ) |
ASU 2018-02 Adoption | | | | | (0.4 | ) | | (0.9 | ) | | | | (1.3 | ) |
Net Income | | | | | 11.8 |
| | | | 1.6 |
| | 13.4 |
|
Other Comprehensive Income | | | | | | | 0.1 |
| | | | 0.1 |
|
TOTAL EQUITY – MARCH 31, 2018 | 135.7 |
| | 676.6 |
| | 1,418.0 |
| | (4.8 | ) | | 0.4 |
| | 2,225.9 |
|
| | | | | | | | | | | |
Common Stock Dividends | | | | | (20.0 | ) | | | | | | (20.0 | ) |
Common Stock Dividends – Nonaffiliated | |
| | |
| | |
| | |
| | (1.0 | ) | | (1.0 | ) |
Net Income | |
| | |
| | 37.6 |
| | |
| | 1.1 |
| | 38.7 |
|
Other Comprehensive Income | |
| | |
| | |
| | 0.1 |
| | |
| | 0.1 |
|
TOTAL EQUITY – JUNE 30, 2018 | 135.7 |
| | 676.6 |
| | 1,435.6 |
| | (4.7 | ) | | 0.5 |
| | 2,243.7 |
|
| | | | | | | | | | | |
Common Stock Dividends | | | | | (20.0 | ) | | | | | | (20.0 | ) |
Common Stock Dividends – Nonaffiliated | | | | | | | | | (1.4 | ) | | (1.4 | ) |
Net Income | | | | | 88.2 |
| | | | 1.4 |
| | 89.6 |
|
Other Comprehensive Income | | | | | | | 2.4 |
| | | | 2.4 |
|
TOTAL EQUITY – SEPTEMBER 30, 2018 | $ | 135.7 |
| | $ | 676.6 |
| | $ | 1,503.8 |
| | $ | (2.3 | ) | | $ | 0.5 |
| | $ | 2,314.3 |
|
| | | | | | | | | | | |
TOTAL EQUITY – DECEMBER 31, 2018 | $ | 135.7 |
| | $ | 676.6 |
| | $ | 1,508.4 |
| | $ | (5.4 | ) | | $ | 0.3 |
| | $ | 2,315.6 |
|
| | | | | | | | | | | |
Common Stock Dividends | | | | | (18.7 | ) | | | | | | (18.7 | ) |
Common Stock Dividends – Nonaffiliated | | | | | | | | | (1.1 | ) | | (1.1 | ) |
Net Income | | | | | 27.8 |
| | | | 1.2 |
| | 29.0 |
|
Other Comprehensive Income | | | | | | | 0.1 |
| | | | 0.1 |
|
TOTAL EQUITY – MARCH 31, 2019 | 135.7 |
| | 676.6 |
| | 1,517.5 |
| | (5.3 | ) | | 0.4 |
| | 2,324.9 |
|
| | | | | | | | | | | |
Common Stock Dividends | |
| | |
| | (18.8 | ) | | |
| | |
| | (18.8 | ) |
Common Stock Dividends – Nonaffiliated | |
| | |
| | |
| | |
| | (1.1 | ) | | (1.1 | ) |
Net Income | |
| | |
| | 6.2 |
| | |
| | 1.1 |
| | 7.3 |
|
Other Comprehensive Income | |
| | |
| | |
| | 0.1 |
| | |
| | 0.1 |
|
TOTAL EQUITY – JUNE 30, 2019 | 135.7 |
| | 676.6 |
| | 1,504.9 |
| | (5.2 | ) | | 0.4 |
| | 2,312.4 |
|
| | | | | | | | | | | |
Common Stock Dividends – Nonaffiliated | | | | | | | | | (1.1 | ) | | (1.1 | ) |
Net Income | | | | | 110.5 |
| | | | 0.8 |
| | 111.3 |
|
TOTAL EQUITY – SEPTEMBER 30, 2019 | $ | 135.7 |
| | $ | 676.6 |
| | $ | 1,615.4 |
| | $ | (5.2 | ) | | $ | 0.1 |
| | $ | 2,422.6 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| SWEPCo Common Shareholder | | | | | | | | | | |
| Common Stock | | Paid-in Capital | | Retained Earnings | | Accumulated Other Comprehensive Income (Loss) | | Noncontrolling Interest | | Total |
TOTAL EQUITY – DECEMBER 31, 2018 | $ | 135.7 | | | $ | 676.6 | | | $ | 1,508.4 | | | $ | (5.4) | | | $ | 0.3 | | | $ | 2,315.6 | |
| | | | | | | | | | | |
Common Stock Dividends | | | | | (18.7) | | | | | | | (18.7) | |
Common Stock Dividends – Nonaffiliated | | | | | | | | | (1.1) | | | (1.1) | |
| | | | | | | | | | | |
Net Income | | | | | 27.8 | | | | | 1.2 | | | 29.0 | |
Other Comprehensive Income | | | | | | | 0.1 | | | | | 0.1 | |
TOTAL EQUITY – MARCH 31, 2019 | 135.7 | | | 676.6 | | | 1,517.5 | | | (5.3) | | | 0.4 | | | 2,324.9 | |
| | | | | | | | | | | |
Common Stock Dividends | | | | | (18.8) | | | | | | | (18.8) | |
Common Stock Dividends – Nonaffiliated | | | | | | | | | (1.1) | | | (1.1) | |
Net Income | | | | | 6.2 | | | | | 1.1 | | | 7.3 | |
Other Comprehensive Income | | | | | | | 0.1 | | | | | 0.1 | |
TOTAL EQUITY – JUNE 30, 2019 | 135.7 | | | 676.6 | | | 1,504.9 | | | (5.2) | | | 0.4 | | | 2,312.4 | |
| | | | | | | | | | | |
| | | | | | | | | | | |
Common Stock Dividends – Nonaffiliated | | | | | | | | | (1.1) | | | (1.1) | |
Net Income | | | | | 110.5 | | | | | 0.8 | | | 111.3 | |
| | | | | | | | | | | |
TOTAL EQUITY – SEPTEMBER 30, 2019 | $ | 135.7 | | | $ | 676.6 | | | $ | 1,615.4 | | | $ | (5.2) | | | $ | 0.1 | | | $ | 2,422.6 | |
| | | | | | | | | | | |
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 (a) | (135.6) | | | 135.6 | | | | | | | | | 0 | |
| | | | | | | | | | | |
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 | |
| | | | | |
| |
(a) | See Note 12 - Financing Activities for additional information. |
| |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 126134. | |
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 20192020 and December 31, 20182019
(in millions)
(Unaudited)
| | | | | | | | | | | | | | |
| | September 30, | | December 31, |
| | 2020 | | 2019 |
CURRENT ASSETS | | | | |
Cash and Cash Equivalents | | $ | 25.6 | | | $ | 1.6 | |
Advances to Affiliates | | 2.1 | | | 2.1 | |
Accounts Receivable: | | | | |
Customers | | 12.7 | | | 29.0 | |
Affiliated Companies | | 28.3 | | | 34.5 | |
Miscellaneous | | 24.4 | | | 13.5 | |
Allowance for Uncollectible Accounts | | 0 | | | (1.7) | |
Total Accounts Receivable | | 65.4 | | | 75.3 | |
Fuel (September 30, 2020 and December 31, 2019 Amounts Include $48.7 and $47, Respectively, Related to Sabine) | | 210.5 | | | 140.1 | |
Materials and Supplies (September 30, 2020 and December 31, 2019 Amounts Include $24 and $23.1, Respectively, Related to Sabine) | | 99.2 | | | 94.0 | |
Risk Management Assets | | 4.5 | | | 6.4 | |
| | | | |
| | | | |
Regulatory Asset for Under-Recovered Fuel Costs | | 7.0 | | | 4.9 | |
Prepayments and Other Current Assets | | 29.7 | | | 29.7 | |
TOTAL CURRENT ASSETS | | 444.0 | | | 354.1 | |
| | | | |
PROPERTY, PLANT AND EQUIPMENT | | | | |
Electric: | | | | |
Generation | | 4,674.7 | | | 4,691.4 | |
Transmission | | 2,109.6 | | | 2,056.5 | |
Distribution | | 2,356.6 | | | 2,270.7 | |
Other Property, Plant and Equipment (September 30, 2020 and December 31, 2019 Amounts Include $216.8 and $212.3, Respectively, Related to Sabine) | | 792.5 | | | 733.4 | |
Construction Work in Progress | | 272.3 | | | 216.9 | |
Total Property, Plant and Equipment | | 10,205.7 | | | 9,968.9 | |
Accumulated Depreciation and Amortization (September 30, 2020 and December 31, 2019 Amounts Include $117.4 and $107.5, Respectively, Related to Sabine) | | 3,092.6 | | | 2,873.7 | |
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | 7,113.1 | | | 7,095.2 | |
| | | | |
OTHER NONCURRENT ASSETS | | | | |
Regulatory Assets | | 334.8 | | | 222.4 | |
| | | | |
| | | | |
Deferred Charges and Other Noncurrent Assets | | 245.4 | | | 160.5 | |
TOTAL OTHER NONCURRENT ASSETS | | 580.2 | | | 382.9 | |
| | | | |
TOTAL ASSETS | | $ | 8,137.3 | | | $ | 7,832.2 | |
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134. | | | | |
|
| | | | | | | | |
| | September 30, | | December 31, |
| | 2019 | | 2018 |
CURRENT ASSETS | | | | |
Cash and Cash Equivalents (September 30, 2019 and December 31, 2018 Amounts Include $18.2 and $22, Respectively, Related to Sabine) | | $ | 21.4 |
| | $ | 24.5 |
|
Advances to Affiliates | | 8.5 |
| | 83.4 |
|
Accounts Receivable: | | | | |
Customers | | 20.6 |
| | 24.5 |
|
Affiliated Companies | | 56.8 |
| | 28.8 |
|
Miscellaneous | | 16.6 |
| | 20.2 |
|
Allowance for Uncollectible Accounts | | (1.4 | ) | | (0.7 | ) |
Total Accounts Receivable | | 92.6 |
| | 72.8 |
|
Fuel (September 30, 2019 and December 31, 2018 Amounts Include $51.6 and $35.7, Respectively, Related to Sabine) | | 135.9 |
| | 120.5 |
|
Materials and Supplies | | 69.8 |
| | 67.5 |
|
Risk Management Assets | | 9.4 |
| | 4.8 |
|
Regulatory Asset for Under-Recovered Fuel Costs | | 11.1 |
| | 18.8 |
|
Prepayments and Other Current Assets | | 24.4 |
| | 22.2 |
|
TOTAL CURRENT ASSETS | | 373.1 |
| | 414.5 |
|
| | | | |
PROPERTY, PLANT AND EQUIPMENT | | | | |
Electric: | | | | |
Generation | | 4,676.1 |
| | 4,672.6 |
|
Transmission | | 1,995.9 |
| | 1,866.9 |
|
Distribution | | 2,241.1 |
| | 2,178.6 |
|
Other Property, Plant and Equipment (September 30, 2019 and December 31, 2018 Amounts Include $210.3 and $276.9, Respectively, Related to Sabine) | | 703.2 |
| | 762.7 |
|
Construction Work in Progress | | 235.0 |
| | 199.3 |
|
Total Property, Plant and Equipment | | 9,851.3 |
| | 9,680.1 |
|
Accumulated Depreciation and Amortization (September 30, 2019 and December 31, 2018 Amounts Include $105.7 and $174.6, Respectively, Related to Sabine) | | 2,848.2 |
| | 2,808.3 |
|
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | 7,003.1 |
| | 6,871.8 |
|
| | | | |
OTHER NONCURRENT ASSETS | | | | |
Regulatory Assets | | 223.6 |
| | 230.8 |
|
Deferred Charges and Other Noncurrent Assets | | 167.2 |
| | 111.2 |
|
TOTAL OTHER NONCURRENT ASSETS | | 390.8 |
| | 342.0 |
|
| | | | |
TOTAL ASSETS | | $ | 7,767.0 |
| | $ | 7,628.3 |
|
|
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 126.
|
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
September 30, 20192020 and December 31, 20182019
(Unaudited)
| | | | | | | | | | | | | | |
| | September 30, | | December 31, |
| | 2020 | | 2019 |
| | (in millions) | | |
CURRENT LIABILITIES | | | | |
Advances from Affiliates | | $ | 71.8 | | | $ | 59.9 | |
Accounts Payable: | | | | |
General | | 183.3 | | | 138.0 | |
Affiliated Companies | | 80.5 | | | 53.6 | |
Short-term Debt – Nonaffiliated | | 42.0 | | | 18.3 | |
Long-term Debt Due Within One Year – Nonaffiliated | | 6.2 | | | 121.2 | |
Risk Management Liabilities | | 0.1 | | | 1.9 | |
Customer Deposits | | 63.7 | | | 65.0 | |
Accrued Taxes | | 90.1 | | | 41.8 | |
Accrued Interest | | 23.0 | | | 34.6 | |
| | | | |
Obligations Under Operating Leases | | 8.1 | | | 6.5 | |
Regulatory Liability for Over-Recovered Fuel Costs | | 32.0 | | | 13.6 | |
Other Current Liabilities | | 98.7 | | | 120.3 | |
TOTAL CURRENT LIABILITIES | | 699.5 | | | 674.7 | |
| | | | |
NONCURRENT LIABILITIES | | | | |
Long-term Debt – Nonaffiliated | | 2,631.1 | | | 2,534.4 | |
Long-term Risk Management Liabilities | | 0.7 | | | 3.1 | |
Deferred Income Taxes | | 965.0 | | | 940.9 | |
Regulatory Liabilities and Deferred Investment Tax Credits | | 877.5 | | | 892.3 | |
Asset Retirement Obligations | | 202.4 | | | 196.7 | |
| | | | |
| | | | |
Obligations Under Operating Leases | | 43.8 | | | 34.7 | |
Deferred Credits and Other Noncurrent Liabilities | | 113.0 | | | 114.3 | |
TOTAL NONCURRENT LIABILITIES | | 4,833.5 | | | 4,716.4 | |
| | | | |
TOTAL LIABILITIES | | 5,533.0 | | | 5,391.1 | |
| | | | |
Rate Matters (Note 4) | | | | |
Commitments and Contingencies (Note 5) | | | | |
| | | | |
EQUITY | | | | |
Common Stock – Par Value – $18 Per Share: | | | | |
Authorized – 3,680 Shares | | | | |
Outstanding – 3,680 Shares | | 0.1 | | | 135.7 | |
Paid-in Capital | | 812.2 | | | 676.6 | |
Retained Earnings | | 1,792.9 | | | 1,629.5 | |
Accumulated Other Comprehensive Income (Loss) | | (1.3) | | | (1.3) | |
TOTAL COMMON SHAREHOLDER’S EQUITY | | 2,603.9 | | | 2,440.5 | |
| | | | |
Noncontrolling Interest | | 0.4 | | | 0.6 | |
| | | | |
TOTAL EQUITY | | 2,604.3 | | | 2,441.1 | |
| | | | |
TOTAL LIABILITIES AND EQUITY | | $ | 8,137.3 | | | $ | 7,832.2 | |
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134. | | | | |
|
| | | | | | | | |
| | September 30, | | December 31, |
| | 2019 | | 2018 |
| | (in millions) |
CURRENT LIABILITIES | | | | |
Accounts Payable: | | | | |
General | | $ | 127.6 |
| | $ | 129.1 |
|
Affiliated Companies | | 62.4 |
| | 64.2 |
|
Long-term Debt Due Within One Year – Nonaffiliated | | 121.2 |
| | 59.7 |
|
Risk Management Liabilities | | 1.7 |
| | 0.4 |
|
Customer Deposits | | 65.0 |
| | 64.5 |
|
Accrued Taxes | | 94.7 |
| | 42.8 |
|
Accrued Interest | | 22.9 |
| | 34.7 |
|
Obligations Under Operating Leases | | 5.9 |
| | — |
|
Regulatory Liability for Over-Recovered Fuel Costs | | 17.4 |
| | 11.1 |
|
Other Current Liabilities | | 108.0 |
| | 106.4 |
|
TOTAL CURRENT LIABILITIES | | 626.8 |
| | 512.9 |
|
| | | | |
NONCURRENT LIABILITIES | | | | |
Long-term Debt – Nonaffiliated | | 2,535.7 |
| | 2,653.7 |
|
Long-term Risk Management Liabilities | | 3.0 |
| | 2.2 |
|
Deferred Income Taxes | | 919.1 |
| | 902.8 |
|
Regulatory Liabilities and Deferred Investment Tax Credits | | 918.1 |
| | 923.0 |
|
Asset Retirement Obligations | | 200.9 |
| | 191.3 |
|
Obligations Under Operating Leases | | 32.5 |
| | — |
|
Deferred Credits and Other Noncurrent Liabilities | | 108.3 |
| | 126.8 |
|
TOTAL NONCURRENT LIABILITIES | | 4,717.6 |
| | 4,799.8 |
|
| | | | |
TOTAL LIABILITIES | | 5,344.4 |
| | 5,312.7 |
|
| | | | |
Rate Matters (Note 4) | |
| |
|
Commitments and Contingencies (Note 5) | |
| |
|
| | | | |
EQUITY | | | | |
Common Stock – Par Value – $18 Per Share: | | | | |
Authorized – 7,600,000 Shares | | | | |
Outstanding – 7,536,640 Shares | | 135.7 |
| | 135.7 |
|
Paid-in Capital | | 676.6 |
| | 676.6 |
|
Retained Earnings | | 1,615.4 |
| | 1,508.4 |
|
Accumulated Other Comprehensive Income (Loss) | | (5.2 | ) | | (5.4 | ) |
TOTAL COMMON SHAREHOLDER’S EQUITY | | 2,422.5 |
| | 2,315.3 |
|
| | | | |
Noncontrolling Interest | | 0.1 |
| | 0.3 |
|
| | | | |
TOTAL EQUITY | | 2,422.6 |
| | 2,315.6 |
|
| | | | |
TOTAL LIABILITIES AND EQUITY | | $ | 7,767.0 |
| | $ | 7,628.3 |
|
|
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 126.
|
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 20192020 and 20182019
(in millions)
(Unaudited)
| | | | | | | | | | | | | | |
| | Nine Months Ended September 30, | | |
| | 2020 | | 2019 |
OPERATING ACTIVITIES | | | | |
Net Income | | $ | 163.9 | | | $ | 147.6 | |
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | | | |
Depreciation and Amortization | | 203.9 | | | 187.1 | |
Deferred Income Taxes | | (0.3) | | | (15.9) | |
| | | | |
Allowance for Equity Funds Used During Construction | | (5.7) | | | (4.5) | |
Mark-to-Market of Risk Management Contracts | | (2.3) | | | (2.5) | |
Pension Contributions to Qualified Plan Trust | | (8.9) | | | 0 | |
Property Taxes | | (16.5) | | | (16.1) | |
Deferred Fuel Over/Under-Recovery, Net | | 16.3 | | | 14.1 | |
Change in Regulatory Assets | | (64.5) | | | 5.7 | |
Change in Other Noncurrent Assets | | 3.2 | | | (2.2) | |
Change in Other Noncurrent Liabilities | | 21.0 | | | 5.8 | |
Changes in Certain Components of Working Capital: | | | | |
Accounts Receivable, Net | | 8.0 | | | (17.2) | |
Fuel, Materials and Supplies | | (70.9) | | | (17.7) | |
Accounts Payable | | 88.0 | | | (12.8) | |
Accrued Taxes, Net | | 46.6 | | | 54.1 | |
| | | | |
Other Current Assets | | 1.3 | | | (4.5) | |
Other Current Liabilities | | (50.3) | | | (13.9) | |
Net Cash Flows from Operating Activities | | 332.8 | | | 307.1 | |
| | | | |
INVESTING ACTIVITIES | | | | |
Construction Expenditures | | (319.5) | | | (277.3) | |
Change in Advances to Affiliates, Net | | 0 | | | 74.9 | |
Other Investing Activities | | 4.8 | | | (1.2) | |
Net Cash Flows Used for Investing Activities | | (314.7) | | | (203.6) | |
| | | | |
FINANCING ACTIVITIES | | | | |
| | | | |
| | | | |
Change in Short-term Debt – Nonaffiliated | | 23.7 | | | 0 | |
Change in Advances from Affiliates, Net | | 11.9 | | | 0 | |
Retirement of Long-term Debt – Nonaffiliated | | (19.7) | | | (58.2) | |
Principal Payments for Finance Lease Obligations | | (8.0) | | | (8.1) | |
Dividends Paid on Common Stock | | 0 | | | (37.5) | |
Dividends Paid on Common Stock – Nonaffiliated | | (2.3) | | | (3.3) | |
Other Financing Activities | | 0.3 | | | 0.5 | |
Net Cash Flows from (Used for) Financing Activities | | 5.9 | | | (106.6) | |
| | | | |
Net Increase (Decrease) in Cash and Cash Equivalents | | 24.0 | | | (3.1) | |
Cash and Cash Equivalents at Beginning of Period | | 1.6 | | | 24.5 | |
Cash and Cash Equivalents at End of Period | | $ | 25.6 | | | $ | 21.4 | |
| | | | |
SUPPLEMENTARY INFORMATION | | | | |
Cash Paid for Interest, Net of Capitalized Amounts | | $ | 95.2 | | | $ | 95.1 | |
Net Cash Paid for Income Taxes | | 11.9 | | | 7.3 | |
Noncash Acquisitions Under Finance Leases | | 5.9 | | | 4.7 | |
Construction Expenditures Included in Current Liabilities as of September 30, | | 50.6 | | | 52.0 | |
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134. | | | | |
|
| | | | | | | | |
| | Nine Months Ended September 30, |
| | 2019 | | 2018 |
OPERATING ACTIVITIES | | |
| | |
|
Net Income | | $ | 147.6 |
| | $ | 141.7 |
|
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | | | |
Depreciation and Amortization | | 187.1 |
| | 175.9 |
|
Deferred Income Taxes | | (15.9 | ) | | 2.0 |
|
Allowance for Equity Funds Used During Construction | | (4.5 | ) | | (3.8 | ) |
Mark-to-Market of Risk Management Contracts | | (2.5 | ) | | 2.5 |
|
Property Taxes | | (16.1 | ) | | (15.8 | ) |
Deferred Fuel Over/Under-Recovery, Net | | 14.1 |
| | 4.4 |
|
Change in Other Noncurrent Assets | | 3.5 |
| | (8.9 | ) |
Change in Other Noncurrent Liabilities | | 5.8 |
| | 52.1 |
|
Changes in Certain Components of Working Capital: | | | | |
Accounts Receivable, Net | | (17.2 | ) | | 44.3 |
|
Fuel, Materials and Supplies | | (17.7 | ) | | 5.0 |
|
Accounts Payable | | (12.8 | ) | | (29.9 | ) |
Accrued Taxes, Net | | 54.1 |
| | 38.4 |
|
Other Current Assets | | (4.5 | ) | | 3.2 |
|
Other Current Liabilities | | (13.9 | ) | | 4.2 |
|
Net Cash Flows from Operating Activities | | 307.1 |
| | 415.3 |
|
| | | | |
INVESTING ACTIVITIES | | | | |
Construction Expenditures | | (277.3 | ) | | (336.6 | ) |
Change in Advances to Affiliates, Net | | 74.9 |
| | (516.6 | ) |
Other Investing Activities | | (1.2 | ) | | 1.2 |
|
Net Cash Flows Used for Investing Activities | | (203.6 | ) | | (852.0 | ) |
| | | | |
FINANCING ACTIVITIES | | | | |
Issuance of Long-term Debt – Nonaffiliated | | — |
| | 1,015.4 |
|
Change in Short-term Debt – Nonaffiliated | | — |
| | (2.6 | ) |
Change in Advances from Affiliates, Net | | — |
| | (118.7 | ) |
Retirement of Long-term Debt – Nonaffiliated | | (58.2 | ) | | (385.3 | ) |
Principal Payments for Finance Lease Obligations | | (8.1 | ) | | (8.5 | ) |
Dividends Paid on Common Stock | | (37.5 | ) | | (60.0 | ) |
Dividends Paid on Common Stock – Nonaffiliated | | (3.3 | ) | | (3.2 | ) |
Other Financing Activities | | 0.5 |
| | 0.5 |
|
Net Cash Flows from (Used for) Financing Activities | | (106.6 | ) | | 437.6 |
|
| | | | |
Net Increase (Decrease) in Cash and Cash Equivalents | | (3.1 | ) | | 0.9 |
|
Cash and Cash Equivalents at Beginning of Period | | 24.5 |
| | 1.6 |
|
Cash and Cash Equivalents at End of Period | | $ | 21.4 |
| | $ | 2.5 |
|
| | | | |
SUPPLEMENTARY INFORMATION | | | | |
Cash Paid for Interest, Net of Capitalized Amounts | | $ | 95.1 |
| | $ | 102.5 |
|
Net Cash Paid for Income Taxes | | 7.3 |
| | 12.9 |
|
Noncash Acquisitions Under Finance Leases | | 4.7 |
| | 3.2 |
|
Construction Expenditures Included in Current Liabilities as of September 30, | | 52.0 |
| | 37.0 |
|
|
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 126.
|
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 |
| | | | |
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, OPCo, 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 and Impairments | | AEP, APCo | | |
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 | | |
LeasesFinancing Activities | | AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo | | |
Financing Activities | | | | |
Property, Plant and Equipment | | AEP, APCo | | |
Revenue from Contracts with Customers | | AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo | | |
Variable Interest Entities and Equity Method Investments | | AEP | | |
Revenue from Contracts with Customers | | AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo | | |
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, 20192020 is not necessarily indicative of results that may be expected for the year ending December 31, 2019.2020. The condensed financial statements are unaudited and should be read in conjunction with the audited 20182019 financial statements and notes thereto, which are included in the Registrants’ Annual Reports on Form 10-K as filed with the SEC on February 21, 2019.20, 2020.
COVID-19
In March 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 could reduce future demand for energy, particularly from commercial and industrial customers. The Registrants are taking steps to mitigate the potential risks to customers, suppliers and employees posed by the spread of COVID-19.
As of September 30, 2020 and through the date of this report, the Registrants assessed certain accounting matters that require consideration of forecasted financial information, including, but not limited to, the allowance for credit losses and the carrying value of long-lived assets. While there were not any impairments or significant increases in credit allowances resulting from these assessments for the three and nine months ended September 30, 2020, the ultimate impact of COVID-19 also depends on factors beyond management’s knowledge or control, including the duration and severity of this outbreak as well as third-party actions taken to contain its spread and mitigate its public health effects. Therefore, management cannot estimate the potential future impact to financial position, results of operations and cash flows, but the impacts could be material.
Voluntary Retirement Incentive Program
In June 2020, AEP announced a voluntary retirement incentive program. Eligible employees volunteered for retirement from the date of the announcement through July 6, 2020, with most having an effective retirement date of August 1, 2020. Participating employees were eligible to receive up to six months base pay and a medical premium subsidy. Certain participating employees were also eligible to receive a long-term incentive plan grant, with immediate vesting, of AEP common shares. A total of 200 employees participated in the voluntary retirement program. In August 2020, AEP recorded a charge to expense of $13 million primarily related to lump sum salary payments and cash subsidies. AEP also recorded a charge to expense of $5 million related to the incremental Long-Term Incentive Plan grants issued related to this initiative. Approximately 92% of the expense was within the AEPSC and was allocated among affiliated entities including the Registrant Subsidiaries. The impact of this program was immaterial on the Registrants’ financial statements as of September 30, 2020.
Earnings Per Share (EPS) (Applies to AEP)
Basic EPS is calculated by dividing net earnings available to common shareholders by the weighted averageweighted-average number of common shares outstanding during the period. Diluted EPS is calculated by adjusting the weighted averageweighted-average outstanding common shares, assuming conversion of all potentially dilutive stock awards.
The following tables presenttable presents AEP’s basic and diluted EPS calculations included on the statements of income:
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | | | | | |
| 2020 | | | | 2019 | | |
| (in millions, except per share data) | | | | | | |
| | | $/share | | | | $/share |
| | | | | | | |
| | | | | | | |
Earnings Attributable to AEP Common Shareholders | $ | 748.6 | | | | | $ | 733.5 | | | |
| | | | | | | |
Weighted Average Number of Basic Shares Outstanding | 496.2 | | | $ | 1.51 | | | 493.8 | | | $ | 1.49 | |
Weighted Average Dilutive Effect of Stock-Based Awards | 1.3 | | | (0.01) | | | 1.7 | | | (0.01) | |
Weighted Average Number of Diluted Shares Outstanding | 497.5 | | | $ | 1.50 | | | 495.5 | | | $ | 1.48 | |
|
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, |
| 2019 | | 2018 |
| (in millions, except per share data) |
| |
| | $/share | | | | $/share |
Earnings Attributable to AEP Common Shareholders | $ | 733.5 |
| | |
| | $ | 577.6 |
| | |
|
| | | | | | | |
Weighted Average Number of Basic Shares Outstanding | 493.8 |
| | $ | 1.49 |
| | 493.0 |
| | $ | 1.17 |
|
Weighted Average Dilutive Effect of Stock-Based Awards | 1.7 |
| | (0.01 | ) | | 0.9 |
| | — |
|
Weighted Average Number of Diluted Shares Outstanding | 495.5 |
| | $ | 1.48 |
| | 493.9 |
| | $ | 1.17 |
|
|
| | | | | | | | | | | | | | | |
| Nine Months Ended September 30, |
| 2019 | | 2018 |
| (in millions, except per share data) |
| |
| | $/share | | | | $/share |
Earnings Attributable to AEP Common Shareholders | $ | 1,767.6 |
| | | | $ | 1,560.4 |
| | |
| | | | | | | |
Weighted Average Number of Basic Shares Outstanding | 493.6 |
| | $ | 3.58 |
| | 492.6 |
| | $ | 3.17 |
|
Weighted Average Dilutive Effect of Stock-Based Awards | 1.5 |
| | (0.01 | ) | | 0.9 |
| | (0.01 | ) |
Weighted Average Number of Diluted Shares Outstanding | 495.1 |
| | $ | 3.57 |
| | 493.5 |
| | $ | 3.16 |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, | | | | | | |
| 2020 | | | | 2019 | | |
| (in millions, except per share data) | | | | | | |
| | | $/share | | | | $/share |
| | | | | | | |
| | | | | | | |
Earnings Attributable to AEP Common Shareholders | $ | 1,764.6 | | | | | $ | 1,767.6 | | | |
| | | | | | | |
Weighted Average Number of Basic Shares Outstanding | 495.5 | | | $ | 3.56 | | | 493.6 | | | $ | 3.58 | |
Weighted Average Dilutive Effect of Stock-Based Awards | 1.4 | | | (0.01) | | | 1.5 | | | (0.01) | |
Weighted Average Number of Diluted Shares Outstanding | 496.9 | | | $ | 3.55 | | | 495.1 | | | $ | 3.57 | |
Equity Units issued in March 2019 are potentially dilutive securities but were excluded from the calculation of diluted EPS for the three and nine months ended September 30, 2020 and 2019, as the dilutive stock price threshold wasthresholds were not met. See Note 1312 - Financing Activities for more information related to Equity Units.
There were no0 antidilutive shares outstanding as of September 30, 20192020 and 2018.2019.
Restricted Cash (Applies to AEP, AEP Texas APCo and OPCo)APCo)
Restricted Cash primarily included funds held by trustee for the payment of securitization bonds and contractually restricted deposits held for the future payment of the remaining construction activities at Santa Rita East.
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, 2020 | | | | |
| | AEP | | AEP Texas | | APCo |
| | (in millions) | | | | |
Cash and Cash Equivalents | | $ | 409.7 | | | $ | 0.1 | | | $ | 3.9 | |
Restricted Cash | | 54.1 | | | 44.8 | | | 9.3 | |
Total Cash, Cash Equivalents and Restricted Cash | | $ | 463.8 | | | $ | 44.9 | | | $ | 13.2 | |
|
| | | | | | | | | | | | | | | | |
| | September 30, 2019 |
| | AEP | | AEP Texas | | APCo | | OPCo |
| | (in millions) |
Cash and Cash Equivalents | | $ | 348.8 |
| | $ | 0.1 |
| | $ | 3.5 |
| | $ | 4.7 |
|
Restricted Cash | | 141.0 |
| | 114.3 |
| | 17.1 |
| | — |
|
Total Cash, Cash Equivalents and Restricted Cash | | $ | 489.8 |
| | $ | 114.4 |
| | $ | 20.6 |
| | $ | 4.7 |
|
|
| | | | | | | | | | | | | | | | |
| | December 31, 2018 |
| | AEP | | AEP Texas | | APCo | | OPCo |
| | (in millions) |
Cash and Cash Equivalents | | $ | 234.1 |
| | $ | 3.1 |
| | $ | 4.2 |
| | $ | 4.9 |
|
Restricted Cash | | 210.0 |
| | 156.7 |
| | 25.6 |
| | 27.6 |
|
Total Cash, Cash Equivalents and Restricted Cash | | $ | 444.1 |
| | $ | 159.8 |
| | $ | 29.8 |
| | $ | 32.5 |
|
| | | | | | | | | | | | | | | | | | | | |
| | December 31, 2019 | | | | |
| | AEP | | AEP Texas | | APCo |
| | (in millions) | | | | |
Cash and Cash Equivalents | | $ | 246.8 | | | $ | 3.1 | | | $ | 3.3 | |
Restricted Cash | | 185.8 | | | 154.7 | | | 23.5 | |
Total Cash, Cash Equivalents and Restricted Cash | | $ | 432.6 | | | $ | 157.8 | | | $ | 26.8 | |
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Allowance for Uncollectible Accounts
Generally, AEP Credit records bad debt expense based upon a 12-month rolling average of bad debt write-offs in proportion to gross accounts receivable purchased from participating AEP subsidiaries. The assessment is performed separately by each participating AEP subsidiary, which inherently contemplates any differences in geographical risk characteristics for the allowance. For receivables related to APCo’s West Virginia operations, the bad debt reserve is calculated based on a rolling two-year average write-off in proportion to gross accounts receivable. For customer accounts receivables relating to risk management activities, accounts receivables are reviewed for bad debt reserves at a specific counterparty level basis. For AEP Texas, bad debt reserves are calculated using the specific identification of receivable balances greater than 120 days delinquent, and for those balances less than 120 days where the collection is doubtful. For miscellaneous accounts receivable, bad debt expense is recorded based upon a 12-month rolling average of bad debt write-offs in proportion to gross accounts receivable, unless specifically identified. In addition to these processes, management contemplates available current information, as well as any reasonable and supportable forecast information, to determine if allowances for uncollectible accounts should be further adjusted in accordance with the accounting guidance for “Credit Losses.” Management’s assessments contemplate expected losses over the life of the accounts receivable.
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. The following standards will impact the financial statements.
ASU 2016-02 “Accounting for Leases” (ASU 2016-02)
In February 2016, the FASB issued ASU 2016-02 increasing the transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheets and disclosing key information about leasing arrangements. Under the new standard, an entity must recognize an asset and liability for operating leases on the balance sheets. Additionally, capital leases are known as finance leases going forward. Leases with terms of 12 months or longer are also subject to the new requirements. Fundamentally, the criteria used to determine lease classification remains the same, but is more subjective under the new standard.
New leasing standard implementation activities included the identification of the lease population within the AEP System as well as the sampling of representative lease contracts to analyze accounting treatment under the new accounting guidance. Based upon the completed assessments, management also prepared a gap analysis to outline new disclosure compliance requirements.
Management adopted ASU 2016-02 effective January 1, 2019 by means of a cumulative-effect adjustment to the balance sheets. Management elected the following practical expedients upon adoption:
|
| | |
Practical Expedient | | Description |
Overall Expedients (for leases commenced prior to adoption date and must be adopted as a package) | | Do not need to reassess whether any expired or existing contracts are/or contain leases, do not need to reassess the lease classification for any expired or existing leases and do not need to reassess initial direct costs for any existing leases. |
Lease and Non-lease Components (elect by class of underlying asset) | | Elect as an accounting policy to not separate non-lease components from lease components and instead account for each lease and associated non-lease component as a single lease component. |
Short-term Lease (elect by class of underlying asset) | | Elect as an accounting policy to not apply the recognition requirements to short-term leases. |
Existing and expired land easements not previously accounted for as leases | | Elect optional transition practical expedient to not evaluate under Topic 842 existing or expired land easements that were not previously accounted for as leases under the current leases guidance in Topic 840. |
Cumulative-effect adjustment in the period of adoption | | Elect the optional transition practical expedient to adopt the new lease requirements through a cumulative-effect adjustment on the balance sheet in the period of adoption. |
Management concluded that the result of adoption would not materially change the volume of contracts that qualify as leases going forward. The adoption of the new standard did not materially impact results of operations or cash flows, but did have a material impact on the balance sheets. See Note 12 - Leases for additional disclosures required by the new standard.
ASU 2016-13 “Measurement of Credit Losses on Financial Instruments” (ASU 2016-13)
In June 2016, the FASB issued ASU 2016-13 requiring the recognition of an allowance for expected credit losses for financial instruments within its scope. Examples of financial instruments that are in scope include trade receivables, certain financial guarantees and held-to-maturity debt securities. The allowance for expected credit losses should be based on historical information, current conditions and reasonable and supportable forecasts. Entities are required to evaluate, and if necessary, recognize expected credit losses at the inception or initial acquisition of a financial instrument (or pool of financial instruments that share similar risk characteristics) subject to ASU 2016-13, and subsequently as of each reporting date. The new standard also revises the other-than-temporary impairment model for available-for-sale debt securities.
The new accounting guidance is effective for interim and annual periods beginning after December 15, 2019, with early adoption permitted for interim and annual periods beginning after December 15, 2018. The amendments will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective.
Management continues to analyze the impact of this new standard. ImplementationNew standard implementation activities to date includeincluded: (a) the identification and evaluation of the population of financial instruments within the AEP system that are subject to the new standard, (b) the development of supporting valuation models to also contemplate appropriate metrics for current and evaluationssupportable forecasted information and (c) the development of disclosures to determine whethercomply with the requirements of ASU 2016-13. As required by ASU 2016-13, the financial instruments subject to the new expected loss recognition model will causestandard were evaluated on a pool-basis to the extent such financial instruments shared similar risk characteristics.
Management adopted ASU 2016-13 and its related implementation guidance effective January 1, 2020, by means of an immaterial cumulative-effect adjustment to Retained Earnings on the balance sheets. The adoption of the new standard did not have a material impact to financial position and had no impact on the results of operations or cash flows. Additionally, the adoption of the new standard did not result in any material changes to previously calculated allowance balancescurrent accounting systems.
ASU 2020-04 “Reference Rate Reform: Facilitation of the Effects of Reference Rate Reform on Financial Reporting” (ASU 2020-04)
In March 2020, the FASB issued ASU 2020-04 providing guidance to ease the potential burden in accounting for Reference Rate Reform on financial reporting. The new standard is elective and supporting valuation models. Based onapplies to all entities, subject to meeting certain criteria, that have contracts, hedging relationships, and other transactions that reference the assessments performedLondon Interbank Offered Rate (LIBOR) or another reference rate expected to be discontinued because of Reference Rate Reform. The new standard establishes a general contract modification principle that entities can apply in other areas that may be affected by Reference Rate Reform and certain elective hedge accounting expedients. Under the new standard, an entity may make a one-time election to sell or to transfer to the available-for-sale or trading classifications (or both sell and transfer), debt securities that both reference an affected rate, and were classified as held-to-maturity before January 1, 2020.
The new accounting guidance is effective for all entities as of March 12, 2020 through December 31, 2022. The amendments may be applied to contract modifications as of any date from the beginning of an interim period that includes or is subsequent to March 12, 2020, or prospectively from a date within an interim period that includes or is subsequent to March 12, 2020, up to the date that the financial statements are available to be issued. The amendments may be applied to eligible hedging relationships existing as of the beginning of the interim period that includes March 12, 2020 and to new eligible hedging relationships entered into after the beginning of the interim period that includes March 12, 2020. The one-time election to sell, transfer, or both sell and transfer debt securities classified as held-to-maturity may be made at any time after March 12, 2020 but no later than December 31, 2022. Management does not expecthas yet to apply the amendments in the new standard to have a materialany contract modifications, hedging relationships, or debt securities. Management is analyzing the impact of this new standard and at this time, cannot estimate the impact of adoption on results of operations, financial position or cash flows.
Management’s implementation activities, including an assessment of the new standard’s disclosure requirements will continue throughout the fourth quarter of 2019. Management will continue to analyze the related impacts to allowances for credit losses and monitor for any potential industry implementation issues. Additionally, Management does not anticipate any significant changes to current accounting systems because of the adoption of the new standard. Management plans to adopt ASU 2016-13 and its related implementation guidance effective January 1, 2020.
3. COMPREHENSIVE INCOME
The disclosures in this note apply to all Registrants except AEPTCo unless indicated otherwise.
Presentation of Comprehensive Income
The following tables provide the components of changes in AOCI and details of reclassifications from AOCI. The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 7 - Benefit Plans for additional details.
AEP
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 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) | 0 | | | 12.1 | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
Generation & Marketing Revenues (b) | | (0.1) | | | 0 | | | 0 | | | (0.1) | |
Purchased Electricity for Resale (b) | | 33.3 | | | 0 | | | 0 | | | 33.3 | |
Interest Expense (b) | | 0 | | | 1.3 | | | 0 | | | 1.3 | |
Amortization of Prior Service Cost (Credit) | | 0 | | | 0 | | | (4.9) | | | (4.9) | |
Amortization of Actuarial (Gains) Losses | | 0 | | | 0 | | | 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) | |
| | | | Cash Flow Hedges | | Pension | | | | | Cash Flow Hedges | | | Pension | | |
Three Months Ended September 30, 2019 | | Commodity | | Interest Rate | | and OPEB | | Total | Three Months Ended September 30, 2019 | | Commodity | | Interest Rate | | and OPEB | | Total |
| | (in millions) | | | (in millions) | |
Balance in AOCI as of June 30, 2019 | | $ | (127.2 | ) | | $ | (15.9 | ) | | $ | (87.6 | ) | | $ | (230.7 | ) | Balance in AOCI as of June 30, 2019 | | $ | (127.2) | | | $ | (15.9) | | | $ | (87.6) | | | $ | (230.7) | |
Change in Fair Value Recognized in AOCI | | 38.4 |
| | (0.8 | ) | (b) | — |
| | 37.6 |
| Change in Fair Value Recognized in AOCI | | 38.4 | | | (0.8) | | (c) | 0 | | | 37.6 | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | | Amount of (Gain) Loss Reclassified from AOCI | |
Generation & Marketing Revenues (a) | | (0.1 | ) | | — |
| | — |
| | (0.1 | ) | |
Purchased Electricity for Resale (a) | | 8.5 |
| | — |
| | — |
| | 8.5 |
| |
Generation & Marketing Revenues (b) | | Generation & Marketing Revenues (b) | | (0.1) | | | 0 | | | 0 | | | (0.1) | |
Purchased Electricity for Resale (b) | | Purchased Electricity for Resale (b) | | 8.5 | | | 0 | | | 0 | | | 8.5 | |
| Amortization of Prior Service Cost (Credit) | | — |
| | — |
| | (4.8 | ) | | (4.8 | ) | Amortization of Prior Service Cost (Credit) | | 0 | | | 0 | | | (4.8) | | | (4.8) | |
Amortization of Actuarial (Gains) Losses | | — |
| | — |
| | 3.0 |
| | 3.0 |
| Amortization of Actuarial (Gains) Losses | | 0 | | | 0 | | | 3.0 | | | 3.0 | |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | 8.4 |
| | — |
| | (1.8 | ) | | 6.6 |
| Reclassifications from AOCI, before Income Tax (Expense) Benefit | | 8.4 | | | 0 | | | (1.8) | | | 6.6 | |
Income Tax (Expense) Benefit | | 1.8 |
| | — |
| | (0.4 | ) | | 1.4 |
| Income Tax (Expense) Benefit | | 1.8 | | | 0 | | | (0.4) | | | 1.4 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | 6.6 |
| | — |
| | (1.4 | ) | | 5.2 |
| Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | 6.6 | | | 0 | | | (1.4) | | | 5.2 | |
Net Current Period Other Comprehensive Income (Loss) | | 45.0 |
| | (0.8 | ) | | (1.4 | ) | | 42.8 |
| Net Current Period Other Comprehensive Income (Loss) | | 45.0 | | | (0.8) | | | (1.4) | | | 42.8 | |
Balance in AOCI as of September 30, 2019 | | $ | (82.2 | ) | | $ | (16.7 | ) | | $ | (89.0 | ) | | $ | (187.9 | ) | Balance in AOCI as of September 30, 2019 | | $ | (82.2) | | | $ | (16.7) | | | $ | (89.0) | | | $ | (187.9) | |
|
| | | | | | | | | | | | | | | | |
| | Cash Flow Hedges | | Pension | | |
Three Months Ended September 30, 2018 | | Commodity | | Interest Rate | | and OPEB | | Total |
| | (in millions) |
Balance in AOCI as of June 30, 2018 | | $ | (30.4 | ) | | $ | (15.3 | ) | | $ | (49.1 | ) | | $ | (94.8 | ) |
Change in Fair Value Recognized in AOCI | | 12.2 |
| | 2.3 |
| | — |
| | 14.5 |
|
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
Generation & Marketing Revenues (a) | | (0.1 | ) | | — |
| | — |
| | (0.1 | ) |
Purchased Electricity for Resale (a) | | (5.8 | ) | | — |
| | — |
| | (5.8 | ) |
Interest Expense (a) | | — |
| | 0.4 |
| | — |
| | 0.4 |
|
Amortization of Prior Service Cost (Credit) | | — |
| | — |
| | (5.0 | ) | | (5.0 | ) |
Amortization of Actuarial (Gains) Losses | | — |
| | — |
| | 3.2 |
| | 3.2 |
|
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | (5.9 | ) | | 0.4 |
| | (1.8 | ) | | (7.3 | ) |
Income Tax (Expense) Benefit | | (1.3 | ) | | 0.1 |
| | (0.4 | ) | | (1.6 | ) |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | (4.6 | ) | | 0.3 |
| | (1.4 | ) | | (5.7 | ) |
Net Current Period Other Comprehensive Income (Loss) | | 7.6 |
| | 2.6 |
| | (1.4 | ) | | 8.8 |
|
Balance in AOCI as of September 30, 2018 | | $ | (22.8 | ) | | $ | (12.7 | ) | | $ | (50.5 | ) | | $ | (86.0 | ) |
AEP
|
| | | | | | | | | | | | | | | | |
| | Cash Flow Hedges | | Pension | | |
Nine Months Ended September 30, 2019 | | Commodity | | Interest Rate | | and OPEB | | Total |
| | (in millions) |
Balance in AOCI as of December 31, 2018 | | $ | (23.0 | ) | | $ | (12.6 | ) | | $ | (84.8 | ) | | $ | (120.4 | ) |
Change in Fair Value Recognized in AOCI | | (92.3 | ) | | (4.5 | ) | (b) | — |
| | (96.8 | ) |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
Generation & Marketing Revenues (a) | | (0.1 | ) | | — |
| | — |
| | (0.1 | ) |
Purchased Electricity for Resale (a) | | 42.0 |
| | — |
| | — |
| | 42.0 |
|
Interest Expense (a) | | — |
| | 0.5 |
| | — |
| | 0.5 |
|
Amortization of Prior Service Cost (Credit) | | — |
| | — |
| | (14.3 | ) | | (14.3 | ) |
Amortization of Actuarial (Gains) Losses | | — |
| | — |
| | 9.0 |
| | 9.0 |
|
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | 41.9 |
| | 0.5 |
| | (5.3 | ) | | 37.1 |
|
Income Tax (Expense) Benefit | | 8.8 |
| | 0.1 |
| | (1.1 | ) | | 7.8 |
|
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | 33.1 |
| | 0.4 |
| | (4.2 | ) | | 29.3 |
|
Net Current Period Other Comprehensive Income (Loss) | | (59.2 | ) | | (4.1 | ) | | (4.2 | ) | | (67.5 | ) |
Balance in AOCI as of September 30, 2019 | | $ | (82.2 | ) | | $ | (16.7 | ) | | $ | (89.0 | ) | | $ | (187.9 | ) |
|
| | | | | | | | | | | | | | | | | | | | |
| | Cash Flow Hedges | | Securities | | | | |
| | | | Interest | | Available | | Pension | | |
Nine Months Ended September 30, 2018 | | Commodity | | Rate | | for Sale | | and OPEB | | Total |
| | (in millions) |
Balance in AOCI as of December 31, 2017 | | $ | (28.4 | ) | | $ | (13.0 | ) | | $ | 11.9 |
| | $ | (38.3 | ) | | $ | (67.8 | ) |
Change in Fair Value Recognized in AOCI | | 30.4 |
| | 2.3 |
| | — |
| | — |
| | 32.7 |
|
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | | | |
Generation & Marketing Revenues (a) | | (0.1 | ) | | — |
| | — |
| | — |
| | (0.1 | ) |
Purchased Electricity for Resale (a) | | (23.6 | ) | | — |
| | — |
| | — |
| | (23.6 | ) |
Interest Expense (a) | | — |
| | 0.9 |
| | — |
| | — |
| | 0.9 |
|
Amortization of Prior Service Cost (Credit) | | — |
| | — |
| | — |
| | (14.7 | ) | | (14.7 | ) |
Amortization of Actuarial (Gains) Losses | | — |
| | — |
| | — |
| | 9.6 |
| | 9.6 |
|
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | (23.7 | ) | | 0.9 |
| | — |
| | (5.1 | ) | | (27.9 | ) |
Income Tax (Expense) Benefit | | (5.0 | ) | | 0.2 |
| | — |
| | (1.1 | ) | | (5.9 | ) |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | (18.7 | ) | | 0.7 |
| | — |
| | (4.0 | ) | | (22.0 | ) |
Net Current Period Other Comprehensive Income (Loss) | | 11.7 |
| | 3.0 |
| | — |
| | (4.0 | ) | | 10.7 |
|
ASU 2018-02 Adoption | | (6.1 | ) | | (2.7 | ) | | — |
| | (8.2 | ) | | (17.0 | ) |
ASU 2016-01 Adoption | | — |
| | — |
| | (11.9 | ) | | — |
| | (11.9 | ) |
Balance in AOCI as of September 30, 2018 | | $ | (22.8 | ) | | $ | (12.7 | ) | | $ | — |
| | $ | (50.5 | ) | | $ | (86.0 | ) |
AEP
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 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) | 0 | | | (92.2) | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
Generation & Marketing Revenues (b) | | (0.3) | | | 0 | | | 0 | | | (0.3) | |
Purchased Electricity for Resale (b) | | 135.7 | | | 0 | | | 0 | | | 135.7 | |
Interest Expense (b) | | 0 | | | 3.6 | | | 0 | | | 3.6 | |
Amortization of Prior Service Cost (Credit) | | 0 | | | 0 | | | (14.4) | | | (14.4) | |
Amortization of Actuarial (Gains) Losses | | 0 | | | 0 | | | 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) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Cash Flow Hedges | | | | Pension | | |
Nine Months Ended September 30, 2019 | | Commodity | | Interest Rate | | and OPEB | | Total |
| | (in millions) | | | | | | |
Balance in AOCI as of December 31, 2018 | | $ | (23.0) | | | $ | (12.6) | | | $ | (84.8) | | | $ | (120.4) | |
Change in Fair Value Recognized in AOCI | | (92.3) | | | (4.5) | | (c) | 0 | | | (96.8) | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
Generation & Marketing Revenues (b) | | (0.1) | | | 0 | | | 0 | | | (0.1) | |
Purchased Electricity for Resale (b) | | 42.0 | | | 0 | | | 0 | | | 42.0 | |
Interest Expense (b) | | 0 | | | 0.5 | | | 0 | | | 0.5 | |
Amortization of Prior Service Cost (Credit) | | 0 | | | 0 | | | (14.3) | | | (14.3) | |
Amortization of Actuarial (Gains) Losses | | 0 | | | 0 | | | 9.0 | | | 9.0 | |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | 41.9 | | | 0.5 | | | (5.3) | | | 37.1 | |
Income Tax (Expense) Benefit | | 8.8 | | | 0.1 | | | (1.1) | | | 7.8 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | 33.1 | | | 0.4 | | | (4.2) | | | 29.3 | |
Net Current Period Other Comprehensive Income (Loss) | | (59.2) | | | (4.1) | | | (4.2) | | | (67.5) | |
Balance in AOCI as of September 30, 2019 | | $ | (82.2) | | | $ | (16.7) | | | $ | (89.0) | | | $ | (187.9) | |
AEP Texas
| | | | | | | | | | | | | | | | | | | | | | |
| | | | 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 | | | | 0 | | | 0 | | | 0 | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Interest Expense (b) | | | | 0.4 | | | 0 | | | 0.4 | |
Amortization of Prior Service Cost (Credit) | | | | 0 | | | (0.1) | | | (0.1) | |
Amortization of Actuarial (Gains) Losses | | | | 0 | | | 0.1 | | | 0.1 | |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | | | 0.4 | | | 0 | | | 0.4 | |
Income Tax (Expense) Benefit | | | | 0.1 | | | 0 | | | 0.1 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | | 0.3 | | | 0 | | | 0.3 | |
Net Current Period Other Comprehensive Income (Loss) | | | | 0.3 | | | 0 | | | 0.3 | |
Balance in AOCI as of September 30, 2020 | | | | $ | (2.6) | | | $ | (9.3) | | | $ | (11.9) | |
| | | | Cash Flow Hedge – | | Pension | | | | | | Cash Flow Hedge – | | Pension | |
Three Months Ended September 30, 2019 | | Interest Rate | | and OPEB | | Total | Three Months Ended September 30, 2019 | | | Interest Rate | | and OPEB | | Total |
| (in millions) | | | (in millions) | |
Balance in AOCI as of June 30, 2019 | | $ | (3.9 | ) | | $ | (10.6 | ) | | $ | (14.5 | ) | Balance in AOCI as of June 30, 2019 | | | $ | (3.9) | | | $ | (10.6) | | | $ | (14.5) | |
Change in Fair Value Recognized in AOCI | | 0.3 |
| | — |
| | 0.3 |
| Change in Fair Value Recognized in AOCI | | | 0.3 | | | 0 | | | 0.3 | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | Amount of (Gain) Loss Reclassified from AOCI | | |
| Amortization of Prior Service Cost (Credit) | | — |
| | (0.1 | ) | | (0.1 | ) | Amortization of Prior Service Cost (Credit) | | | 0 | | | (0.1) | | | (0.1) | |
Amortization of Actuarial (Gains) Losses | | — |
| | 0.1 |
| | 0.1 |
| Amortization of Actuarial (Gains) Losses | | | 0 | | | 0.1 | | | 0.1 | |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | — |
| | — |
| | — |
| Reclassifications from AOCI, before Income Tax (Expense) Benefit | | | 0 | | | 0 | | | 0 | |
Income Tax (Expense) Benefit | | — |
| | — |
| | — |
| Income Tax (Expense) Benefit | | | 0 | | | 0 | | | 0 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | — |
| | — |
| | — |
| Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | 0 | | | 0 | | | 0 | |
Net Current Period Other Comprehensive Income (Loss) | | 0.3 |
| | — |
| | 0.3 |
| Net Current Period Other Comprehensive Income (Loss) | | | 0.3 | | | 0 | | | 0.3 | |
Balance in AOCI as of September 30, 2019 | | $ | (3.6 | ) | | $ | (10.6 | ) | | $ | (14.2 | ) | Balance in AOCI as of September 30, 2019 | | | $ | (3.6) | | | $ | (10.6) | | | $ | (14.2) | |
| | | | | | | | | | | | Cash Flow Hedge – | | Pension | |
Nine Months Ended September 30, 2020 | | Nine Months Ended September 30, 2020 | | | Interest Rate | | and OPEB | | Total |
| | Cash Flow Hedge – | | Pension | | | | | (in millions) | |
Three Months Ended September 30, 2018 | | Interest Rate | | and OPEB | | Total | |
| (in millions) | |
Balance in AOCI as of June 30, 2018 | | $ | (4.9 | ) | | $ | (9.8 | ) | | $ | (14.7 | ) | |
Balance in AOCI as of December 31, 2019 | | Balance in AOCI as of December 31, 2019 | | | $ | (3.4) | | | $ | (9.4) | | | $ | (12.8) | |
Change in Fair Value Recognized in AOCI | | — |
| | — |
| | — |
| Change in Fair Value Recognized in AOCI | | | 0 | | | 0 | | | 0 | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | Amount of (Gain) Loss Reclassified from AOCI | | |
Interest Expense (a) | | 0.4 |
| | — |
| | 0.4 |
| |
| Interest Expense (b) | | Interest Expense (b) | | | 1.0 | | | 0 | | | 1.0 | |
Amortization of Prior Service Cost (Credit) | | Amortization of Prior Service Cost (Credit) | | | 0 | | | (0.1) | | | (0.1) | |
Amortization of Actuarial (Gains) Losses | | Amortization of Actuarial (Gains) Losses | | | 0 | | | 0.2 | | | 0.2 | |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | 0.4 |
| | — |
| | 0.4 |
| Reclassifications from AOCI, before Income Tax (Expense) Benefit | | | 1.0 | | | 0.1 | | | 1.1 | |
Income Tax (Expense) Benefit | | 0.1 |
| | — |
| | 0.1 |
| Income Tax (Expense) Benefit | | | 0.2 | | | 0 | | | 0.2 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | 0.3 |
| | — |
| | 0.3 |
| Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | 0.8 | | | 0.1 | | | 0.9 | |
Net Current Period Other Comprehensive Income (Loss) | | 0.3 |
| | — |
| | 0.3 |
| Net Current Period Other Comprehensive Income (Loss) | | | 0.8 | | | 0.1 | | | 0.9 | |
Balance in AOCI as of September 30, 2018 | | $ | (4.6 | ) | | $ | (9.8 | ) | | $ | (14.4 | ) | |
Balance in AOCI as of September 30, 2020 | | Balance in AOCI as of September 30, 2020 | | | $ | (2.6) | | | $ | (9.3) | | | $ | (11.9) | |
| | | | Cash Flow Hedge – | | Pension | | | | | | Cash Flow Hedge – | | Pension | |
Nine Months Ended September 30, 2019 | | Interest Rate | | and OPEB | | Total | Nine Months Ended September 30, 2019 | | | Interest Rate | | and OPEB | | Total |
| (in millions) | | | (in millions) | |
Balance in AOCI as of December 31, 2018 | | $ | (4.4 | ) | | $ | (10.7 | ) | | $ | (15.1 | ) | Balance in AOCI as of December 31, 2018 | | | $ | (4.4) | | | $ | (10.7) | | | $ | (15.1) | |
Change in Fair Value Recognized in AOCI | | 0.3 |
| | — |
| | 0.3 |
| Change in Fair Value Recognized in AOCI | | | 0.3 | | | 0 | | | 0.3 | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | Amount of (Gain) Loss Reclassified from AOCI | | |
Interest Expense (a) | | 0.6 |
| | — |
| | 0.6 |
| |
| Interest Expense (b) | | Interest Expense (b) | | | 0.6 | | | 0 | | | 0.6 | |
Amortization of Prior Service Cost (Credit) | | — |
| | (0.1 | ) | | (0.1 | ) | Amortization of Prior Service Cost (Credit) | | | 0 | | | (0.1) | | | (0.1) | |
Amortization of Actuarial (Gains) Losses | | — |
| | 0.2 |
| | 0.2 |
| Amortization of Actuarial (Gains) Losses | | | 0 | | | 0.2 | | | 0.2 | |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | 0.6 |
| | 0.1 |
| | 0.7 |
| Reclassifications from AOCI, before Income Tax (Expense) Benefit | | | 0.6 | | | 0.1 | | | 0.7 | |
Income Tax (Expense) Benefit | | 0.1 |
| | — |
| | 0.1 |
| Income Tax (Expense) Benefit | | | 0.1 | | | 0 | | | 0.1 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | 0.5 |
| | 0.1 |
| | 0.6 |
| Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | 0.5 | | | 0.1 | | | 0.6 | |
Net Current Period Other Comprehensive Income (Loss) | | 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, 2019 | | $ | (3.6 | ) | | $ | (10.6 | ) | | $ | (14.2 | ) | Balance in AOCI as of September 30, 2019 | | | $ | (3.6) | | | $ | (10.6) | | | $ | (14.2) | |
|
| | | | | | | | | | | | |
| | Cash Flow Hedge – | | Pension | | |
Nine Months Ended September 30, 2018 | | Interest Rate | | and OPEB | | Total |
| (in millions) |
Balance in AOCI as of December 31, 2017 | | $ | (4.5 | ) | | $ | (8.1 | ) | | $ | (12.6 | ) |
Change in Fair Value Recognized in AOCI | | — |
| | — |
| | — |
|
Amount of (Gain) Loss Reclassified from AOCI | | | | | | |
Interest Expense (a) | | 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 |
|
ASU 2018-02 Adoption | | (0.9 | ) | | (1.8 | ) | | (2.7 | ) |
Balance in AOCI as of September 30, 2018 | | $ | (4.6 | ) | | $ | (9.8 | ) | | $ | (14.4 | ) |
APCo
| | | | | | | | | | | | | | | | | | | | | | |
| | | | 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 | | | 0.7 | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Interest Expense (b) | | | | (0.2) | | | 0 | | | (0.2) | |
Amortization of Prior Service Cost (Credit) | | | | 0 | | | (1.3) | | | (1.3) | |
Amortization of Actuarial (Gains) Losses | | | | 0 | | | 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) | |
| | | | Cash Flow Hedge – | | Pension | | | | | | Cash Flow Hedge – | | Pension | |
Three Months Ended September 30, 2019 | | Interest Rate | | and OPEB | | Total | Three Months Ended September 30, 2019 | | | Interest Rate | | and OPEB | | Total |
| (in millions) | | | (in millions) | |
Balance in AOCI as of June 30, 2019 | | $ | 1.4 |
| | $ | (8.1 | ) | | $ | (6.7 | ) | Balance in AOCI as of June 30, 2019 | | | $ | 1.4 | | | $ | (8.1) | | | $ | (6.7) | |
Change in Fair Value Recognized in AOCI | | (0.3 | ) | | — |
| | (0.3 | ) | Change in Fair Value Recognized in AOCI | | | (0.3) | | | 0 | | | (0.3) | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | Amount of (Gain) Loss Reclassified from AOCI | | |
| Amortization of Prior Service Cost (Credit) | | — |
| | (1.4 | ) | | (1.4 | ) | Amortization of Prior Service Cost (Credit) | | | 0 | | | (1.4) | | | (1.4) | |
Amortization of Actuarial (Gains) Losses | | — |
| | 0.6 |
| | 0.6 |
| Amortization of Actuarial (Gains) Losses | | | 0 | | | 0.6 | | | 0.6 | |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | — |
| | (0.8 | ) | | (0.8 | ) | Reclassifications from AOCI, before Income Tax (Expense) Benefit | | | 0 | | | (0.8) | | | (0.8) | |
Income Tax (Expense) Benefit | | — |
| | (0.2 | ) | | (0.2 | ) | Income Tax (Expense) Benefit | | | 0 | | | (0.2) | | | (0.2) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | — |
| | (0.6 | ) | | (0.6 | ) | Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | 0 | | | (0.6) | | | (0.6) | |
Net Current Period Other Comprehensive Income (Loss) | | (0.3 | ) | | (0.6 | ) | | (0.9 | ) | Net Current Period Other Comprehensive Income (Loss) | | | (0.3) | | | (0.6) | | | (0.9) | |
Balance in AOCI as of September 30, 2019 | | $ | 1.1 |
| | $ | (8.7 | ) | | $ | (7.6 | ) | Balance in AOCI as of September 30, 2019 | | | $ | 1.1 | | | $ | (8.7) | | | $ | (7.6) | |
| | | | | | | | | | | | | | | | | | | | | | |
| | | | 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) | | | 0 | | | (3.8) | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Interest Expense (b) | | | | (0.8) | | | 0 | | | (0.8) | |
Amortization of Prior Service Cost (Credit) | | | | 0 | | | (4.0) | | | (4.0) | |
Amortization of Actuarial (Gains) Losses | | | | 0 | | | 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) | |
| | | | | | | | | | | | Cash Flow Hedge – | | Pension | |
Nine Months Ended September 30, 2019 | | Nine Months Ended September 30, 2019 | | | Interest Rate | | and OPEB | | Total |
| | Cash Flow Hedge – | | Pension | | | | | (in millions) | |
Three Months Ended September 30, 2018 | | Interest Rate | | and OPEB | | Total | |
| (in millions) | |
Balance in AOCI as of June 30, 2018 | | $ | 2.3 |
| | $ | (2.7 | ) | | $ | (0.4 | ) | |
Balance in AOCI as of December 31, 2018 | | Balance in AOCI as of December 31, 2018 | | | $ | 1.8 | | | $ | (6.8) | | | $ | (5.0) | |
Change in Fair Value Recognized in AOCI | | — |
| | — |
| | — |
| Change in Fair Value Recognized in AOCI | | | (0.3) | | | 0 | | | (0.3) | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | Amount of (Gain) Loss Reclassified from AOCI | | |
Interest Expense (a) | | (0.4 | ) | | — |
| | (0.4 | ) | |
| Interest Expense (b) | | Interest Expense (b) | | | (0.5) | | | 0 | | | (0.5) | |
Amortization of Prior Service Cost (Credit) | | — |
| | (1.3 | ) | | (1.3 | ) | Amortization of Prior Service Cost (Credit) | | | 0 | | | (4.0) | | | (4.0) | |
Amortization of Actuarial (Gains) Losses | | — |
| | 0.4 |
| | 0.4 |
| Amortization of Actuarial (Gains) Losses | | | 0 | | | 1.6 | | | 1.6 | |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | (0.4 | ) | | (0.9 | ) | | (1.3 | ) | Reclassifications from AOCI, before Income Tax (Expense) Benefit | | | (0.5) | | | (2.4) | | | (2.9) | |
Income Tax (Expense) Benefit | | (0.1 | ) | | (0.2 | ) | | (0.3 | ) | Income Tax (Expense) Benefit | | | (0.1) | | | (0.5) | | | (0.6) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | (0.3 | ) | | (0.7 | ) | | (1.0 | ) | Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | (0.4) | | | (1.9) | | | (2.3) | |
Net Current Period Other Comprehensive Income (Loss) | | (0.3 | ) | | (0.7 | ) | | (1.0 | ) | Net Current Period Other Comprehensive Income (Loss) | | | (0.7) | | | (1.9) | | | (2.6) | |
Balance in AOCI as of September 30, 2018 | | $ | 2.0 |
| | $ | (3.4 | ) | | $ | (1.4 | ) | |
Balance in AOCI as of September 30, 2019 | | Balance in AOCI as of September 30, 2019 | | | $ | 1.1 | | | $ | (8.7) | | | $ | (7.6) | |
|
| | | | | | | | | | | | |
| | Cash Flow Hedge – | | Pension | | |
Nine Months Ended September 30, 2019 | | Interest Rate | | and OPEB | | Total |
| (in millions) |
Balance in AOCI as of December 31, 2018 | | $ | 1.8 |
| | $ | (6.8 | ) | | $ | (5.0 | ) |
Change in Fair Value Recognized in AOCI | | (0.3 | ) | | — |
| | (0.3 | ) |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | |
Interest Expense (a) | | (0.5 | ) | | — |
| | (0.5 | ) |
Amortization of Prior Service Cost (Credit) | | — |
| | (4.0 | ) | | (4.0 | ) |
Amortization of Actuarial (Gains) Losses | | — |
| | 1.6 |
| | 1.6 |
|
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | (0.5 | ) | | (2.4 | ) | | (2.9 | ) |
Income Tax (Expense) Benefit | | (0.1 | ) | | (0.5 | ) | | (0.6 | ) |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | (0.4 | ) | | (1.9 | ) | | (2.3 | ) |
Net Current Period Other Comprehensive Income (Loss) | | (0.7 | ) | | (1.9 | ) | | (2.6 | ) |
Balance in AOCI as of September 30, 2019 | | $ | 1.1 |
| | $ | (8.7 | ) | | $ | (7.6 | ) |
|
| | | | | | | | | | | | | | | | |
| | Cash Flow Hedges | | Pension | | |
Nine Months Ended September 30, 2018 | | Commodity | | Interest Rate | | and OPEB | | Total |
| | (in millions) |
Balance in AOCI as of December 31, 2017 | | $ | — |
| | $ | 2.2 |
| | $ | (0.9 | ) | | $ | 1.3 |
|
Change in Fair Value Recognized in AOCI | | (0.7 | ) | | — |
| | — |
| | (0.7 | ) |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
Purchased Electricity for Resale (a) | | 0.9 |
| | — |
| | — |
| | 0.9 |
|
Interest Expense (a) | | — |
| | (0.9 | ) | | — |
| | (0.9 | ) |
Amortization of Prior Service Cost (Credit) | | — |
| | — |
| | (3.9 | ) | | (3.9 | ) |
Amortization of Actuarial (Gains) Losses | | — |
| | — |
| | 1.0 |
| | 1.0 |
|
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | 0.9 |
| | (0.9 | ) | | (2.9 | ) | | (2.9 | ) |
Income Tax (Expense) Benefit | | 0.2 |
| | (0.2 | ) | | (0.6 | ) | | (0.6 | ) |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | 0.7 |
| | (0.7 | ) | | (2.3 | ) | | (2.3 | ) |
Net Current Period Other Comprehensive Income (Loss) | | — |
| | (0.7 | ) | | (2.3 | ) | | (3.0 | ) |
ASU 2018-02 Adoption | | — |
| | 0.5 |
| | (0.2 | ) | | 0.3 |
|
Balance in AOCI as of September 30, 2018 | | $ | — |
| | $ | 2.0 |
| | $ | (3.4 | ) | | $ | (1.4 | ) |
I&M
| | | | | | | | | | | | | | | | | | | | | | |
| | | | 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 | | | | 0 | | | 0 | | | 0 | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Interest Expense (b) | | | | 0.5 | | | 0 | | | 0.5 | |
Amortization of Prior Service Cost (Credit) | | | | 0 | | | (0.3) | | | (0.3) | |
Amortization of Actuarial (Gains) Losses | | | | 0 | | | 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 | | | 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) | |
| | | | Cash Flow Hedge – | | Pension | | | | | | Cash Flow Hedge – | | Pension | |
Three Months Ended September 30, 2019 | | Interest Rate | | and OPEB | | Total | Three Months Ended September 30, 2019 | | | Interest Rate | | and OPEB | | Total |
| (in millions) | | | (in millions) | |
Balance in AOCI as of June 30, 2019 | | $ | (10.7 | ) | | $ | (2.4 | ) | | $ | (13.1 | ) | Balance in AOCI as of June 30, 2019 | | | $ | (10.7) | | | $ | (2.4) | | | $ | (13.1) | |
Change in Fair Value Recognized in AOCI | | 0.4 |
| | — |
| | 0.4 |
| Change in Fair Value Recognized in AOCI | | | 0.4 | | | 0 | | | 0.4 | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | Amount of (Gain) Loss Reclassified from AOCI | | |
| Amortization of Prior Service Cost (Credit) | | — |
| | (0.2 | ) | | (0.2 | ) | Amortization of Prior Service Cost (Credit) | | | 0 | | | (0.2) | | | (0.2) | |
Amortization of Actuarial (Gains) Losses | | — |
| | 0.2 |
| | 0.2 |
| Amortization of Actuarial (Gains) Losses | | | 0 | | | 0.2 | | | 0.2 | |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | — |
| | — |
| | — |
| Reclassifications from AOCI, before Income Tax (Expense) Benefit | | | 0 | | | 0 | | | 0 | |
Income Tax (Expense) Benefit | | — |
| | — |
| | — |
| Income Tax (Expense) Benefit | | | 0 | | | 0 | | | 0 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | — |
| | — |
| | — |
| Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | 0 | | | 0 | | | 0 | |
Net Current Period Other Comprehensive Income (Loss) | | 0.4 |
| | — |
| | 0.4 |
| Net Current Period Other Comprehensive Income (Loss) | | | 0.4 | | | 0 | | | 0.4 | |
Balance in AOCI as of September 30, 2019 | | $ | (10.3 | ) | | $ | (2.4 | ) | | $ | (12.7 | ) | Balance in AOCI as of September 30, 2019 | | | $ | (10.3) | | | $ | (2.4) | | | $ | (12.7) | |
| | | | | | | | | | | | | | | | | | | | | | |
| | | | 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 | | | | 0 | | | 0 | | | 0 | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Interest Expense (b) | | | | 1.5 | | | 0 | | | 1.5 | |
Amortization of Prior Service Cost (Credit) | | | | 0 | | | (0.6) | | | (0.6) | |
Amortization of Actuarial (Gains) Losses | | | | 0 | | | 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 | | | 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) | |
| | | | | | | | | | | | Cash Flow Hedge – | | Pension | |
Nine Months Ended September 30, 2019 | | Nine Months Ended September 30, 2019 | | | Interest Rate | | and OPEB | | Total |
| | Cash Flow Hedge – | | Pension | | | | | (in millions) | |
Three Months Ended September 30, 2018 | | Interest Rate | | and OPEB | | Total | |
| (in millions) | |
Balance in AOCI as of June 30, 2018 | | $ | (12.2 | ) | | $ | (1.7 | ) | | $ | (13.9 | ) | |
Balance in AOCI as of December 31, 2018 | | Balance in AOCI as of December 31, 2018 | | | $ | (11.5) | | | $ | (2.3) | | | $ | (13.8) | |
Change in Fair Value Recognized in AOCI | | — |
| | — |
| | — |
| Change in Fair Value Recognized in AOCI | | | 0.4 | | | 0 | | | 0.4 | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | Amount of (Gain) Loss Reclassified from AOCI | | |
Interest Expense (a) | | 0.4 |
| | — |
| | 0.4 |
| |
| Interest Expense (b) | | Interest Expense (b) | | | 1.0 | | | 0 | | | 1.0 | |
Amortization of Prior Service Cost (Credit) | | — |
| | (0.2 | ) | | (0.2 | ) | Amortization of Prior Service Cost (Credit) | | | 0 | | | (0.6) | | | (0.6) | |
Amortization of Actuarial (Gains) Losses | | — |
| | 0.2 |
| | 0.2 |
| Amortization of Actuarial (Gains) Losses | | | 0 | | | 0.5 | | | 0.5 | |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | 0.4 |
| | — |
| | 0.4 |
| Reclassifications from AOCI, before Income Tax (Expense) Benefit | | | 1.0 | | | (0.1) | | | 0.9 | |
Income Tax (Expense) Benefit | | 0.1 |
| | — |
| | 0.1 |
| Income Tax (Expense) Benefit | | | 0.2 | | | 0 | | | 0.2 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | 0.3 |
| | — |
| | 0.3 |
| Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | 0.8 | | | (0.1) | | | 0.7 | |
Net Current Period Other Comprehensive Income (Loss) | | 0.3 |
| | — |
| | 0.3 |
| Net Current Period Other Comprehensive Income (Loss) | | | 1.2 | | | (0.1) | | | 1.1 | |
Balance in AOCI as of September 30, 2018 | | $ | (11.9 | ) | | $ | (1.7 | ) | | $ | (13.6 | ) | |
Balance in AOCI as of September 30, 2019 | | Balance in AOCI as of September 30, 2019 | | | $ | (10.3) | | | $ | (2.4) | | | $ | (12.7) | |
|
| | | | | | | | | | | | |
| | Cash Flow Hedge – | | Pension | | |
Nine Months Ended September 30, 2019 | | Interest Rate | | and OPEB | | Total |
| (in millions) |
Balance in AOCI as of December 31, 2018 | | $ | (11.5 | ) | | $ | (2.3 | ) | | $ | (13.8 | ) |
Change in Fair Value Recognized in AOCI | | 0.4 |
| | — |
| | 0.4 |
|
Amount of (Gain) Loss Reclassified from AOCI | | | | | | |
Interest Expense (a) | | 1.0 |
| | — |
| | 1.0 |
|
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 | | 1.0 |
| | (0.1 | ) | | 0.9 |
|
Income Tax (Expense) Benefit | | 0.2 |
| | — |
| | 0.2 |
|
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | 0.8 |
| | (0.1 | ) | | 0.7 |
|
Net Current Period Other Comprehensive Income (Loss) | | 1.2 |
| | (0.1 | ) | | 1.1 |
|
Balance in AOCI as of September 30, 2019 | | $ | (10.3 | ) | | $ | (2.4 | ) | | $ | (12.7 | ) |
|
| | | | | | | | | | | | |
| | Cash Flow Hedge – | | Pension | | |
Nine Months Ended September 30, 2018 | | Interest Rate | | and OPEB | | Total |
| | (in millions) |
Balance in AOCI as of December 31, 2017 | | $ | (10.7 | ) | | $ | (1.4 | ) | | $ | (12.1 | ) |
Change in Fair Value Recognized in AOCI | | — |
| | — |
| | — |
|
Amount of (Gain) Loss Reclassified from AOCI | | | | | | |
Interest Expense (a) | | 1.5 |
| | — |
| | 1.5 |
|
Amortization of Prior Service Cost (Credit) | | — |
| | (0.6 | ) | | (0.6 | ) |
Amortization of Actuarial (Gains) Losses | | — |
| | 0.6 |
| | 0.6 |
|
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 |
|
ASU 2018-02 Adoption | | (2.4 | ) | | (0.3 | ) | | (2.7 | ) |
Balance in AOCI as of September 30, 2018 | | $ | (11.9 | ) | | $ | (1.7 | ) | | $ | (13.6 | ) |
OPCo
|
| | | | |
| | Cash Flow Hedge – |
Three Months Ended September 30, 2019 | | Interest Rate |
| (in millions) |
Balance in AOCI as of June 30, 2019 | | $ | 0.3 |
|
Change in Fair Value Recognized in AOCI | | (0.2 | ) |
Amount of (Gain) Loss Reclassified from AOCI | | |
Interest Expense (a) | | (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) | | (0.3 | ) |
Balance in AOCI as of September 30, 2019 | | $ | — |
|
|
| | | | |
| | Cash Flow Hedge – |
Three Months Ended September 30, 2018 | | Interest Rate |
| (in millions) |
Balance in AOCI as of June 30, 2018 | | $ | 1.7 |
|
Change in Fair Value Recognized in AOCI | | — |
|
Amount of (Gain) Loss Reclassified from AOCI | | |
Interest Expense (a) | | (0.5 | ) |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | (0.5 | ) |
Income Tax (Expense) Benefit | | (0.1 | ) |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | (0.4 | ) |
Net Current Period Other Comprehensive Income (Loss) | | (0.4 | ) |
Balance in AOCI as of September 30, 2018 | | $ | 1.3 |
|
|
| | | | |
| | Cash Flow Hedge – |
Nine Months Ended September 30, 2019 | | Interest Rate |
| (in millions) |
Balance in AOCI as of December 31, 2018 | | $ | 1.0 |
|
Change in Fair Value Recognized in AOCI | | (0.2 | ) |
Amount of (Gain) Loss Reclassified from AOCI | | |
Interest Expense (a) | | (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) | | (1.0 | ) |
Balance in AOCI as of September 30, 2019 | | $ | — |
|
|
| | | | |
| | Cash Flow Hedge – |
Nine Months Ended September 30, 2018 | | Interest Rate |
| (in millions) |
Balance in AOCI as of December 31, 2017 | | $ | 1.9 |
|
Change in Fair Value Recognized in AOCI | | — |
|
Amount of (Gain) Loss Reclassified from AOCI | | |
Interest Expense (a) | | (1.3 | ) |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | (1.3 | ) |
Income Tax (Expense) Benefit | | (0.3 | ) |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | (1.0 | ) |
Net Current Period Other Comprehensive Income (Loss) | | (1.0 | ) |
ASU 2018-02 Adoption | | 0.4 |
|
Balance in AOCI as of September 30, 2018 | | $ | 1.3 |
|
PSO
|
| | | | |
| | Cash Flow Hedge – |
Three Months Ended September 30, 2019 | | Interest Rate |
| (in millions) |
Balance in AOCI as of June 30, 2019 | | $ | 1.6 |
|
Change in Fair Value Recognized in AOCI | | (0.3 | ) |
Amount of (Gain) Loss Reclassified from AOCI | | |
Interest Expense (a) | | 0.2 |
|
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | 0.2 |
|
Income Tax (Expense) Benefit | | 0.1 |
|
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | 0.1 |
|
Net Current Period Other Comprehensive Income (Loss) | | (0.2 | ) |
Balance in AOCI as of September 30, 2019 | | $ | 1.4 |
|
|
| | | | |
| | Cash Flow Hedge – |
Three Months Ended September 30, 2018 | | Interest Rate |
| (in millions) |
Balance in AOCI as of June 30, 2018 | | $ | 2.6 |
|
Change in Fair Value Recognized in AOCI | | — |
|
Amount of (Gain) Loss Reclassified from AOCI | | |
Interest Expense (a) | | (0.2 | ) |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | (0.2 | ) |
Income Tax (Expense) Benefit | | — |
|
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | (0.2 | ) |
Net Current Period Other Comprehensive Income (Loss) | | (0.2 | ) |
Balance in AOCI as of September 30, 2018 | | $ | 2.4 |
|
|
| | | | |
| | Cash Flow Hedge – |
Nine Months Ended September 30, 2019 | | Interest Rate |
| (in millions) |
Balance in AOCI as of December 31, 2018 | | $ | 2.1 |
|
Change in Fair Value Recognized in AOCI | | (0.3 | ) |
Amount of (Gain) Loss Reclassified from AOCI | | |
Interest Expense (a) | | (0.5 | ) |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | (0.5 | ) |
Income Tax (Expense) Benefit | | (0.1 | ) |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | (0.4 | ) |
Net Current Period Other Comprehensive Income (Loss) | | (0.7 | ) |
Balance in AOCI as of September 30, 2019 | | $ | 1.4 |
|
|
| | | | |
| | Cash Flow Hedge – |
Nine Months Ended September 30, 2018 | | Interest Rate |
| (in millions) |
Balance in AOCI as of December 31, 2017 | | $ | 2.6 |
|
Change in Fair Value Recognized in AOCI | | — |
|
Amount of (Gain) Loss Reclassified from AOCI | | |
Interest Expense (a) | | (0.9 | ) |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | (0.9 | ) |
Income Tax (Expense) Benefit | | (0.2 | ) |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | (0.7 | ) |
Net Current Period Other Comprehensive Income (Loss) | | (0.7 | ) |
ASU 2018-02 Adoption | | 0.5 |
|
Balance in AOCI as of September 30, 2018 | | $ | 2.4 |
|
SWEPCo
|
| | | | | | | | | | | | |
| | Cash Flow Hedge – | | Pension | | |
Three Months Ended September 30, 2019 | | Interest Rate | | and OPEB | | Total |
| (in millions) |
Balance in AOCI as of June 30, 2019 | | $ | (2.5 | ) | | $ | (2.7 | ) | | $ | (5.2 | ) |
Change in Fair Value Recognized in AOCI | | 0.3 |
| | — |
| | 0.3 |
|
Amount of (Gain) Loss Reclassified from AOCI | | | | | | |
Amortization of Prior Service Cost (Credit) | | — |
| | (0.5 | ) | | (0.5 | ) |
Amortization of Actuarial (Gains) Losses | | — |
| | 0.2 |
| | 0.2 |
|
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | — |
| | (0.3 | ) | | (0.3 | ) |
Income Tax (Expense) Benefit | | — |
| | — |
| | — |
|
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, 2019 | | $ | (2.2 | ) | | $ | (3.0 | ) | | $ | (5.2 | ) |
|
| | | | | | | | | | | | |
| | Cash Flow Hedge – | | Pension | | |
Three Months Ended September 30, 2018 | | Interest Rate | | and OPEB | | Total |
| (in millions) |
Balance in AOCI as of June 30, 2018 | | $ | (6.4 | ) | | $ | 1.7 |
| | $ | (4.7 | ) |
Change in Fair Value Recognized in AOCI | | 2.3 |
| | — |
| | 2.3 |
|
Amount of (Gain) Loss Reclassified from AOCI | | | | | | |
Interest Expense (a) | | 0.5 |
| | — |
| | 0.5 |
|
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 | | 0.5 |
| | (0.4 | ) | | 0.1 |
|
Income Tax (Expense) Benefit | | 0.1 |
| | (0.1 | ) | | — |
|
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | 0.4 |
| | (0.3 | ) | | 0.1 |
|
Net Current Period Other Comprehensive Income (Loss) | | 2.7 |
| | (0.3 | ) | | 2.4 |
|
Balance in AOCI as of September 30, 2018 | | $ | (3.7 | ) | | $ | 1.4 |
| | $ | (2.3 | ) |
|
| | | | | | | | | | | | |
| | Cash Flow Hedge – | | Pension | | |
Nine Months Ended September 30, 2019 | | Interest Rate | | and OPEB | | Total |
| (in millions) |
Balance in AOCI as of December 31, 2018 | | $ | (3.3 | ) | | $ | (2.1 | ) | | $ | (5.4 | ) |
Change in Fair Value Recognized in AOCI | | 0.3 |
| | — |
| | 0.3 |
|
Amount of (Gain) Loss Reclassified from AOCI | | | | | | |
Interest Expense (a) | | 1.0 |
| | — |
| | 1.0 |
|
Amortization of Prior Service Cost (Credit) | | — |
| | (1.5 | ) | | (1.5 | ) |
Amortization of Actuarial (Gains) Losses | | — |
| | 0.4 |
| | 0.4 |
|
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | 1.0 |
| | (1.1 | ) | | (0.1 | ) |
Income Tax (Expense) Benefit | | 0.2 |
| | (0.2 | ) | | — |
|
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | 0.8 |
| | (0.9 | ) | | (0.1 | ) |
Net Current Period Other Comprehensive Income (Loss) | | 1.1 |
| | (0.9 | ) | | 0.2 |
|
Balance in AOCI as of September 30, 2019 | | $ | (2.2 | ) | | $ | (3.0 | ) | | $ | (5.2 | ) |
|
| | | | | | | | | | | | |
| | Cash Flow Hedge – | | Pension | | |
Nine Months Ended September 30, 2018 | | Interest Rate | | and OPEB | | Total |
| (in millions) |
Balance in AOCI as of December 31, 2017 | | $ | (6.0 | ) | | $ | 2.0 |
| | $ | (4.0 | ) |
Change in Fair Value Recognized in AOCI | | 2.3 |
| | — |
| | 2.3 |
|
Amount of (Gain) Loss Reclassified from AOCI | | | | | | |
Interest Expense (a) | | 1.6 |
| | — |
| | 1.6 |
|
Amortization of Prior Service Cost (Credit) | | — |
| | (1.5 | ) | | (1.5 | ) |
Amortization of Actuarial (Gains) Losses | | — |
| | 0.2 |
| | 0.2 |
|
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | 1.6 |
| | (1.3 | ) | | 0.3 |
|
Income Tax (Expense) Benefit | | 0.3 |
| | (0.3 | ) | | — |
|
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | 1.3 |
| | (1.0 | ) | | 0.3 |
|
Net Current Period Other Comprehensive Income (Loss) | | 3.6 |
| | (1.0 | ) | | 2.6 |
|
ASU 2018-02 Adoption | | (1.3 | ) | | 0.4 |
| | (0.9 | ) |
Balance in AOCI as of September 30, 2018 | | $ | (3.7 | ) | | $ | 1.4 |
| | $ | (2.3 | ) |
| | | | | | | | | | | | | | | | | | |
(a) | Amounts reclassified to the referenced line item on the statements of income. |
| | Cash Flow Hedge – | | | | | | | | |
(b) | The change in fair value includes $2 million and $6 million related to AEP's investment in joint venture wind farms acquired as part of the purchase of Sempra Renewables LLC for the three and nine months endedThree Months Ended September 30, 2019, respectively. See “Sempra Renewables LLC” section2020 | | | | Interest Rate | | | | | | | | |
| | | (in millions) | | | | | | | | | |
Balance in AOCI as of Note 14 for additional information.June 30, 2020 | | | | $ | 0 | | | | | | | | | |
Change in Fair Value Recognized in AOCI | | | | 0 | | | | | | | | | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
Interest Expense (b) | | | | 0 | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | | | 0 | | | | | | | | | |
Income Tax (Expense) Benefit | | | | 0 | | | | | | | | | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | | 0 | | | | | | | | | |
Net Current Period Other Comprehensive Income (Loss) | | | | 0 | | | | | | | | | |
Balance in AOCI as of September 30, 2020 | | | | $ | 0 | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| | | | Cash Flow Hedge – | | | | | | | | |
Three Months Ended September 30, 2019 | | | | Interest Rate | | | | | | | | |
| | | (in millions) | | | | | | | | | |
Balance in AOCI as of June 30, 2019 | | | | $ | 0.3 | | | | | | | | | |
Change in Fair Value Recognized in AOCI | | | | (0.2) | | | | | | | | | |
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 | | | | 0 | | | | | | | | | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | | (0.1) | | | | | | | | | |
Net Current Period Other Comprehensive Income (Loss) | | | | (0.3) | | | | | | | | | |
Balance in AOCI as of September 30, 2019 | | | | $ | 0 | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| | | | Cash Flow Hedge – | | | | | | | | |
Nine Months Ended September 30, 2020 | | | | Interest Rate | | | | | | | | |
| | | (in millions) | | | | | | | | | |
Balance in AOCI as of December 31, 2019 | | | | $ | 0 | | | | | | | | | |
Change in Fair Value Recognized in AOCI | | | | 0 | | | | | | | | | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
Interest Expense (b) | | | | 0 | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | | | 0 | | | | | | | | | |
Income Tax (Expense) Benefit | | | | 0 | | | | | | | | | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | | 0 | | | | | | | | | |
Net Current Period Other Comprehensive Income (Loss) | | | | 0 | | | | | | | | | |
Balance in AOCI as of September 30, 2020 | | | | $ | 0 | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| | | | Cash Flow Hedge – | | | | | | | | |
Nine Months Ended September 30, 2019 | | | | Interest Rate | | | | | | | | |
| | | (in millions) | | | | | | | | | |
Balance in AOCI as of December 31, 2018 | | | | $ | 1.0 | | | | | | | | | |
Change in Fair Value Recognized in AOCI | | | | (0.2) | | | | | | | | | |
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) | | | | (1.0) | | | | | | | | | |
Balance in AOCI as of September 30, 2019 | | | | $ | 0 | | | | | | | | | |
PSO
| | | | | | | | | | | | | | |
| | | | Cash Flow Hedge – | | | | |
Three Months Ended September 30, 2020 | | | | Interest Rate | | | | |
| | | (in millions) | | | | | |
Balance in AOCI as of June 30, 2020 | | | | $ | 0.6 | | | | | |
Change in Fair Value Recognized in AOCI | | | | 0 | | | | | |
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 | | | | 0 | | | | | |
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, 2020 | | | | $ | 0.3 | | | | | |
| | | | | | | | | | | | | | |
| | | | Cash Flow Hedge – | | | | |
Three Months Ended September 30, 2019 | | | | Interest Rate | | | | |
| | | (in millions) | | | | | |
Balance in AOCI as of June 30, 2019 | | | | $ | 1.6 | | | | | |
Change in Fair Value Recognized in AOCI | | | | (0.3) | | | | | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Interest Expense (b) | | | | 0.2 | | | | | |
| | | | | | | | |
| | | | | | | | |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | | | 0.2 | | | | | |
Income Tax (Expense) Benefit | | | | 0.1 | | | | | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | | 0.1 | | | | | |
Net Current Period Other Comprehensive Income (Loss) | | | | (0.2) | | | | | |
Balance in AOCI as of September 30, 2019 | | | | $ | 1.4 | | | | | |
| | | | | | | | | | | | | | |
| | | | 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 | | | | 0 | | | | | |
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 | | | | | |
| | | | | | | | | | | | | | |
| | | | Cash Flow Hedge – | | | | |
Nine Months Ended September 30, 2019 | | | | Interest Rate | | | | |
| | | (in millions) | | | | | |
Balance in AOCI as of December 31, 2018 | | | | $ | 2.1 | | | | | |
Change in Fair Value Recognized in AOCI | | | | (0.3) | | | | | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Interest Expense (b) | | | | (0.5) | | | | | |
| | | | | | | | |
| | | | | | | | |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | | | (0.5) | | | | | |
Income Tax (Expense) Benefit | | | | (0.1) | | | | | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | | (0.4) | | | | | |
Net Current Period Other Comprehensive Income (Loss) | | | | (0.7) | | | | | |
Balance in AOCI as of September 30, 2019 | | | | $ | 1.4 | | | | | |
SWEPCo
| | | | | | | | | | | | | | | | | | | | | | |
| | | | 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 | | | | 0 | | | 0 | | | 0 | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Interest Expense (b) | | | | 0.5 | | | 0 | | | 0.5 | |
Amortization of Prior Service Cost (Credit) | | | | 0 | | | (0.5) | | | (0.5) | |
Amortization of Actuarial (Gains) Losses | | | | 0 | | | 0 | | | 0 | |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | | | 0.5 | | | (0.5) | | | 0 | |
Income Tax (Expense) Benefit | | | | 0.1 | | | (0.1) | | | 0 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | | 0.4 | | | (0.4) | | | 0 | |
Net Current Period Other Comprehensive Income (Loss) | | | | 0.4 | | | (0.4) | | | 0 | |
Balance in AOCI as of September 30, 2020 | | | | $ | (0.7) | | | $ | (0.6) | | | $ | (1.3) | |
| | | | | | | | | | | | | | | | | | | | | | |
| | | | Cash Flow Hedge – | | Pension | | |
Three Months Ended September 30, 2019 | | | | Interest Rate | | and OPEB | | Total |
| | | (in millions) | | | | | |
Balance in AOCI as of June 30, 2019 | | | | $ | (2.5) | | | $ | (2.7) | | | $ | (5.2) | |
Change in Fair Value Recognized in AOCI | | | | 0.3 | | | 0 | | | 0.3 | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Amortization of Prior Service Cost (Credit) | | | | 0 | | | (0.5) | | | (0.5) | |
Amortization of Actuarial (Gains) Losses | | | | 0 | | | 0.2 | | | 0.2 | |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | | | 0 | | | (0.3) | | | (0.3) | |
Income Tax (Expense) Benefit | | | | 0 | | | 0 | | | 0 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | | 0 | | | (0.3) | | | (0.3) | |
Net Current Period Other Comprehensive Income (Loss) | | | | 0.3 | | | (0.3) | | | 0 | |
Balance in AOCI as of September 30, 2019 | | | | $ | (2.2) | | | $ | (3.0) | | | $ | (5.2) | |
SWEPCo
| | | | | | | | | | | | | | | | | | | | | | |
| | | | 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 | | | | $ | (1.8) | | | $ | 0.5 | | | $ | (1.3) | |
Change in Fair Value Recognized in AOCI | | | | 0 | | | 0 | | | 0 | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Interest Expense (b) | | | | 1.4 | | | 0 | | | 1.4 | |
Amortization of Prior Service Cost (Credit) | | | | 0 | | | (1.5) | | | (1.5) | |
Amortization of Actuarial (Gains) Losses | | | | 0 | | | 0.1 | | | 0.1 | |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | | | 1.4 | | | (1.4) | | | 0 | |
Income Tax (Expense) Benefit | | | | 0.3 | | | (0.3) | | | 0 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | | 1.1 | | | (1.1) | | | 0 | |
Net Current Period Other Comprehensive Income (Loss) | | | | 1.1 | | | (1.1) | | | 0 | |
Balance in AOCI as of September 30, 2020 | | | | $ | (0.7) | | | $ | (0.6) | | | $ | (1.3) | |
| | | | | | | | | | | | | | | | | | | | | | |
| | | | Cash Flow Hedge – | | Pension | | |
Nine Months Ended September 30, 2019 | | | | Interest Rate | | and OPEB | | Total |
| | | (in millions) | | | | | |
Balance in AOCI as of December 31, 2018 | | | | $ | (3.3) | | | $ | (2.1) | | | $ | (5.4) | |
Change in Fair Value Recognized in AOCI | | | | 0.3 | | | 0 | | | 0.3 | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Interest Expense (b) | | | | 1.0 | | | 0 | | | 1.0 | |
Amortization of Prior Service Cost (Credit) | | | | 0 | | | (1.5) | | | (1.5) | |
Amortization of Actuarial (Gains) Losses | | | | 0 | | | 0.4 | | | 0.4 | |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | | | 1.0 | | | (1.1) | | | (0.1) | |
Income Tax (Expense) Benefit | | | | 0.2 | | | (0.2) | | | 0 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | | 0.8 | | | (0.9) | | | (0.1) | |
Net Current Period Other Comprehensive Income (Loss) | | | | 1.1 | | | (0.9) | | | 0.2 | |
Balance in AOCI as of September 30, 2019 | | | | $ | (2.2) | | | $ | (3.0) | | | $ | (5.2) | |
(a)The change in fair value includes $(1) million and $6 million related to AEP's investment in joint venture wind farms acquired as part of the purchase of Sempra Renewables LLC for the three and nine months ended September 30, 2020, respectively.
(b)Amounts reclassified to the referenced line item on the statements of income.
(c)The change in fair value includes $2 million and $6 million related to AEP’s investment in joint venture wind farms acquired as part of the purchase of Sempra Renewables LLC for the three and nine months ended September 30, 2019, respectively.
4. RATE MATTERS
The disclosures in this note apply to all Registrants unless indicated otherwise.
As discussed in the 20182019 Annual Report, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 20182019 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 20192020 and updates the 20182019 Annual Report.
Regulated Generating UnitUnits to be Retired by 2020 (Applies to AEP, PSO and PSO)SWEPCo)
In September 2018, management announced that the Oklaunion Power Station iswas probable of abandonment and iswas expected to be retired. The Oklaunion Power Station was retired in September 2020. PSO will seek recovery of the Oklaunion Power Station in its next base rate case. In October 2020, the Oklaunion Power Station site was sold to a non-affiliated third-party. See “Oklaunion Power Station” section of Note 6 for additional information.
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 October 2020. December 2026. In March 2020, management announced plans to retire the plant in 2021.
The table below summarizes the plant investment and their cost of removal, currently being recovered, as well as the regulatory assetassets for accelerated depreciation for the generating unitunits as of September 30, 2019. See “2018 Oklahoma Base Rate Case” below for additional information.2020.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Plant | | Gross Investment Including CWIP | | Accumulated Depreciation | | Net Investment | | Accelerated Depreciation Regulatory Asset | | | Materials and Supplies | | Cost of Removal Regulatory Liability | | Expected Retirement Date | | Remaining Recovery Period |
| | (dollars in millions) | | | | | | | | | | | | | | | |
Oklaunion Power Station | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 38.0 | | (a) | | $ | 3.4 | | | $ | 5.2 | | | 2020 | | 27 years |
Dolet Hills Power Station | | 346.7 | | | 250.0 | | | $ | 96.7 | | | 50.4 | | (b) | | 5.8 | | | 24.0 | | | 2021 | | 27 years |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Gross Investment | | Accumulated Depreciation | | Net Investment | | Accelerated Depreciation Regulatory Asset (a) | | Materials and Supplies | | Cost of Removal Regulatory Liability | | Expected Retirement Date | | Remaining Recovery Period |
(dollars in millions) |
$ | 106.6 |
| | $ | 80.6 |
| | $ | 26.0 |
| | $ | 21.9 |
| | $ | 3.2 |
| | $ | 5.1 |
| | 2020 | | 27 years |
(a)In October 2018, PSO changed depreciation rates to utilize the 2020 end-of-life and defer depreciation expense to a regulatory asset for the amount in excess of the previously OCC-approved depreciation rates for Oklaunion Power Station.
(b)In January 2020, SWEPCo changed depreciation rates to utilize the 2026 end-of-life and defer depreciation expense to a regulatory asset for the amount in excess of the previously APSC-approved depreciation rates for Dolet Hills Power Station. In March 2020, SWEPCo changed depreciation rates again to utilize the accelerated 2021 end-of-life.
| |
(a) | In October 2018, PSO changed depreciation rates to utilize the 2020 end-of-life and defer depreciation expense to a regulatory asset for the amount in excess of the previously OCC-approved depreciation rates for Oklaunion Power Station. See “2018 Oklahoma Base Rate Case” discussion below for additional information. |
Dolet Hills Power Station and Related Fuel Operations (Applies to AEP and SWEPCo)
During the second quarter of 2019, the Dolet Hills Power Station initiated a seasonal operating schedule. In January 2020, in accordance with the terms of SWEPCo’s settlement of its base rate review filed with the APSC, management announced that SWEPCo will seek regulatory approval to retire the Dolet Hills Power Station by the end of 2026. DHLC provides 100% of the fuel supply to Dolet Hills Power Station. After careful consideration of current economic conditions, and particularly for the benefit of their customers, management of SWEPCo and CLECO determined DHLC would not proceed developing additional Oxbow Lignite Company (Oxbow) mining areas for future lignite extraction and ceased extraction of lignite at the mine in May 2020. Based on these actions, management revised the estimated useful life of DHLC’s and Oxbow’s assets to coincide with the date at which extraction was discontinued in the second quarter of 2020 and the date at which delivery of lignite is expected to cease in September 2021. 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 March 2020, primarily due to the revision in the useful life of DHLC, SWEPCo recorded a revision to increase estimated ARO liabilities by $21 million. 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 costs are recoverable by SWEPCo through base rates. SWEPCo’s share of the net investment in the Dolet Hills Power Station is $153 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 Lignite Mining Agreement, DHLC bills SWEPCo its proportionate share of incurred lignite extraction and associated mining-related costs as fuel is delivered. As of September 30, 2020, DHLC has unbilled lignite inventory and fixed costs of $36 million that will be billed to SWEPCo prior to the closure of the Dolet Hills Power Station. In 2009, SWEPCo acquired interests in Oxbow, which owns mineral rights and leases land. Under a Joint Operating Agreement pertaining to the Oxbow mineral rights and land leases, Oxbow bills SWEPCo its proportionate share of incurred costs. As of September 30, 2020, Oxbow has unbilled fixed costs of $10 million that will be billed to SWEPCo prior to the closure of the Dolet Hills Power Station. DHLC and Oxbow have billed SWEPCo $111 million for lignite deliveries from April 2020 through September 2020, which primarily includes accelerated depreciation and amortization of fixed costs. Additional operational and land-related costs are expected to be incurred by DHLC and Oxbow and billed to SWEPCo prior to the closure of the Dolet Hills Power Station and recovered through fuel clauses.
In October 2020, SWEPCo filed a request with the LPSC for recovery of the Louisiana share of these additional fuel costs. SWEPCo’s filing proposes to defer $36 million of fuel costs in 2021 and recover the deferral plus carrying costs over five years beginning in 2022.
If any of these 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 | | |
| | September 30, | | December 31, |
| | 2020 | | 2019 |
Noncurrent Regulatory Assets | | (in millions) | | |
| | | | |
Regulatory Assets Currently Earning a Return | | | | |
Dolet Hills Power Station Accelerated Depreciation | | $ | 50.4 | | | $ | 0 | |
Kentucky Deferred Purchase Power Expenses | | 38.5 | | | 30.2 | |
Oklaunion Power Station Accelerated Depreciation | | 38.0 | | | 27.4 | |
Plant Retirement Costs – Unrecovered Plant | | 35.2 | | | 35.2 | |
| | | | |
COVID-19 | | 2.0 | | | 0 | |
Other Regulatory Assets Pending Final Regulatory Approval | | 2.2 | | | 0.7 | |
Regulatory Assets Currently Not Earning a Return | | | | |
Storm-Related Costs | | 86.3 | | | 7.2 | |
Plant Retirement Costs – Asset Retirement Obligation Costs | | 25.9 | | | 30.1 | |
COVID-19 | | 20.3 | | | 0 | |
Asset Retirement Obligation | | 8.7 | | | 7.2 | |
Vegetation Management Program (a) | | 3.8 | | | 29.4 | |
Cook Plant Study Costs (b) | | 0 | | | 7.6 | |
Other Regulatory Assets Pending Final Regulatory Approval | | 5.3 | | | 6.7 | |
Total Regulatory Assets Pending Final Regulatory Approval (c) | | $ | 316.6 | | | $ | 181.7 | |
|
| | | | | | | | |
| | AEP |
| | September 30, | | December 31, |
| | 2019 | | 2018 |
Noncurrent Regulatory Assets | | (in millions) |
| | | | |
Regulatory Assets Currently Earning a Return | | | | |
Plant Retirement Costs – Unrecovered Plant | | $ | 50.3 |
| | $ | 50.3 |
|
Kentucky Deferred Purchase Power Expenses | | 26.2 |
| | 14.5 |
|
Oklaunion Power Station Accelerated Depreciation | | 21.9 |
| | 5.5 |
|
Other Regulatory Assets Pending Final Regulatory Approval | | 5.4 |
| | 9.3 |
|
Regulatory Assets Currently Not Earning a Return | | |
| | |
|
Plant Retirement Costs – Asset Retirement Obligation Costs | | 37.8 |
| | 35.3 |
|
Storm-Related Costs (a) | | — |
| | 152.4 |
|
Other Regulatory Assets Pending Final Regulatory Approval | | 26.8 |
| | 20.7 |
|
Total Regulatory Assets Pending Final Regulatory Approval (b) | $ | 168.4 |
| | $ | 288.0 |
|
| |
(a) | In September 2019, AEP Texas securitized $235 million of storm-related costs. As a result of the securitization, the regulatory asset balance was transferred to Securitized Assets on the balance sheets. See “Texas Storm Cost Securitization” discussion below for additional information. |
| |
(b) | In 2015, APCo recorded a $91 million reduction, before cost of removal of $17 million, to accumulated depreciation related to the remaining net book value of plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. APCo’s recovery of the remaining Virginia net book value for the retired plants will be considered in the Virginia SCC’s 2020 triennial review of APCo’s generation and distribution base rates. |
|
| | | | | | | | |
| | AEP Texas |
| | September 30, | | December 31, |
| | 2019 | | 2018 |
Noncurrent Regulatory Assets | | (in millions) |
| | | | |
Regulatory Assets Currently Not Earning a Return | | | | |
Rate Case Expense | | $ | 2.3 |
| | $ | 0.2 |
|
Storm-Related Costs (a) | | — |
| | 152.4 |
|
Total Regulatory Assets Pending Final Regulatory Approval | | $ | 2.3 |
| | $ | 152.6 |
|
| |
(a) | In September 2019, AEP Texas securitized $235 million of storm-related costs. As a result of the securitization, the regulatory asset balance was transferred to Securitized Assets on the balance sheets. See “Texas Storm Cost Securitization” discussion below for additional information. |
|
| | | | | | | | |
| | APCo |
| | September 30, | | December 31, |
| | 2019 | | 2018 |
Noncurrent Regulatory Assets | | (in millions) |
| | | | |
Regulatory Assets Currently Earning a Return | | | | |
Plant Retirement Costs – Materials and Supplies | | $ | 5.1 |
| | $ | 9.0 |
|
Regulatory Assets Currently Not Earning a Return | | | | |
Plant Retirement Costs – Asset Retirement Obligation Costs | | 37.8 |
| | 35.3 |
|
Other Regulatory Assets Pending Final Regulatory Approval | | — |
| | 0.6 |
|
Total Regulatory Assets Pending Final Regulatory Approval (a) | | $ | 42.9 |
| | $ | 44.9 |
|
| |
(a) | In 2015, APCo recorded a $91 million reduction, before cost of removal of $17 million, to accumulated depreciation related to the remaining net book value of plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. APCo’s recovery of the remaining Virginia net book value for the retired plants will be considered in the Virginia SCC’s 2020 triennial review of APCo’s generation and distribution base rates. |
|
| | | | | | | | |
| | I&M |
| | September 30, | | December 31, |
| | 2019 | | 2018 |
Noncurrent Regulatory Assets | | (in millions) |
| | | | |
Regulatory Assets Currently Not Earning a Return | | | | |
Cook Plant Study Costs | | $ | 10.7 |
| | $ | — |
|
Other Regulatory Assets Pending Final Regulatory Approval | | 0.1 |
| | 3.3 |
|
Total Regulatory Assets Pending Final Regulatory Approval | | $ | 10.8 |
| | $ | 3.3 |
|
|
| | | | | | | | |
| | OPCo |
| | September 30, | | December 31, |
| | 2019 | | 2018 |
Noncurrent Regulatory Assets | | (in millions) |
| | | | |
Regulatory Assets Currently Not Earning a Return | | | | |
Other Regulatory Assets Pending Final Regulatory Approval | | $ | 0.1 |
| | $ | 1.0 |
|
Total Regulatory Assets Pending Final Regulatory Approval | | $ | 0.1 |
| | $ | 1.0 |
|
|
| | | | | | | | |
| | PSO |
| | September 30, | | December 31, |
| | 2019 | | 2018 |
Noncurrent Regulatory Assets | | (in millions) |
| | | | |
Regulatory Assets Currently Earning a Return | | | | |
Oklaunion Power Station Accelerated Depreciation | | $ | 21.9 |
| | $ | 5.5 |
|
Regulatory Assets Currently Not Earning a Return | | |
| | |
|
Other Regulatory Assets Pending Final Regulatory Approval | | — |
| | 0.5 |
|
Total Regulatory Assets Pending Final Regulatory Approval | | $ | 21.9 |
| | $ | 6.0 |
|
|
| | | | | | | | |
| | SWEPCo |
| | September 30, | | December 31, |
| | 2019 | | 2018 |
Noncurrent Regulatory Assets | | (in millions) |
| | | | |
Regulatory Assets Currently Earning a Return | | | | |
Plant Retirement Costs – Unrecovered Plant | | $ | 50.3 |
| | $ | 50.3 |
|
Other Regulatory Assets Pending Final Regulatory Approval | | 0.3 |
| | 0.3 |
|
Regulatory Assets Currently Not Earning a Return | | |
| | |
|
Asset Retirement Obligation - Arkansas, Louisiana | | 6.8 |
| | 5.3 |
|
Rate Case Expense – Texas | | 1.4 |
| | 4.9 |
|
Other Regulatory Assets Pending Final Regulatory Approval | | 4.2 |
| | 3.6 |
|
Total Regulatory Assets Pending Final Regulatory Approval | | $ | 63.0 |
| | $ | 64.4 |
|
(a)In April 2020, $26 million of deferred expenses were approved for recovery. See “2019 Texas Base Rate Case” section below for additional information.
(b)Approved for recovery in the first quarter of 2020 in the Indiana Base Rate Case.
(c)APCo is currently in the process of retiring and replacing its Virginia jurisdictional Automated Meter Reading (AMR) meters with AMI meters. As of September 30, 2020 and December 31, 2019, APCo has approximately $52 million and $51 million, respectively, of Virginia jurisdictional AMR meters recorded in Total Property, Plant and Equipment - Net on its balance sheets. APCo is pursuing full recovery of these assets through its Virginia depreciation rates. See “2017-2019 Virginia Triennial Review” section below for additional information.
| | | | | | | | | | | | | | |
| | AEP Texas | | |
| | September 30, | | December 31, |
| | 2020 | | 2019 |
Noncurrent Regulatory Assets | | (in millions) | | |
| | | | |
Regulatory Assets Currently Not Earning a Return | | | | |
COVID-19 | | $ | 10.9 | | | $ | 0 | |
Vegetation Management Program (a) | | 3.8 | | | 29.4 | |
Other Regulatory Assets Pending Final Regulatory Approval | | 1.4 | | | 1.4 | |
Total Regulatory Assets Pending Final Regulatory Approval | | $ | 16.1 | | | $ | 30.8 | |
(a)In April 2020, $26 million of deferred expenses were approved for recovery. See “2019 Texas Base Rate Case” section below for additional information.
| | | | | | | | | | | | | | |
| | APCo | | |
| | September 30, | | December 31, |
| | 2020 | | 2019 |
Noncurrent Regulatory Assets | | (in millions) | | |
| | | | |
Regulatory Assets Currently Earning a Return | | | | |
COVID-19 – Virginia | | $ | 2.0 | | | $ | 0 | |
Plant Retirement Costs – Materials and Supplies | | 0 | | | 0.5 | |
Regulatory Assets Currently Not Earning a Return | | | | |
Plant Retirement Costs – Asset Retirement Obligation Costs | | 25.9 | | | 30.1 | |
COVID-19 – West Virginia | | 0.8 | | | 0 | |
| | | | |
Total Regulatory Assets Pending Final Regulatory Approval (a) | | $ | 28.7 | | | $ | 30.6 | |
(a)APCo is currently in the process of retiring and replacing its Virginia jurisdictional Automated Meter Reading (AMR) meters with AMI meters. As of September 30, 2020 and December 31, 2019, APCo has approximately $52 million and $51 million, respectively, of Virginia jurisdictional AMR meters recorded in Total Property, Plant and Equipment - Net on its balance sheets. APCo is pursuing full recovery of these assets through its Virginia depreciation rates. See “2017-2019 Virginia Triennial Review” section below for additional information.
| | | | | | | | | | | | | | |
| | I&M | | |
| | September 30, | | December 31, |
| | 2020 | | 2019 |
Noncurrent Regulatory Assets | | (in millions) | | |
| | | | |
Regulatory Assets Currently Not Earning a Return | | | | |
COVID-19 | | $ | 3.1 | | | $ | 0 | |
Cook Plant Study Costs (a) | | 0 | | | 7.6 | |
Other Regulatory Assets Pending Final Regulatory Approval | | 0 | | | 0.1 | |
Total Regulatory Assets Pending Final Regulatory Approval | | $ | 3.1 | | | $ | 7.7 | |
(a)Approved for recovery in the first quarter of 2020 in the Indiana Base Rate Case.
| | | | | | | | | | | | | | |
| | OPCo | | |
| | September 30, | | December 31, |
| | 2020 | | 2019 |
Noncurrent Regulatory Assets | | (in millions) | | |
| | | | |
Regulatory Assets Currently Not Earning a Return | | | | |
| | | | |
| | | | |
| | | | |
Storm-Related Costs | | $ | 3.6 | | | $ | 0 | |
COVID-19 | | 2.9 | | | 0 | |
Other Regulatory Assets Pending Final Regulatory Approval | | 0.1 | | | 0.1 | |
Total Regulatory Assets Pending Final Regulatory Approval | | $ | 6.6 | | | $ | 0.1 | |
| | | | | | | | | | | | | | |
| | PSO | | |
| | September 30, | | December 31, |
| | 2020 | | 2019 |
Noncurrent Regulatory Assets | | (in millions) | | |
| | | | |
Regulatory Assets Currently Earning a Return | | | | |
Oklaunion Power Station Accelerated Depreciation | | $ | 38.0 | | | $ | 27.4 | |
| | | | |
Regulatory Assets Currently Not Earning a Return | | | | |
| | | | |
| | | | |
Storm-Related Costs | | 9.4 | | | 7.2 | |
COVID-19 | | 0.3 | | | 0 | |
Total Regulatory Assets Pending Final Regulatory Approval | | $ | 47.7 | | | $ | 34.6 | |
| | | | | | | | | | | | | | |
| | SWEPCo | | |
| | September 30, | | December 31, |
| | 2020 | | 2019 |
Noncurrent Regulatory Assets | | (in millions) | | |
| | | | |
Regulatory Assets Currently Earning a Return | | | | |
Dolet Hills Power Station Accelerated Depreciation | | $ | 50.4 | | | $ | 0 | |
Plant Retirement Costs – Unrecovered Plant, Louisiana | | 35.2 | | | 35.2 | |
Other Regulatory Assets Pending Final Regulatory Approval | | 2.2 | | | 0.2 | |
Regulatory Assets Currently Not Earning a Return | | | | |
Storm-Related Costs - Louisiana | | 67.3 | | | 0 | |
Asset Retirement Obligation - Louisiana | | 8.5 | | | 7.2 | |
| | | | |
| | | | |
COVID-19 | | 1.7 | | | 0 | |
Other Regulatory Assets Pending Final Regulatory Approval | | 2.0 | | | 3.7 | |
Total Regulatory Assets Pending Final Regulatory Approval | | $ | 167.3 | | | $ | 46.3 | |
If these costs are ultimately determined not to be recoverable, it could reduce future net income and cash flows and impact financial condition.
COVID-19 Pandemic
During the first quarter of 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. During the third and the fourth quarter of 2020, certain state regulators began to lift restrictions on disconnects. As of September 30, 2020, AEP resumed disconnections in its regulated jurisdictions with the exception of Virginia, West Virginia, Kentucky, Arkansas, Louisiana and Tennessee. AEP’s electric operating companies continue to work with regulators and stakeholders in these states and management currently anticipates resuming customary disconnection practices in the fourth quarter of 2020. However, this timing could change if there is new legislation or other regulatory directives issued in the future. 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. The
Registrants have worked with their state commissions to achieve deferral authority for incremental expenses incurred due to COVID-19. All of AEP’s regulated jurisdictions have issued initial COVID-19 orders with the exception of Tennessee. 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)
2019 Texas Base Rate Case
In May 2019, AEP Texas filed a request with the PUCT for a $56 million annual increase in rates based upon a proposed 10.5% ROE. The filing included a proposed Income Tax Refund Rider that will refund $21 million annually of Excess ADIT that is primarily not subject to normalization requirements. The rate case also sought a prudence determination on all transmission and distribution capital additions through 2018 included in interim rates from 2008 to December 2019.
In April 2020, the PUCT issued an order approving a stipulation and settlement agreement. The order includes an annual base rate reduction of $40 million based upon a 9.4% ROE with a capital structure of 57.5% debt and 42.5% common equity effective with the first billing cycle in June 2020. The order provides recovery of $26 million in capitalized vegetation management expenses that were incurred through 2018. The order includes disallowances of $23 million related to capital investments recorded through 2018 and $4 million related to rate case expenses. In addition, AEP Texas will refund: (a) $77 million of Excess ADIT and excess federal income taxes collected as a result of Tax Reform to distribution customers over a one year period, (b) $31 million of Excess ADIT and excess federal income taxes collected as a result of Tax Reform to transmission customers as a one-time credit and (c) $30 million of previously collected rates that were subject to reconciliation in this proceeding over a one year period with no carrying costs. The order requires AEP Texas to file its next base rate case within four years of the date of that the final order was issued. The order also states future financially based capital incentives will not be included in interim transmission and distribution rates and contains various ring-fencing provisions. As a result of the final order, AEP Texas will refund $275 million of Excess ADIT associated with certain depreciable property using ARAM to transmission customers. AEP Texas will determine how to refund the remaining Excess ADIT that is not subject to normalization requirements in future proceedings.
In December 2019, as a result of the initial stipulation and settlement agreement, AEP Texas (a) recorded an impairment of $33 million related to capital investments, which included $10 million of 2019 investments, in Asset Impairments and Other Related Charges on the statements of income, (b) recorded a $30 million provision for refund on the statements of income for revenues previously collected through rates and (c) wrote-off $4 million of rate case expenses to Other Operation on the statements of income.
AEP Texas Interim Transmission and Distribution Rates
As ofThrough September 30, 2019,2020, AEP Texas’ cumulative revenues from interim transmission and distributionbase rate increases from 2008 through 2019,that are subject to review areis estimated to be $1.3 billion. The 2019$38 million. A base rate case described belowreview 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.
2019 Texas Base Rate Case
In May 2019, AEP Texas filed a request with the PUCT for a $56 million annual increase in rates based upon a proposed 10.5% return on common equity. The filing includes a proposed Income Tax Refund Rider that will refund $21 million annually of Excess ADIT that is primarily not subject to rate normalization requirements. The rate case also seeks a prudence determination on all capital additions included in interim rates from 2008.
In July and August 2019, PUCT staff and various intervenors filed testimony. The PUCT staff recommended a $63 million annual rate reduction based on a 9.35% return on common equity while intervenors recommended annual rate reductions of up to $159 million based on a return on common equity ranging from 9% to 9.2%. The difference between AEP Texas’ requested annual base rate increase and the PUCT staff’s and various intervenor’s recommendations are primarily due to: (a) recommended capital structure of 60% debt and 40% common equity as compared to the 55% debt and 45% common equity requested by AEP Texas, (b) a reduction in the requested return on common equity and (c) various disallowances that could potentially result in write-offs exceeding $450 million. The PUCT staff's recommended disallowances primarily consisted of $85 million in capital incentives and $26 million for capitalized vegetation management expenses. The intervenors recommended disallowances primarily consisted of (a) $173 million
for a newly constructed transmission operations center and other service centers, (b) $94 million for Hurricane Harvey costs, (c) $36 million for capitalized cross arms and (d) $21 million for capitalized plant costs related to unreimbursed damages to assets caused by third-parties. In addition, one intervenor recommended AEP Texas refund $115 million of Excess ADIT, which includes $2 million in interest, related to previously owned deregulated generation assets. AEP Texas recorded $113 million as a favorable adjustment to income tax expense in 2017 as a result of Tax Reform. Hearings were held in August 2019 and briefs were filed in September 2019. AEP Texas is expectingrequired to file for a Proposal for Decision from the ALJ in the fourth quarter of 2019. The PUCT is expected to issue an order on the case by the first quarter of 2020. If any of these costs are not recoverable or refunds of revenues collected under interim transmission and distribution rates are ordered to be returned to customers, it could reduce future net income and cash flows and impact financial condition.comprehensive rate review no later than April 3, 2024.
Texas Storm Cost Securitization
In August 2017, Hurricane Harvey hit the coast of Texas, causing power outages in the AEP Texas service territory. In March 2019, AEP Texas filed a request to securitize total estimated distribution-related system restoration costs with the PUCT, which included estimated carrying costs. In June 2019, the PUCT approved the financing order. As part of the financing order, AEP Texas agreed to offset $64 million of Excess ADIT that is not subject to rate normalization requirements against the total distribution-related system restoration costs. In September 2019, AEP Texas issued $235 million of securitization bonds. The securitization bonds included carrying costs of $33 million, which includes $21 million of debt carrying costs recorded as a reduction to Interest Expense in 2019.
The remaining $95 million of estimated net transmission-related system restoration costs, including carrying charges, is expected to be recovered in the 2019 Texas Base Rate Case described above or through interim transmission base rate increases. If these costs are not recovered, it could have an adverse effect on future net income, cash flows and financial condition.
APCo and WPCo Rate Matters (Applies to AEP and APCo)
2017-2019 Virginia Legislation Affecting Earnings ReviewsTriennial Review
Under a 2015 amendedAmendments to Virginia law APCo’s existing generation and distribution base rates were frozen until after the Virginia SCC ruled on APCo’s next biennial review. The 2015 amendments also precluded the Virginia SCC from performing biennial reviews of APCo’s earnings for the years 2014 through 2017.
New Virginia legislation impacting investor-owned utilities waswere enacted, effective July 1, 2018, that requiresrequired APCo to file its nexta generation and distribution base rate case by March 31, 2020 using 2017, 2018 and 2019 earnings test years (triennial review). Triennial reviews are subject to an earnings test, which provides that 70% of any earnings exceedingin excess of 70 basis points over theabove APCo’s Virginia SCC authorized return on common equityROE would be refunded to customers or be used tocustomers. In such case, the Virginia SCC could also lower APCo’s Virginia retail base rates on a prospective basis. The Virginia legislation also states that, under certain circumstances, costs associated with asset impairments related to early retirement determinations made by a utility for generation facilities fueled by coal, natural gas or oil or for automated meters be considered fully recovered in the period recorded.
In November 2018, the Virginia SCC approvedauthorized a return on common equityROE of 9.42% applicable to APCo base rate earnings for the 2017-2019 triennial period.
Virginia law provides that costs associated with asset impairments of retired coal generation assets, or automated meters, or both, which a utility records as an expense, shall be attributed to the test periods under review in a triennial review proceeding, and be deemed recovered. In 2015, APCo retired the Sporn Plant, the Kanawha River Plant, the Glen Lyn Plant, Clinch River Unit 3 and the coal portions of Clinch River Units 1 and 2 (collectively, the retired coal-fired generation assets). The net book value of the Virginia jurisdictional share of these plants was $93 million before cost of removal, including materials and supplies inventory and ARO balances. Based on management’s interpretation of Virginia law and more certainty regarding APCo’s triennial revenues, expenses and resulting earnings upon reaching the end of the three-year review period, APCo recorded a pretax expense of $93 million related to its previously retired coal-fired generation assets in December 2019. As a result, management deems these costs to be substantially recovered by APCo during the triennial review period.
In March 2020, APCo submitted its 2017-2019 Virginia triennial earnings review filing and base rate adjustment clauses from November 2018 through November 2020. Management has reviewedcase with the Virginia SCC as required by state law. APCo requested a $65 million annual increase in base rates based upon a proposed 9.9% ROE. The requested annual increase includes $19 million related to depreciation for updated test year end depreciable balances and a proposed increase in APCo’s actualVirginia depreciation rates and forecasted$8 million related to APCo’s calculated shortfall in 2017-2019 APCo’s Virginia earnings. Inclusive of the Virginia jurisdictional share of the $93 million expense associated with APCo’s retired coal-fired generation assets, APCo calculated its 2017-2019 Virginia earnings for the triennial period to be below the authorized ROE range.
APCo is currently in the process of retiring and concluded that itreplacing its Virginia jurisdictional Automated Meter Reading (AMR) meters with AMI meters. As of September 30, 2020 and December 31, 2019, APCo has approximately $52 million and $51 million of Virginia jurisdictional AMR meters as well as $82 million and $75 million of Virginia jurisdictional AMI meters recorded in Total Property, Plant and Equipment - Net on its balance sheets. APCo is not probable, but is reasonably possible,pursuing full recovery of these assets through its Virginia depreciation rates as discussed above.
In July 2020, a certain intervenor filed testimony asserting that APCo will over-earnhad a revenue surplus of $23 million for its filed rate year based upon the intervenor’s recommended ROE of 8.75%. The intervenor also filed proposed adjustments to APCo’s requested revenue requirement including: (a) a reduction to depreciation expense to reflect a 2040 retirement date for Amos Plant instead of 2032 for Amos Units 1 and 2 and 2033 for Amos Unit 3 as proposed by APCo, (b) removal of AMI meters from rate base along with related depreciation and (c) a reduction of purchased power expense related to OVEC demand charges. This intervenor, along with one other intervenor, also proposed the removal of major storm expenses.
In addition, this certain intervenor submitted corrected testimony contending APCo’s earned return for the triennial period was 11.12%, which equates to a potential refund to customers of $34 million. The intervenor also filed a separate legal memorandum opposing the inclusion of the 2019 expensing of the retired coal-fired generation assets from APCo’s 2017-2019 earnings test results. The testimony also removed the related rate base associated with the retired coal units. Another intervenor recommended that APCo not earn a return on $114 million of prepaid pension and OPEB assets.
In August and September 2020, the Virginia staff filed testimony supporting an annual APCo Virginia jurisdictional revenue deficiency of $17 million based upon an ROE of 8.73%. However, Virginia staff contends APCo’s earned return for the triennial period was 9.55%, which is above the 9.42% midpoint of APCo’s authorized ROE range. Based on Virginia law, a Virginia SCC order finding an earned ROE above the midpoint would prevent APCo from receiving a prospective increase in Virginia retail rates. In addition, the staff recommended that APCo: (a) reverse the pretax Virginia jurisdictional share of the $93 million expense recorded in December 2019 for its retired coal-fired generation assets and instead amortize the retired assets over a 10-year period beginning in 2015, (b) implement 2017 depreciation study rates, effective January 2018, which would increase depreciation expense by $18 million and $20 million in 2018 and 2019, respectively (including $5 million annually related to transmission), (c) implement 2019 depreciation study rates, effective January 2020, which would increase depreciation expense by $29 million annually (including $11 million related to transmission) starting January 1, 2020 and (d) remove $9 million of major storm expenses and $12 million of coal combustion by-product expenses from the requested annual increase in base rates.
APCo expects to receive an order in November 2020. If any APCo Virginia jurisdictional costs are not recoverable or if refunds of revenues collected from customers during the 2017-2019 triennial period. Due to various uncertainties, including weather, storm restoration, weather-normalized demand and potential customer shopping during 2019, management cannot estimate a range of potential APCo Virginia over-earnings during the 2017-2019 triennial period. Ifreview period are ordered by the Virginia triennial review of APCo earnings results in any disallowance,SCC, it could reduce future net income and cash flows and impact financial condition.
West Virginia ENEC and Vegetation Management Riders
Virginia Staff Depreciation Study Request
In November 2018, Virginia staff recommended that APCo implement new Virginia jurisdictional depreciation rates effective January 1, 2018 based on APCo’s depreciation study that was prepared at Virginia staff’s request using December 31, 2017 APCo property balances. Implementation of those depreciation rates would result in a $21 million pretax increase in annual depreciation expense ($6 million related to transmission) with no corresponding increase in retail base rates. In December 2018, APCo submitted a response to the Virginia staff stating that it was inappropriate for APCo to change Virginia depreciation rates in advance of the Virginia SCC’s upcoming Triennial Review of APCo, citing the Virginia SCC’s November 2014 order to not change APCo’s Virginia depreciation rates until APCo’s next base rate case/review. If the Virginia SCC were to issue an order approving the Virginia staff’s recommended retroactive change in APCo’s Virginia depreciation rates, it would reduce future net income and cash flows and impact financial condition.
Virginia Tax Reform
In March 2019, the Virginia SCC issued an order to reduce APCo’s base rates to refund: (a) $40 million annually for ongoing annual tax savings, (b) $9 million annually of Excess ADIT associated with certain depreciable property using ARAM, (c) $94 million of Excess ADIT that is not subject to rate normalization requirements over three years and (d) a one-time credit of $22 million for estimated excess taxes collected from customers during the 15-month period ending March 31, 2019.
2018 West Virginia Base Rate Case
In May 2018, APCo and WPCo filed a joint request with the WVPSC to increase their combined West Virginia base rates by $115 million ($98 million related to APCo) annually based on a 10.22% return on common equity. The proposed annual increase included $32 million ($28 million related to APCo) due to increased annual depreciation expense and reflected the impact of the reduction in the federal income tax rate due to Tax Reform.In October 2018, APCo and WPCo filed updated schedules supporting a $95 million ($80 million related to APCo) annual increase in West Virginia base rates primarily due to the impact of West Virginia Tax Reform.
In February 2019,June 2020, the WVPSC issued an order approvingdirecting APCo and WPCo to increase rider rates relating to ENEC and vegetation management by a Stipulation and Settlement agreement between APCo, WPCo, WVPSC staff and certain intervenors. The agreement included an annual base rate increase of $44combined $101 million ($36 millionrelated to APCo) based upon a 9.75% return on common equity effective March 2019. The agreement also included: (a) $18 million ($14 million related to APCo) of increased annual depreciation expense, (b) a $24 million refund ($1981 million related to APCo) over two years, throughtwelve months beginning September 2020. This increase will be partially offset by a rider beginning March 2019,refund of Excess ADIT that is not subject to rate normalization requirements, (c) the utilization of $14$38 million ($1231 million related to APCo) of Excess ADIT that is not subject to rate normalization requirements over ten months beginning September 2020. These transactions will result in no overall impact to offset regulatory asset balances relating to ENEC, (d) an agreement to seek WVPSC approval of economic incentive programs to provide funds to aid in industrial and commercial development and (e) an agreement, barring any unforeseen events, to not initiate another base rate proceeding prior to April 1, 2020.net income.
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 filed base rate proceeding. Through September 30, 2019,2020, AEP’s share of ETT’s cumulative revenues that are subject to review is estimated to be $987 million.$1.1 billion. A base rate review could produce a refund if ETT incurs a disallowance of the transmission investment on which an interim increase was based. A revenue decrease, including a refund of interim transmission rates, could reduce future net income and cash flows and impact financial condition. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring.
In 2018, the PUCT adopted a rule requiring investor-owned utilities operating solely inside ERCOT to make periodic filings for base rate proceedings. The rule requires ETT to file for a comprehensive base rate review no later than February 1, 2021.
I&M Rate Matters (Applies to AEP and I&M)
Michigan Tax Reform
In October 2018, I&M made a filing with the MPSC recommending to: (a) refund approximately $68 million of Excess ADIT associated with certain depreciable property using ARAM and (b) refund approximately $37 million of Excess ADIT that is not subject to rate normalization requirements over ten years. In September 2019, an ALJ issued a Proposal for Decision and various intervenors filed objections which included changing the refund period from ten years to seven years. In October 2019, I&M filed responses to the various intervenor objections. An order from the MPSC regarding Excess ADIT is expected in the fourth quarter of 2019.
2019 Indiana Base Rate Case
In May 2019, I&M filed a request with the IURC for a $172 million annual increase. The requested increase in Indiana rates would be phased in through January 2021 and iswas based upon a proposed 10.5% return on common equity.ROE. The proposed annual increase includesincluded $78 million related to a proposed annual increase in depreciation expense. The requested annual increase in depreciation expense includesincluded $52 million related to proposed investments and $26 million related to increased depreciation rates. The request includesincluded the continuation of all existing riders and a new Automated Metering InfrastructureAMI rider for proposed meter projects.
In August 2019, various intervenors filed testimony that recommended annual rate increases ranging from $2 millionMarch 2020, the IURC issued an order approving a phased-in increase in base rates of up to $33$77 million based upon a returnan ROE of 9.7%. This approved phase-in increase includes: (a) an annual increase in base rates of $44 million effective March 2020 and (b) an annual increase in base rates of up to $77 million, effective January 2021, based on common equity ranging from 9%the IURC-approved forecast of December 31, 2020 Indiana jurisdictional electric plant in service. A compliance filing will be made in January 2021 to 9.73%. The difference betweenadjust the final rate increase to reflect the lower of I&M’s requested annual base rate increase andactual or IURC-approved Indiana jurisdictional electric plant in service balance as of December 31, 2020. The order also approved the intervenor’s recommendations are primarily due to: (a)majority of I&M’s proposed denialchanges in depreciation as well as the test year level of return on and of certain new plantAMI deployment, but did not approve a cost recovery rider for AMI investments (b) proposed lower depreciation rates, (c) a reductionmade in the requested return on common equity and (d) exclusion ofsubsequent years. The order rejected I&M’s proposed re-allocation of capacity costs related to I&M’s June 2020the loss of a significant FERC wholesale contract.contract, which will negatively impact I&M’s annual pretax earnings by approximately $20 million starting June 2020.
KPCo Rate Matters (Applies to AEP)
Kentucky Tax Reform
In May 2020, KPCo filed a request with the KPSC to issue a one-time refund of Excess ADIT that is not subject to normalization requirements to customers of approximately $11 million to eliminate certain customer delinquencies attributable to the COVID-19 pandemic. In October 2020, the KPSC denied KPCo’s request.
2020 Kentucky Base Rate Case
In June 2020, KPCo filed a request with the KPSC for a $65 million net annual increase in base rates based upon a proposed 10% ROE with the increase to be implemented no earlier than January 2021. The filing proposes that KPCo would offset the first year of rate increases by refunding Excess ADIT that is not subject to normalization requirements to customers. Additionally, KPCo requested recovery of the previously authorized deferral of $50 million of Rockport Plant Unit Power Agreement expenses and related carrying charges over a 5-year period beginning in December 2022, through an existing purchased power rider.
In October 2020, various intervenors filed testimony recommending annual rate increases ranging from $0 to $17 million based upon a ROE ranging from 8.93% to 9.25%. Other differences between KPCo’s requested annual base rate increase and the intervenors’ recommendations are primarily due to: (a) a proposed change in the recovery period of Rockport Plant, Unit 2 SCR depreciation expense from three to ten years, (b) a proposal to remove certain employee-related expenses from the revenue requirement and (c) a recommendation that KPCo not earn a return on $64 million of prepaid pension and OPEB assets. In addition, intervenors expressed opposition to: (a) KPCo’s proposed recovery/return of certain parties recommended disallowances that could potentially resultannual PJM Open Access Transmission Tariff expenses below/above the corresponding level recovered in write-offsbase rates through an existing rider, (b) deployment of $41 million relatedAMI with cost recovery through a new rider and (c) KPCo’s proposed changes to the remaining book value of existing Indiana jurisdictional meters and $11 million associated with certain Cook Plant study costs.
In September 2019, I&M filedits net metering tariff. KPCo will file rebuttal testimony rebutting the various parties’ recommendations. A hearing at the IURC began in October 2019. The IURC is expected to issue an order on the case by the first quarter ofNovember 2020. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
2019 MichiganOPCo Rate Matters (Applies to AEP and OPCo)
2020 Ohio Base Rate Case
In June 2019, I&M2020, OPCo filed a request with the MPSCPUCO for a $58$42 million annual increase. The requested increase in Michiganbase rates would be phased in through June 2020 and is based upon a proposed 10.5% return on common equity. The proposed annual increase includes $19 million related to10.15% ROE net of existing riders. Additionally, OPCo filed a proposed annual increase in depreciation expense. The requested annual increase in depreciation expense includes $13 million related to proposed investments and $6 million related to increased depreciation rates. The proposed annual increase also includes $10 millionrequest with the PUCO for annual lost revenue relateda 60-day temporary delay of the normal rate case proceeding due to the Michigan Electric Customer Choice Program that began in 2019.
In October 2019, MPSC staff and various intervenors filed testimony. The MPSC staff recommended a $38 million annual rate increase based upon a 9.75% return on common equity while intervenors recommended annual rate increases of upCOVID-19 pandemic with rates expected to $28 million based on a return on common equity ranging from 9.1% to 9.25%. be effective approximately mid-2021. If any of thesethe requested costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
OPCo Rate Matters (Applies to AEP and OPCo)
2019 Ohio ESP FilingsDIR Audit
ESP Extension through 2024
OPCo conducts business under an Electric Security Plan as approved by the PUCO which subjects the DIR to annual audits. In 2016, OPCo refiled its amended ESP extension application and supporting testimony, consistentAugust 2020, a third-party consulting company filed an audit report with the termsPUCO indicating that OPCo exceeded its 2019 authorized revenue limit by $17 million. Management disagrees with the audit results and believes that OPCo was below its authorized revenue limit in 2019. The PUCO has not yet issued a procedural schedule to address the audit results. If the results of the modified and approved stipulation agreement and based upon a 2016 PUCO order. The amended filing proposed to extend the ESP through May 2024.
In April 2018,audit are upheld by the PUCO issued an order approving the ESP extension stipulation agreement, with no significant changes. In October 2018, an intervenor filed an appeal with the Ohio Supreme Court challenging various approved riders. In October 2019, oral arguments were held in the Ohio Supreme Court. If the Ohio Supreme Court reverses the PUCO’s decision,and any refunds to customers or revenue reductions are ordered, it could reduce future net income and cash flows and impact financial condition.
OPCo’s Enhanced Service Reliability Rider (ESRR) authorized under the ESP is subject to annual audits. In May 2018, the PUCO staff filed comments indicating that 2016 spending under the ESRR was subject to authorized limits and that OPCo overspent those limits. OPCo filed reply comments objecting to the PUCO staff’s position, including the method of calculating the overspent amount. In March 2019, the PUCO staff filed additional comments which adjusted the method of the calculation but maintained that OPCo overspent the authorized limit in 2016 and 2017, which could result in a refund of $10 million. Management believes that both 2016 and 2017 ESRR spending is not subject to an authorized limit and that a spending limit was not established until 2018, as part of the ESP extension. A hearing was held in May 2019 to address the 2016 audit. Post-hearing briefs in this case were filed in June 2019 and reply briefs were filed in July 2019. If it is determined OPCo did have an authorized spending limit under the ESRR in 2016 and 2017, and refunds are ordered, it would reduce future net income and cash flows and impact financial condition.
2016 SEET Filing
Ohio law provides for the return of significantly excessive earnings to ratepayers upon PUCO review. Significantly excessive earnings are measured by whether the earned return on common equity of the electric utility is significantly in excess of the return on common equity that was earned during the same period by publicly traded companies, including utilities, that face comparable business and financial risk.
In 2016, OPCo recorded a 2016 SEET provision of $58 million based upon projected earnings data for companies in the comparable utilities risk group. In determining OPCo’s return on equity in relation to the comparable utilities risk group, management excluded the following items resolved in OPCo’s Global Settlement that was filed at the PUCO in December 2016 and subsequently approved in February 2017: (a) gain on the deferral of RSR costs, (b) refunds to customers related to the SEET remands and (c) refunds to customers related to fuel adjustment clause proceedings.
In February 2019, the PUCO issued an order that OPCo did not have significantly excessive earnings in 2016. As a result of the order, OPCo reversed the $58 million provision in the first quarter of 2019.
PSO Rate Matters (Applies to AEP and PSO)
2018 Oklahoma Base Rate Case
In 2018, PSO filed a request with the OCC for an $88 million annual increase in Oklahoma retail rates based upon a 10.3% return on common equity. PSO also proposed to implement a performance-based rate plan that combines a formula rate with a set of customer-focused performance incentive measures related to reliability, public safety, customer satisfaction and economic development. The proposed annual increase included $13 million related to increased annual depreciation rates and $7 million related to increased storm expense amortization. The requested increase in annual depreciation rates included the recovery of Oklaunion Power Station through 2028 (currently being recovered in rates through 2046). Management has announced plans to retire Oklaunion Power Station by October 2020.
In March 2019, the OCC issued an order approving a Stipulation and Settlement agreement for a $46 million annual increase, based on a 9.4% return on equity effective with the first billing cycle of April 2019. The order also included agreements between the parties that: (a) depreciation rates will remain unchanged, (b) PSO will file a new base rate request no earlier than October 2020 and no later than October 2021 and (c) PSO will refund Excess ADIT that is not subject to rate normalization requirements over five years instead of the ten years ordered in the Oklahoma Tax Reform case. The order did not approve the performance-based rate plan but instead provided for an expansion of the SPP Transmission Tariff that tracks previously untracked SPP costs and a new Distribution Reliability and Safety Rider that provides additional revenues capped at $5 million per year for distribution projects related to safety and reliability that are not normal distribution replacements.
SWEPCo Rate Matters (Applies to AEP and SWEPCo)
2012 Texas Base Rate Case
In 2012, SWEPCo filed a request with the PUCT to increase annual base rates primarily due to the completion of the Turk Plant. In 2013, the PUCT issued an order affirming the prudence of the Turk Plant but determined that the Turk Plant’s Texas jurisdictional capital cost cap established in a previous Certificate of Convenience and Necessity case also limited SWEPCo’s recovery of AFUDC in addition to limits on its recovery of cash construction costs.
Upon rehearing in 2014, the PUCT reversed its initial ruling and determined that AFUDC was excluded from the Turk Plant’s Texas jurisdictional capital cost cap. As a result, SWEPCo reversed $114 million of a previously recorded regulatory disallowance in 2013. The resulting annual base rate increase was approximately $52 million. In 2017, the Texas District Court upheld the PUCT’s 2014 order and intervenors filed appeals with the Texas Third Court of Appeals.
In July 2018, the Texas Third Court of Appeals reversed the PUCT’s judgment affirming the prudence of the Turk Plant and remanded the issue back to the PUCT. In August 2018, SWEPCo filed a Motion for Reconsideration at the Court of Appeals, which was denied. In January 2019, SWEPCo and the PUCT filed petitions for review with the Texas Supreme Court. In Maythe fourth quarter of 2019 and first quarter of 2020, SWEPCo and various intervenors filed replies tobriefs with the petition.Texas Supreme Court. In July 2019, SWEPCo filed its response to these replies. TheAugust 2020, the Texas Supreme Court has requested full briefing by the parties.granted SWEPCo’s initial brief is due in October 2019. Response briefs are due in November 2019petition for review and SWEPCo’s reply brief is due inoral arguments were scheduled for December 2019.2020.
As of September 30, 2019,2020, the net book value of Turk Plant was $1.5$1.4 billion, before cost of removal, including materials and supplies inventory and CWIP. If certain parts of the PUCT order are overturned and if SWEPCo cannot ultimately fully recover its approximate 33% Texas jurisdictional share of the Turk Plant investment, including AFUDC, it could reduce future net income and cash flows and impact financial condition.
2016 Texas Base Rate Case
In 2016, SWEPCo filed a request with the PUCT for a net increase in Texas annual revenues of $69 million based upon a 10% return on common equity.ROE. In January 2018, the PUCT issued a final order approving a net increase in Texas annual revenues of $50 million based upon a return on common equityROE 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. If certain parts of the PUCT order are overturned, it could reduce future net income and cash flows and impact financial condition.
2018 Louisiana Formula Rate Filing
In April 2018, SWEPCo filed its formula rate plan for test year 2017 with the LPSC. The filing included a net $28 million annual increase, which was effective August 2018 and included SWEPCo’s Louisiana jurisdictional share of Welsh Plant and Flint Creek Plant environmental controls. The filing also included a reduction in the federal income tax rate due to Tax Reform but did not address the return of Excess ADIT benefits to customers.
In July 2018, SWEPCo made a supplemental filing to its formula rate plan with the LPSC to reduce the requested annual increase to $18 million. The difference between SWEPCo’s requested $28 million annual increase and the $18 million annual increase in the supplemental filing is primarily the result of the return of Excess ADIT benefits to customers.customers through a tax rider that will end when the Excess ADIT not subject to normalization requirements is fully refunded to customers which is currently estimated to be July 2020.
In October 2018, the LPSC staff issued a recommendation that SWEPCo refund $11 million of excess federal income taxes collected, as a result of Tax Reform, from January 1, 2018 through July 31, 2018. In June 2019, the LPSC staff issued its report which reaffirmed its $11 million refund recommendation. The report also contends that SWEPCo’s requested annual rate increase of $18 million, which was implemented in August 2018, is overstated by $4 million and proposes an annual rate increase of $14 million. Additionally, the report recommends SWEPCo refund the excess over-collections associated with the $4 million difference for the period of August 2018 through the implementation of new rates. In July 2019, the LPSC approved the $11 million refund. A decisionIn July 2020, the LPSC issued an order approving an unopposed stipulation and settlement agreement for a one-time refund of $6 million over three months beginning in August 2020.
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. SWEPCo is currently evaluating recovery options for the storm damage in its Arkansas jurisdiction. As of September 30, 2020, management estimates that SWEPCo has incurred incremental other operation and maintenance expenses of $69 million ($67 million of which has been deferred as a regulatory asset related to the Louisiana jurisdiction) and incremental capital expenditures of $31 million ($30 million related to the Louisiana jurisdiction). 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. Management currently estimates that SWEPCo has incurred incremental other operation and maintenance expenses ranging from $10 million to $18 million and incremental capital expenditures of up to $6 million. SWEPCo will seek deferral authority of incremental other operation and maintenance expenses from the LPSC. 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 its 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 also requested recovery of the Texas jurisdictional share of the Dolet Hills Power Station of $45 million which is expected to be retired by the LPSC on the remaining issues is expected in the fourth quarterend of 2019.
2021. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
Welsh Plant - Environmental Impact
Management currently estimates that the investment necessary to meet proposed environmental regulations through 2025 for Welsh Plant, Units 1 and 3 could total approximately $550 million, excluding AFUDC. As of September 30, 2019, SWEPCo had incurred costs of $399 million, including AFUDC, related to these projects. Management continues to evaluate the impact of environmental rules and related project cost estimates. As of September 30, 2019, the total net book value of Welsh Plant, Units 1 and 3 was $612 million, before cost of removal, including materials and supplies inventory and CWIP.
In 2016, as approved by the APSC, SWEPCo began recovering $79 million related to the Arkansas jurisdictional share of these environmental costs, subject to prudence review in the next Arkansas filed base rate proceeding. In 2017, the LPSC approved recovery of $131 million in investments related to its Louisiana jurisdictional share of environmental controls installed at Welsh Plant. SWEPCo’s approved Louisiana jurisdictional share of Welsh Plant deferrals: (a) are $10 million, excluding $5 million of unrecognized equity as of September 30, 2019, (b) is subject to review by the LPSC and (c) includes a weighted average cost of capital return on environmental investments and the related depreciation expense and taxes. See “2018 Louisiana Formula Rate Filing” and “2019 Arkansas Base Rate Case” disclosures for additional information.
If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
2019 Arkansas Base Rate Case
In February 2019, SWEPCo filed a request with the APSC for a $75 million increase in Arkansas base rates based upon a proposed 10.5% return on common equity. The filing requests rate base treatment for the Stall Plant and environmental retrofits that are currently being recovered through riders. Eliminating these riders would result in a net annual requested base rate increase of $58 million. The proposed net annual increase includes $12 million related to vegetation management to improve the reliability of its Arkansas distribution system. The filing also provides notice of SWEPCo’s proposal to have its rates regulated under the formula rate review mechanism authorized by Arkansas law, including a Formula Rate Review Rider. In October 2019, SWEPCo reduced its requested base rate increase from $75 million to $67 million.
In October 2019,SWEPCo, the APSC staff and various intervenors filed a unanimous stipulation and settlement agreement with the APSC. The agreement includes a proposed annual base rate increase of $53 million ($24 million net of amounts currently recovered through riders) based upon a 9.45% return on common equity and includes $6 million for increased annual depreciation expense. The agreement provides recovery for: (a) the Stall Plant, (b) environmental retrofit projects and (c) the remaining net book value, with a debt return for investors, of Welsh Unit 2. The agreement also includes a proposal to have its rates regulated under the formula rate mechanism authorized by Arkansas law, including a Formula Rate Review Rider. Also in October 2019, a settlement hearing with the APSC was held. SWEPCo expects the APSC to issue an order in the fourth quarter of 2019. If any of these costs are not recoverable, or disallowances were to occur, it could reduce future net income and cash flows and impact financial condition.
FERC Rate Matters
AFUDC Waiver (Applies to all Registrants except AEP Texas)
FERC Transmission Complaint - AEP’s PJM Participants (Applies to AEP, AEPTCo, APCo, I&M and OPCo)
In 2016, seven parties filedJune 2020, FERC granted a complaint attemporary waiver providing utilities the FERC that alleged the base return on common equity used by AEP’s transmission owning subsidiaries within PJM in calculating formula transmission rates under the PJM OATT is excessive and should be reduced from 10.99%option to 8.32%, effective upon the date of the complaint. In March 2018, AEP’s transmission owning subsidiaries within PJM and six of the complainants filed a settlement agreement with the FERC (the seventh complainant abstained). The settlement agreement: (a) established a base ROE for AEP’s transmission owning subsidiaries within PJM of 9.85% (10.35% inclusive of the RTO incentive adder of 0.5%), effective January 1, 2018, (b) required AEP’s transmission owning subsidiaries within PJM to provide a one-time refund of $50 million, attributable from the date of the complaint through December 31, 2017, which was credited to customer bills in the second quarter of 2018 and (c) increased the cap on the equity portion of the capital structure to 55% from 50%. As part of the settlement agreement, AEP’s transmission owning subsidiaries within PJM also filed updated transmission formula rates incorporating the reduction in the corporate federal income tax rate due to Tax Reform, effective January 1, 2018 and providing for the amortization of the portion of the Excess ADIT that is not subject to rate normalization requirements over a ten-year period through credits to the federal income tax expense component of the revenue requirement. In May 2019, the FERC approved the settlement agreement.
FERC Transmission Complaint - AEP’s SPP Participants (Applies to AEP, AEPTCo, PSO and SWEPCo)
In 2017, several parties filed a complaint at the FERC that states the base return on common equity used by AEP’s transmission owning subsidiaries within SPP in calculating formula transmission rates under the SPP OATT is excessive and should be reduced from 10.7% to 8.36%, effective upon the date of the complaint through September 5, 2018. In September 2018, the same parties filed another complaint at the FERC that states the base return on common equity used by AEP’s transmission owning subsidiaries within SPP in calculating formula transmission rates under the SPP OATT is excessive and should be reduced from 10.7% to 8.71%, effective upon the date of the second complaint. In June 2019, the FERC approved an unopposed settlement agreement between AEP’s transmission owning subsidiaries within SPP and the complainants. The settlement agreement established a base ROE of 10% (10.50% inclusive of the RTO incentive adder of 0.5%) effective January 1, 2019. Additionally, refunds including carrying charges will be made from the date of the first complaint through December 31, 2018. Refunds for the period prior to 2019 will be
made at the time of the 2019 true-up of 2018 rates. Refunds from January 2019 onward will conclude with the 2020 true-up of 2019 rates.
Modifications to AEP’s SPP Transmission Rates (Applies to AEP, AEPTCo, PSO and SWEPCo)
In 2017, AEP’s transmission owning subsidiaries within SPP filed an application at the FERCelect to modify the SPP OATTexisting AFUDC rate calculations in response to the COVID-19 pandemic. As a result of the waiver, the AFUDC formula transmission rate calculation,for the 12-month period starting with March 2020 may be calculated using the simple average of the actual historical short-term debt balances for 2019, instead of current period short-term balances. All other aspects of the AFUDC formula remained unchanged. AEP subsidiaries including an adjustmentcertain Registrant Subsidiaries elected to recover a tax-related regulatory asset and a shift from historical to projected expenses.apply the waiver in July 2020. The modified SPP OATT formula rates are basedimpact upon election was immaterial on projected calendar yearthe Registrants’ financial activity and projected plant balances. The FERC accepted the proposed modifications effective January 1, 2018, subject to refund. In February 2019, AEP’s transmission owning subsidiaries within SPP filed an uncontested settlement agreement with the FERC resolving all outstanding issues. In June 2019, the FERC approved the settlement agreement.
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 20182019 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 and OPCo)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 a $4 billion revolving credit facility due in June 2022, under which up to $1.2 billion may be issued as letters of credit on behalf of subsidiaries. As of September 30, 2019,2020, no letters of credit were issued under the revolving credit facility.
An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility. AEP issues letters of credit on behalf of subsidiaries under six uncommitted facilities totaling $405 million. The Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities as of September 30, 20192020 were as follows:
| | | | | | | | | | | | | | |
Company | | Amount | | Maturity |
| | (in millions) | | |
AEP | | $ | 197.3 | | | October 2020 to August 2021 |
AEP Texas | | 2.2 | | | July 2021 |
| | | | |
|
| | | | | | |
Company | | Amount | | Maturity |
| | (in millions) | | |
AEP | | $ | 204.4 |
| | October 2019 to October 2020 |
AEP Texas | | 2.2 |
| | July 2020 |
OPCo | | 3.6 |
| | April 2020 to September 2020 |
Guarantees of Third-Party Obligations (Applies to AEP and SWEPCo)
As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of $155 million. Since SWEPCo uses self-bonding, the guarantee commits SWEPCo to complete the reclamation, in the event, Sabine does not complete the work. This guarantee ends upon depletion of reserves and completion of reclamation. The reserves are estimated to deplete in 2036 with reclamation completed by 2046 at an estimated cost of $107 million. Actual reclamation costs could vary due to inflation and scope changes to the mine reclamation. As of September 30, 2019, SWEPCo has collected $77 million through a rider
for reclamation costs, of which $83 million was recorded in Asset Retirement Obligations, offset by $6 million recorded in Deferred Charges and Other Noncurrent Assets on SWEPCo’s balance sheets.
Sabine charges all of its costs to its only customer, SWEPCo, which recovers these costs through its fuel clauses.
Guarantees of Equity Method Investees (Applies to AEP)
In December 2016, AEP issued a performance guarantee for a 50% owned joint venture which is accounted for as an equity method investment. If the joint venture were to default on payments or performance, AEP would be required to make payments on behalf of the joint venture. As of September 30, 2019, the maximum potential amount of future payments associated with this guarantee was $75 million, which expired in October 2019.
In April 2019, AEP acquired Sempra Renewables LLC. See “Acquisitions” section of Note 6 for additional information.
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, 2019,2020, 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, 2020, 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 | | $ | 49.8 | |
AEP Texas | | 11.4 | |
APCo | | 6.8 | |
I&M | | 4.5 | |
OPCo | | 7.9 | |
PSO | | 4.6 | |
SWEPCo | | 5.2 | |
Rockport Lease (Applies to AEP and I&M)
AEGCo and I&M entered into a sale-and-leaseback transaction in 1989 with Wilmington Trust Company (Owner Trustee), an unrelated, unconsolidated trustee for Rockport Plant, Unit 2 (the Plant). The Owner Trustee was capitalized with equity from six owner participants with no relationship to AEP or any of its subsidiaries and debt from a syndicate of banks and securities in a private placement to certain institutional investors.
The Owner Trustee owns the Plant and leases equal portions to AEGCo and I&M. The lease is accounted for as an operating lease. The lease term is for 33 years and at the end of the lease term, AEGCo and I&M have the option to renew the lease at a rate that approximates fair value. The option to renew was not included in the measurement of the lease obligation as of September 30, 2020 as the execution of the option was not reasonably certain. AEP, AEGCo and I&M have no ownership interest in the Owner Trustee and do not guarantee its debt.
The future minimum lease payments for this sale-and-leaseback transaction as of September 30, 2020 were as follows:
| | | | | | | | | | | | | | |
Future Minimum Lease Payments | | AEP (a) | | I&M |
| | (in millions) | | |
2020 | | $ | 73.9 | | | $ | 37.0 | |
2021 | | 147.8 | | | 73.9 | |
2022 | | 147.5 | | | 73.7 | |
Total Future Minimum Lease Payments | | $ | 369.2 | | | $ | 184.6 | |
(a)AEP’s future minimum lease payments include equal shares from AEGCo and I&M.
AEPRO Boat and Barge Leases (Applies to AEP)
In 2015, AEP sold its commercial barge transportation subsidiary, AEPRO, to a nonaffiliated party. Certain boat and barge leases acquired by the nonaffiliated party are subject to an AEP guarantee in favor of the respective lessors, ensuring future payments under such leases with maturities up to 2027. As of September 30, 2020, the maximum potential amount of future payments required under the guaranteed leases was $50 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, 2020, AEP’s boat and barge lease guarantee liability was $3 million, of which $1 million was recorded in Other Current Liabilities and $2 million was recorded in Deferred Credits and Other Noncurrent Liabilities on AEP’s balance sheet.
In February 2020, the nonaffiliated party filed Chapter 11 bankruptcy. The party entered into a restructuring support agreement and has announced it expects 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.
Virginia House Bill 443 (Applies to AEP and APCo)
In March 2020, Virginia’s Governor signed House Bill 443 (HB 443), effective July 2020, requiring APCo to close certain ash disposal units at the retired Glen Lyn Station by removal of all coal combustion material. As a result, in June 2020, APCo recorded a $199 million revision to increase estimated Glen Lyn Station ash disposal ARO liabilities. The closure is required to be completed within 15 years from the start of the excavation process. HB 443 provides for the recovery of all costs associated with closure by removal through the Virginia environmental rate adjustment clause (E-RAC). APCo may begin recovering these costs through the E-RAC beginning July 1, 2022. APCo is permitted to record carrying costs on the unrecovered balance of closure costs at a weighted average cost of capital approved by the Virginia SCC. HB 443 also allows any closure costs allocated to non-Virginia jurisdictional customers, but not collected from such non-Virginia jurisdictional customers, to be recovered from Virginia jurisdictional customers through the E-RAC.
NUCLEAR CONTINGENCIES (Applies to AEP and I&M)
I&M owns and operates the Cook Plant under licenses granted by the Nuclear Regulatory Commission. I&M has a significant future financial commitment to dispose of SNF and to safely decommission and decontaminate the plant. The licenses to operate the two nuclear units at the Cook Plant expire in 2034 and 2037. The operation of a nuclear facility also involves special risks, potential liabilities and specific regulatory and safety requirements. By agreement, I&M is partially liable, together with all other electric utility companies that own nuclear generation units, for a nuclear power plant incident at any nuclear plant in the U.S. Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial.
OPERATIONAL CONTINGENCIES
Rockport Plant Litigation (Applies to AEP and I&M)
In 2013, the Wilmington Trust Company filed a complaint in the U.S. District Court for the Southern District of New York against AEGCo and I&M alleging that it would be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration in December 2022. The terms of the consent decree allow the installation of environmental emission control equipment, repowering, refueling or retirement of the unit. The plaintiffs seek a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiffs. The New York court granted a motion to transfer this case to the U.S. District Court for the Southern District of Ohio.
AEGCo and I&M sought and were granted dismissal by the U.S. District Court for the Southern District of Ohio of certain of the plaintiffs’ claims, including claims for compensatory damages, breach of contract, breach of the implied covenant of good faith and fair dealing and indemnification of costs. Plaintiffs voluntarily dismissed the surviving claims that AEGCo and I&M failed to exercise prudent utility practices with prejudice, and the court issued a final judgment. The plaintiffs subsequently filed an appeal in the U.S. Court of Appeals for the Sixth Circuit.
In 2017, the U.S. Court of Appeals for the Sixth Circuit issued an opinion and judgment affirming the district court’s dismissal of the owners’ breach of good faith and fair dealing claim as duplicative of the breach of contract claims, reversing the district court’s dismissal of the breach of contract claims and remanding the case for further proceedings.
Thereafter, AEP filed a motion with the U.S. District Court for the Southern District of Ohio in the original NSR litigation, seeking to modify the consent decree. The district court granted the owners’ unopposed motion to stay the lease litigation to afford time for resolution of AEP’s motion to modify the consent decree. The consent decree was modified based on an agreement among the parties in July 2019. As partThe district court’s stay of the modification tolease litigation expired in August 2020. Upon expiration of the stay, plaintiffs filed a motion for partial summary judgment, arguing that the consent decree I&M agreed to provide an additional $7.5 million to citizens’ groupsviolates the facility lease and the statesparticipation agreement and requesting that the
district court enter a judgment for environmental mitigation projects. As joint ownersthe plaintiffs on their breach of contract claim. AEP’s memorandum in the Rockport Plant, the $7.5 million paymentopposition was shared between AEGCo and I&M based on the joint ownership agreement. See “Modificationfiled in October 2020. All deadlines, including discovery, are stayed, pending resolution of the New Source Review Litigation Consent Decree” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for additional information.motion.
Management will continue to defend against the claims. Given that the district court dismissed plaintiffs’ claims seeking compensatory relief as premature, and that plaintiffs have yet to present a methodology for determining or any analysis supporting any alleged damages, management cannot determine a range of potential losses that areis reasonably possible of occurring.
Patent Infringement Complaint (Applies to AEP, AEP Texas and SWEPCo)
In July 2019, Midwest Energy Emissions Corporation and MES Inc. (collectively, the plaintiffs) filed a patent infringement complaint against various parties, including AEP Texas, AGR, Cardinal Operating Company and SWEPCo (collectively, the AEP Defendants). The complaint alleges that the AEP Defendants infringed two patents owned by the plaintiffs by using specific processes for mercury control at certain coal-fired generating stations. In July 2020, plaintiffs amended the complaint to add three new patents. The amended complaint seeks injunctive relief and damages. The case is scheduled for trial in January 2023. Management will continue to defend against the claims. Management is unable to determine a range of potential losslosses that is reasonably possible of occurring.
Claims Challenging Transition of American Electric Power System Retirement Plan to Cash Balance Formula
The American Electric Power System Retirement Plan (the Plan) has received a letter written on behalf of four participants (the Claimants) making a claim for additional plan benefits and purporting to advance such claims on behalf of a class. When the Plan’s benefit formula was changed in the year 2000, AEP provided a special provision for employees hired before January 1, 2001, allowing them to continue benefit accruals under the then benefit formula for a full 10 years alongside of the new cash balance benefit formula then being implemented. Employees who were hired on or after January 1, 2001 accrued benefits only under the new cash balance benefit formula. The Claimants have asserted claims that (a) the Plan violates the requirements under the Employee Retirement Income Security Act (ERISA) intended to preclude back-loading the accrual of benefits to the end of a participant’s career; (b) the Plan violates the age discrimination prohibitions of ERISA and the Age Discrimination in Employment Act; and (c) the company failed to provide required notice regarding the changes to the Plan. AEP has responded to the Claimants providing a reasoned explanation for why each of their claims have been denied. The denial of those claims was appealed to the AEP System Retirement Plan Appeal Committee and the Committee upheld the denial of claims. Management will continue to defend against the claims. Management is unable to determine a range of potential losses that are reasonably possible of occurring.
Litigation Related to Ohio House Bill 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 complaint alleges misrepresentations or omissions by AEP regarding: (a) its alleged participation in public corruption with respect to the passage of Ohio House Bill 6, (b) its regulatory, legislative and lobbying activities in Ohio and (c) its clean energy strategy. The complaint seeks monetary damages among other forms of relief. Management is unable to determine a range of potential losses that is reasonably possible of occurring.
6. ACQUISITIONS AND IMPAIRMENTSDISPOSITIONS
The disclosures in this note apply to AEP only unless indicated otherwise.
ACQUISITIONS
Sempra Renewables LLC (Generation & Marketing Segment)
In April 2019, AEP acquired Sempra Renewables LLC and its ownership interests in 724 MWs of wind generation and battery assets valued at approximately $1.1 billion. This acquisition is part of AEP’s strategy to grow its renewable generation portfolio and to diversify generation resources. AEP paid $583$580 million in cash and acquired a 50% ownership interest in five non-consolidated joint ventures with net assets valued at $406$404 million as of the acquisition date (which includes $364 million of existing debt obligations). Additionally, the transaction included the acquisition of two tax equity partnerships and the associated recognition of noncontrolling tax equity interest of $135 million. The purchase price, subject to working capital adjustments, was allocated as follows:
|
| | | | | | | | | | | | |
Purchase Price Allocation of Sempra Renewables LLC at Acquisition Date - April 22nd, 2019 |
Assets: | | Liabilities and Equity: | | Net Purchase Price |
(in millions) |
Current Assets | $ | 9.7 |
| | Current Liabilities | $ | 12.9 |
| | |
Property, Plant and Equipment | 238.1 |
| | Asset Retirement Obligations | 5.7 |
| | |
Investment in Joint Ventures | 405.9 |
| | Total Liabilities | 18.6 |
| | |
Other Noncurrent Assets | 82.9 |
| | Noncontrolling Interest | 134.8 |
| | |
Total Assets | $ | 736.6 |
| | Liabilities and Noncontrolling Interest | $ | 153.4 |
| | $ | 583.2 |
|
Management allocated the purchase price based upon the relative fair value of the assets acquired and noncontrolling interests assumed. The fair value of the primary assets acquired and the noncontrolling interests assumed was determined using a discounted cash flow method under the income approach. The key input assumptions utilized in the determination of the fair value of these assets were the pricing and terms of the existing purchase power agreements, forecasted market power prices, forecasted PTCs from the wind farms, expected wind farm net capacity, forecasted cash benefits from income tax depreciation and discount rates reflecting risk inherent in the future cash flows and future power prices. Additional key input assumptions for the fair value of the noncontrolling interests include the terms of the limited liability company agreements that dictate the sharing of the tax attributes and cash flows associated with the tax equity partnerships. Under the accounting rules for acquisitions, AEP has one year to finalize the purchase price allocation, including working capital adjustments and other closing adjustments.
Upon closing of the purchase, Sempra Renewables LLC was legally renamed AEP Wind Holdings LLC. AEP Wind Holdings LLC develops, owns and operates, or holds interests in, wind generation facilities in the United States. The operating wind generation portfolio includes seven wind farms. Five wind farms are jointly-owned with BP Wind Energy, and two wind farms are consolidated by AEP and are tax equity partnerships with nonaffiliated noncontrolling interests. All seven wind farms have long-term PPAs for 100% of their energy production. One of the joint venture wind farms has PPAs with I&M and OPCo for a portion of its energy production which totaled $2 million and $3 million, respectively, of purchased electricity for the three months ended September 30, 2019, and $5 million and $10 million, respectively, for the nine months ended September 30, 2019. Another joint venture wind farm has a PPA with SWEPCo for a portion of its energy production which totaled $3 million and $6 million of purchased electricity for the three and nine months ended September 30, 2019, respectively. The PPAs with I&M, OPCo and SWEPCo were executed prior to the acquisition of the wind farms and will be accounted for in accordance with the accounting guidance for “Related Parties.”
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, 2019,2020, the maximum potential amount of future payments associated with these guarantees was $186$166 million, with the last guarantee expiring in December 2037. The non-contingent liability recorded associated with these guarantees was $34$31 million, as of September 30, 2019.
The acquired business contributed revenues and Net Income to AEP that were not materialwith an additional $1 million expected credit loss liability for the period April 22, 2019 to September 30, 2019. The pro-forma revenuecontingent portion of the guarantees. Management considered historical losses, economic conditions, and net income related toreasonable and supportable forecasts in the acquisitioncalculation of Sempra Renewables LLC were not material for the threeexpected 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 nine months ended September 30, 2019 and 2018.default probabilities of the respective PPA counterparties.
See Note 14 - Variable Interest Entities and Equity Method Investments for additional information related to the purchased wind farms.
Santa Rita East (Generation & Marketing Segment)
In July 2019, AEP acquired a 75% interest, or 227 MWs, in Santa Rita East for approximately $356 million. In accordance with the accounting guidance for “Business Combinations,” management determined that the acquisition of Santa Rita East represents an asset acquisition. Additionally, and in accordance with the accounting guidance for “Consolidation,” management concluded that Santa Rita East is a VIE. As a result, to account for the initial consolidation of Santa Rita East, 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 Santa Rita East and recent third-party market transactions for similar wind farms. See “Santa Rita East” section
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 Note 14Desert Sky Wind Farm LLC and Trent Wind Farm LLC (collectively the LLCs) to sell its noncontrolling interest to AEP. The exercise price for additional information.
IMPAIRMENTS
Other Assets (Corporate and Other) (Vertically Integrated Utilities Segment) (Appliesthe 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 APCo)management has concluded that 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.
DISPOSITIONS
Conesville Plant (Generation & Marketing Segment)
In June 2020, AEP and a non-affiliated joint-owner executed an Environmental Liability and Property Transfer and Asset Purchase Agreement with a non-affiliated third-party related to the first quartermerchant Conesville Plant site. The purchaser took ownership of 2018,the assets and assumed responsibility for environmental liabilities, including ash pond closure, asbestos abatement and decommissioning and demolition of the Conesville Plant site. In consideration of the transfer of the acquired assets to the purchaser and the purchaser’s assumption of liabilities, AEP was notified bywill pay approximately $98 million, derecognized $106 million in ARO and recorded an equity investee that it had ceased operations. AEPimmaterial gain on the transaction which is recorded a pretax impairment of $21 million in Other Operation on the statements of incomeincome. AEP paid approximately $26 million in June 2020 and will make additional payments totaling $28 million in quarterly installments from October 2020 to April 2021 and payments totaling $44 million in quarterly installments from July 2021 to July 2022.
Oklaunion Power Station (Applies to AEP, AEP Texas and PSO)
In October 2020, AEP Texas, PSO and a non-affiliated joint-owner executed an Environmental Liability and Property Transfer and Asset Purchase Agreement with a non-affiliated third-party related to the equity investmentOklaunion Power Station site. The purchaser took ownership of the assets and related assets.assumed responsibility for environmental liabilities, including ash pond closure, asbestos abatement and decommissioning and demolition of the Oklaunion Power Station site. The impairment also hadsale is expected to have an immaterial impact to APCo.
Merchant Generating Assets (Generation & Marketing Segment)
A project to reconstruct a defective dam structure at Racine beganon the financial statements in the firstfourth quarter of 2017. As of September 30, 2018, the Racine reconstruction project had accumulated new capital expenditures of $35 million. Due to a significant increase in estimated costs to complete the reconstruction project, in the third quarter of 2018, an impairment analysis was performed. AEP performed step one of the impairment analysis using undiscounted cash flows for the estimated useful life of Racine based upon energy and capacity price curves, which were developed internally with observable Level 2 third-party quotations and unobservable Level 3 inputs, as well as management’s forecasts of operating expenses and capital expenditures. AEP performed step two of the impairment analysis on Racine using a ten-year discounted cash flow model based upon similar forecasted information used in the step one test. The step two analysis resulted in a determination that the fair value of Racine in its condition as of September 30, 2018 was $0. As a result, AEP recorded a pretax impairment of $35 million in Other Operation on the statements of income in the third quarter of 2018. In October 2018, AEP received authorization from the FERC to restart generation at Racine and generation resumed in November 2018.2020.
Due to weather-related delays in the first quarter of 2019, reconstruction activities at Racine are now estimated to be completed in the first half of 2020. AEP expects to incur additional capital expenditures to complete the reconstruction project, at which point the fair value of Racine, as fully operational, is expected to approximate the book value once complete. Future revisions in cost estimates or delays in completion could result in additional losses which could reduce future net income and cash flows and impact financial condition.
7. BENEFIT PLANS
The disclosures in this note apply to all Registrants except AEPTCo unless indicated otherwise.
AEP sponsors a qualified pension plan and two unfunded nonqualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees.
Components of Net Periodic Benefit Cost
The following tables provide the components of net periodic benefit cost (credit) by Registrant for the plans:
AEP
| | | Pension Plans | | OPEB | | Pension Plans | | | OPEB | |
| Three Months Ended September 30, | | Three Months Ended September 30, | | Three Months Ended September 30, | | | Three Months Ended September 30, | |
| 2019 | | 2018 | | 2019 | | 2018 | | 2020 | | 2019 | | 2020 | | 2019 |
| (in millions) | | (in millions) | |
Service Cost | $ | 23.8 |
| | $ | 24.4 |
| | $ | 2.4 |
| | $ | 2.9 |
| Service Cost | $ | 28.0 | | | $ | 23.8 | | | $ | 2.5 | | | $ | 2.4 | |
Interest Cost | 51.1 |
| | 46.9 |
| | 12.6 |
| | 11.8 |
| Interest Cost | 42.0 | | | 51.1 | | | 10.0 | | | 12.6 | |
Expected Return on Plan Assets | (74.0 | ) | | (72.6 | ) | | (23.4 | ) | | (25.6 | ) | Expected Return on Plan Assets | (66.3) | | | (74.0) | | | (23.9) | | | (23.4) | |
Amortization of Prior Service Credit | — |
| | — |
| | (17.3 | ) | | (17.3 | ) | Amortization of Prior Service Credit | 0 | | | 0 | | | (17.4) | | | (17.3) | |
Amortization of Net Actuarial Loss | 14.4 |
| | 21.3 |
| | 5.5 |
| | 2.7 |
| Amortization of Net Actuarial Loss | 23.5 | | | 14.4 | | | 1.4 | | | 5.5 | |
Net Periodic Benefit Cost (Credit) | $ | 15.3 |
| | $ | 20.0 |
| | $ | (20.2 | ) | | $ | (25.5 | ) | Net Periodic Benefit Cost (Credit) | $ | 27.2 | | | $ | 15.3 | | | $ | (27.4) | | | $ | (20.2) | |
| | | | Pension Plans | | | OPEB | |
| | | Nine Months Ended September 30, | | | Nine Months Ended September 30, | |
| | | 2020 | | 2019 | | 2020 | | 2019 |
| | | (in millions) | |
Service Cost | | Service Cost | $ | 84.0 | | | $ | 71.6 | | | $ | 7.5 | | | $ | 7.1 | |
Interest Cost | | Interest Cost | 125.9 | | | 153.3 | | | 29.9 | | | 37.9 | |
Expected Return on Plan Assets | | Expected Return on Plan Assets | (198.7) | | | (222.0) | | | (71.8) | | | (70.3) | |
Amortization of Prior Service Credit | | Amortization of Prior Service Credit | 0 | | | 0 | | | (52.3) | | | (51.8) | |
Amortization of Net Actuarial Loss | | Amortization of Net Actuarial Loss | 70.3 | | | 43.2 | | | 4.4 | | | 16.6 | |
Net Periodic Benefit Cost (Credit) | | Net Periodic Benefit Cost (Credit) | $ | 81.5 | | | $ | 46.1 | | | $ | (82.3) | | | $ | (60.5) | |
|
| | | | | | | | | | | | | | | |
| Pension Plans | | OPEB |
| Nine Months Ended September 30, | | Nine Months Ended September 30, |
| 2019 | | 2018 | | 2019 | | 2018 |
| (in millions) |
Service Cost | $ | 71.6 |
| | $ | 73.2 |
| | $ | 7.1 |
| | $ | 8.7 |
|
Interest Cost | 153.3 |
| | 140.8 |
| | 37.9 |
| | 35.5 |
|
Expected Return on Plan Assets | (222.0 | ) | | (217.7 | ) | | (70.3 | ) | | (76.7 | ) |
Amortization of Prior Service Credit | — |
| | — |
| | (51.8 | ) | | (51.8 | ) |
Amortization of Net Actuarial Loss | 43.2 |
| | 63.9 |
| | 16.6 |
| | 7.9 |
|
Net Periodic Benefit Cost (Credit) | $ | 46.1 |
| | $ | 60.2 |
| | $ | (60.5 | ) | | $ | (76.4 | ) |
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, | |
| 2019 | | 2018 | | 2019 | | 2018 | | 2020 | | 2019 | | 2020 | | 2019 |
| (in millions) | | (in millions) | |
Service Cost | $ | 2.2 |
| | $ | 2.3 |
| | $ | 0.1 |
| | $ | 0.3 |
| Service Cost | $ | 2.6 | | | $ | 2.2 | | | $ | 0.2 | | | $ | 0.1 | |
Interest Cost | 4.4 |
| | 4.0 |
| | 1.0 |
| | 0.9 |
| Interest Cost | 3.5 | | | 4.4 | | | 0.8 | | | 1.0 | |
Expected Return on Plan Assets | (6.5 | ) | | (6.4 | ) | | (1.9 | ) | | (2.1 | ) | Expected Return on Plan Assets | (5.7) | | | (6.5) | | | (2.0) | | | (1.9) | |
Amortization of Prior Service Credit | — |
| | — |
| | (1.5 | ) | | (1.5 | ) | Amortization of Prior Service Credit | 0 | | | 0 | | | (1.4) | | | (1.5) | |
Amortization of Net Actuarial Loss | 1.2 |
| | 1.8 |
| | 0.5 |
| | 0.2 |
| Amortization of Net Actuarial Loss | 1.9 | | | 1.2 | | | 0.1 | | | 0.5 | |
Net Periodic Benefit Cost (Credit) | $ | 1.3 |
| | $ | 1.7 |
| | $ | (1.8 | ) | | $ | (2.2 | ) | Net Periodic Benefit Cost (Credit) | $ | 2.3 | | | $ | 1.3 | | | $ | (2.3) | | | $ | (1.8) | |
| | | | Pension Plans | | | OPEB | |
| | | Nine Months Ended September 30, | | | Nine Months Ended September 30, | |
| | | 2020 | | 2019 | | 2020 | | 2019 |
| | | (in millions) | |
Service Cost | | Service Cost | $ | 7.6 | | | $ | 6.5 | | | $ | 0.6 | | | $ | 0.5 | |
Interest Cost | | Interest Cost | 10.5 | | | 13.1 | | | 2.4 | | | 3.0 | |
Expected Return on Plan Assets | | Expected Return on Plan Assets | (17.1) | | | (19.4) | | | (6.0) | | | (5.8) | |
Amortization of Prior Service Credit | | Amortization of Prior Service Credit | 0 | | | 0 | | | (4.4) | | | (4.4) | |
Amortization of Net Actuarial Loss | | Amortization of Net Actuarial Loss | 5.8 | | | 3.7 | | | 0.4 | | | 1.4 | |
Net Periodic Benefit Cost (Credit) | | Net Periodic Benefit Cost (Credit) | $ | 6.8 | | | $ | 3.9 | | | $ | (7.0) | | | $ | (5.3) | |
|
| | | | | | | | | | | | | | | |
| Pension Plans | | OPEB |
| Nine Months Ended September 30, | | Nine Months Ended September 30, |
| 2019 | | 2018 | | 2019 | | 2018 |
| (in millions) |
Service Cost | $ | 6.5 |
| | $ | 6.9 |
| | $ | 0.5 |
| | $ | 0.7 |
|
Interest Cost | 13.1 |
| | 12.0 |
| | 3.0 |
| | 2.8 |
|
Expected Return on Plan Assets | (19.4 | ) | | (19.2 | ) | | (5.8 | ) | | (6.4 | ) |
Amortization of Prior Service Credit | — |
| | — |
| | (4.4 | ) | | (4.4 | ) |
Amortization of Net Actuarial Loss | 3.7 |
| | 5.4 |
| | 1.4 |
| | 0.6 |
|
Net Periodic Benefit Cost (Credit) | $ | 3.9 |
| | $ | 5.1 |
| | $ | (5.3 | ) | | $ | (6.7 | ) |
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, | |
| 2019 |
| 2018 | | 2019 | | 2018 | | 2020 | | 2019 | | 2020 | | 2019 |
| (in millions) | | (in millions) | |
Service Cost | $ | 2.4 |
| | $ | 2.4 |
| | $ | 0.2 |
| | $ | 0.3 |
| Service Cost | $ | 2.7 | | | $ | 2.4 | | | $ | 0.3 | | | $ | 0.2 | |
Interest Cost | 6.3 |
| | 5.8 |
| | 2.2 |
| | 2.1 |
| Interest Cost | 5.0 | | | 6.3 | | | 1.6 | | | 2.2 | |
Expected Return on Plan Assets | (9.4 | ) | | (9.1 | ) | | (3.7 | ) | | (4.0 | ) | Expected Return on Plan Assets | (8.4) | | | (9.4) | | | (3.6) | | | (3.7) | |
Amortization of Prior Service Credit | — |
| | — |
| | (2.5 | ) | | (2.5 | ) | Amortization of Prior Service Credit | 0 | | | 0 | | | (2.5) | | | (2.5) | |
Amortization of Net Actuarial Loss | 1.8 |
| | 2.6 |
| | 1.0 |
| | 0.4 |
| Amortization of Net Actuarial Loss | 2.8 | | | 1.8 | | | 0.2 | | | 1.0 | |
Net Periodic Benefit Cost (Credit) | $ | 1.1 |
| | $ | 1.7 |
| | $ | (2.8 | ) | | $ | (3.7 | ) | Net Periodic Benefit Cost (Credit) | $ | 2.1 | | | $ | 1.1 | | | $ | (4.0) | | | $ | (2.8) | |
| | | | Pension Plans | | | OPEB | |
| | | Nine Months Ended September 30, | | | Nine Months Ended September 30, | |
| | | 2020 | | 2019 | | 2020 | | 2019 |
| | | (in millions) | |
Service Cost | | Service Cost | $ | 7.9 | | | $ | 7.1 | | | $ | 0.8 | | | $ | 0.7 | |
Interest Cost | | Interest Cost | 15.2 | | | 18.9 | | | 4.9 | | | 6.5 | |
Expected Return on Plan Assets | | Expected Return on Plan Assets | (25.2) | | | (28.1) | | | (10.9) | | | (11.0) | |
Amortization of Prior Service Credit | | Amortization of Prior Service Credit | 0 | | | 0 | | | (7.6) | | | (7.5) | |
Amortization of Net Actuarial Loss | | Amortization of Net Actuarial Loss | 8.4 | | | 5.3 | | | 0.7 | | | 2.8 | |
Net Periodic Benefit Cost (Credit) | | Net Periodic Benefit Cost (Credit) | $ | 6.3 | | | $ | 3.2 | | | $ | (12.1) | | | $ | (8.5) | |
|
| | | | | | | | | | | | | | | |
| Pension Plans | | OPEB |
| Nine Months Ended September 30, | | Nine Months Ended September 30, |
| 2019 | | 2018 | | 2019 | | 2018 |
| (in millions) |
Service Cost | $ | 7.1 |
| | $ | 7.0 |
| | $ | 0.7 |
| | $ | 0.8 |
|
Interest Cost | 18.9 |
| | 17.6 |
| | 6.5 |
| | 6.2 |
|
Expected Return on Plan Assets | (28.1 | ) | | (27.4 | ) | | (11.0 | ) | | (12.0 | ) |
Amortization of Prior Service Credit | — |
| | — |
| | (7.5 | ) | | (7.5 | ) |
Amortization of Net Actuarial Loss | 5.3 |
| | 7.9 |
| | 2.8 |
| | 1.4 |
|
Net Periodic Benefit Cost (Credit) | $ | 3.2 |
| | $ | 5.1 |
| | $ | (8.5 | ) | | $ | (11.1 | ) |
I&M
| | | | | | | | | | | | | | | | | | | | | | | |
| Pension Plans | | | | OPEB | | |
| Three Months Ended September 30, | | | | Three Months Ended September 30, | | |
| 2020 | | 2019 | | 2020 | | 2019 |
| (in millions) | | | | | | |
Service Cost | $ | 3.9 | | | $ | 3.3 | | | $ | 0.4 | | | $ | 0.3 | |
Interest Cost | 4.9 | | | 6.0 | | | 1.2 | | | 1.5 | |
Expected Return on Plan Assets | (8.3) | | | (9.1) | | | (3.0) | | | (2.8) | |
Amortization of Prior Service Credit | 0 | | | 0 | | | (2.3) | | | (2.4) | |
Amortization of Net Actuarial Loss | 2.7 | | | 1.6 | | | 0.1 | | | 0.7 | |
Net Periodic Benefit Cost (Credit) | $ | 3.2 | | | $ | 1.8 | | | $ | (3.6) | | | $ | (2.7) | |
| | | | | | | |
| Pension Plans | | | | OPEB | | |
| Nine Months Ended September 30, | | | | Nine Months Ended September 30, | | |
| 2020 | | 2019 | | 2020 | | 2019 |
| (in millions) | | | | | | |
Service Cost | $ | 11.6 | | | $ | 10.0 | | | $ | 1.1 | | | $ | 1.0 | |
Interest Cost | 14.7 | | | 17.9 | | | 3.5 | | | 4.4 | |
Expected Return on Plan Assets | (24.9) | | | (27.5) | | | (8.8) | | | (8.5) | |
Amortization of Prior Service Credit | 0 | | | 0 | | | (7.1) | | | (7.1) | |
Amortization of Net Actuarial Loss | 8.1 | | | 4.9 | | | 0.5 | | | 2.0 | |
Net Periodic Benefit Cost (Credit) | $ | 9.5 | | | $ | 5.3 | | | $ | (10.8) | | | $ | (8.2) | |
|
| | | | | | | | | | | | | | | |
| Pension Plans | | OPEB |
| Three Months Ended September 30, | | Three Months Ended September 30, |
| 2019 | | 2018 | | 2019 | | 2018 |
| (in millions) |
Service Cost | $ | 3.3 |
| | $ | 3.4 |
| | $ | 0.3 |
| | $ | 0.4 |
|
Interest Cost | 6.0 |
| | 5.6 |
| | 1.5 |
| | 1.4 |
|
Expected Return on Plan Assets | (9.1 | ) | | (9.0 | ) | | (2.8 | ) | | (3.1 | ) |
Amortization of Prior Service Credit | — |
| | — |
| | (2.4 | ) | | (2.4 | ) |
Amortization of Net Actuarial Loss | 1.6 |
| | 2.5 |
| | 0.7 |
| | 0.3 |
|
Net Periodic Benefit Cost (Credit) | $ | 1.8 |
| | $ | 2.5 |
| | $ | (2.7 | ) | | $ | (3.4 | ) |
|
| | | | | | | | | | | | | | | |
| Pension Plans | | OPEB |
| Nine Months Ended September 30, | | Nine Months Ended September 30, |
| 2019 | | 2018 | | 2019 | | 2018 |
| (in millions) |
Service Cost | $ | 10.0 |
| | $ | 10.2 |
| | $ | 1.0 |
| | $ | 1.2 |
|
Interest Cost | 17.9 |
| | 16.6 |
| | 4.4 |
| | 4.1 |
|
Expected Return on Plan Assets | (27.5 | ) | | (26.8 | ) | | (8.5 | ) | | (9.3 | ) |
Amortization of Prior Service Credit | — |
| | — |
| | (7.1 | ) | | (7.1 | ) |
Amortization of Net Actuarial Loss | 4.9 |
| | 7.4 |
| | 2.0 |
| | 0.9 |
|
Net Periodic Benefit Cost (Credit) | $ | 5.3 |
| | $ | 7.4 |
| | $ | (8.2 | ) | | $ | (10.2 | ) |
OPCo
| | | | | | | | | | | | | | | | | | | | | | | |
| Pension Plans | | | | OPEB | | |
| Three Months Ended September 30, | | | | Three Months Ended September 30, | | |
| 2020 | | 2019 | | 2020 | | 2019 |
| (in millions) | | | | | | |
Service Cost | $ | 2.4 | | | $ | 1.9 | | | $ | 0.2 | | | $ | 0.2 | |
Interest Cost | 3.9 | | | 4.8 | | | 1.0 | | | 1.4 | |
Expected Return on Plan Assets | (6.6) | | | (7.3) | | | (2.6) | | | (2.7) | |
Amortization of Prior Service Credit | 0 | | | 0 | | | (1.8) | | | (1.8) | |
Amortization of Net Actuarial Loss | 2.1 | | | 1.3 | | | 0.2 | | | 0.6 | |
Net Periodic Benefit Cost (Credit) | $ | 1.8 | | | $ | 0.7 | | | $ | (3.0) | | | $ | (2.3) | |
| | | | | | | |
| Pension Plans | | | | OPEB | | |
| Nine Months Ended September 30, | | | | Nine Months Ended September 30, | | |
| 2020 | | 2019 | | 2020 | | 2019 |
| (in millions) | | | | | | |
Service Cost | $ | 7.2 | | | $ | 5.9 | | | $ | 0.7 | | | $ | 0.6 | |
Interest Cost | 11.6 | | | 14.3 | | | 3.1 | | | 4.1 | |
Expected Return on Plan Assets | (19.7) | | | (22.0) | | | (7.9) | | | (8.1) | |
Amortization of Prior Service Credit | 0 | | | 0 | | | (5.3) | | | (5.2) | |
Amortization of Net Actuarial Loss | 6.4 | | | 4.0 | | | 0.5 | | | 1.9 | |
Net Periodic Benefit Cost (Credit) | $ | 5.5 | | | $ | 2.2 | | | $ | (8.9) | | | $ | (6.7) | |
|
| | | | | | | | | | | | | | | |
| Pension Plans | | OPEB |
| Three Months Ended September 30, | | Three Months Ended September 30, |
| 2019 | | 2018 | | 2019 | | 2018 |
| (in millions) |
Service Cost | $ | 1.9 |
| | $ | 2.0 |
| | $ | 0.2 |
| | $ | 0.2 |
|
Interest Cost | 4.8 |
| | 4.4 |
| | 1.4 |
| | 1.3 |
|
Expected Return on Plan Assets | (7.3 | ) | | (7.2 | ) | | (2.7 | ) | | (2.9 | ) |
Amortization of Prior Service Credit | — |
| | — |
| | (1.8 | ) | | (1.7 | ) |
Amortization of Net Actuarial Loss | 1.3 |
| | 2.0 |
| | 0.6 |
| | 0.3 |
|
Net Periodic Benefit Cost (Credit) | $ | 0.7 |
| | $ | 1.2 |
| | $ | (2.3 | ) | | $ | (2.8 | ) |
|
| | | | | | | | | | | | | | | |
| Pension Plans | | OPEB |
| Nine Months Ended September 30, | | Nine Months Ended September 30, |
| 2019 | | 2018 | | 2019 | | 2018 |
| (in millions) |
Service Cost | $ | 5.9 |
| | $ | 5.8 |
| | $ | 0.6 |
| | $ | 0.7 |
|
Interest Cost | 14.3 |
| | 13.3 |
| | 4.1 |
| | 3.9 |
|
Expected Return on Plan Assets | (22.0 | ) | | (21.6 | ) | | (8.1 | ) | | (8.8 | ) |
Amortization of Prior Service Credit | — |
| | — |
| | (5.2 | ) | | (5.2 | ) |
Amortization of Net Actuarial Loss | 4.0 |
| | 6.0 |
| | 1.9 |
| | 0.8 |
|
Net Periodic Benefit Cost (Credit) | $ | 2.2 |
| | $ | 3.5 |
| | $ | (6.7 | ) | | $ | (8.6 | ) |
PSO
| | | | | | | | | | | | | | | | | | | | | | | |
| Pension Plans | | | | OPEB | | |
| Three Months Ended September 30, | | | | Three Months Ended September 30, | | |
| 2020 | | 2019 | | 2020 | | 2019 |
| (in millions) | | | | | | |
Service Cost | $ | 1.9 | | | $ | 1.6 | | | $ | 0.1 | | | $ | 0.2 | |
Interest Cost | 2.1 | | | 2.6 | | | 0.6 | | | 0.7 | |
Expected Return on Plan Assets | (3.6) | | | (4.0) | | | (1.3) | | | (1.3) | |
Amortization of Prior Service Credit | 0 | | | 0 | | | (1.0) | | | (1.1) | |
Amortization of Net Actuarial Loss | 1.1 | | | 0.7 | | | 0 | | | 0.3 | |
Net Periodic Benefit Cost (Credit) | $ | 1.5 | | | $ | 0.9 | | | $ | (1.6) | | | $ | (1.2) | |
| | | | | | | |
| Pension Plans | | | | OPEB | | |
| Nine Months Ended September 30, | | | | Nine Months Ended September 30, | | |
| 2020 | | 2019 | | 2020 | | 2019 |
| (in millions) | | | | | | |
Service Cost | $ | 5.5 | | | $ | 4.9 | | | $ | 0.4 | | | $ | 0.5 | |
Interest Cost | 6.4 | | | 7.9 | | | 1.6 | | | 2.0 | |
Expected Return on Plan Assets | (10.9) | | | (12.2) | | | (3.9) | | | (3.9) | |
Amortization of Prior Service Credit | 0 | | | 0 | | | (3.2) | | | (3.2) | |
Amortization of Net Actuarial Loss | 3.5 | | | 2.2 | | | 0.2 | | | 0.9 | |
Net Periodic Benefit Cost (Credit) | $ | 4.5 | | | $ | 2.8 | | | $ | (4.9) | | | $ | (3.7) | |
|
| | | | | | | | | | | | | | | |
| Pension Plans | | OPEB |
| Three Months Ended September 30, | | Three Months Ended September 30, |
| 2019 | | 2018 | | 2019 | | 2018 |
| (in millions) |
Service Cost | $ | 1.6 |
| | $ | 1.7 |
| | $ | 0.2 |
| | $ | 0.1 |
|
Interest Cost | 2.6 |
| | 2.5 |
| | 0.7 |
| | 0.6 |
|
Expected Return on Plan Assets | (4.0 | ) | | (4.0 | ) | | (1.3 | ) | | (1.3 | ) |
Amortization of Prior Service Credit | — |
| | — |
| | (1.1 | ) | | (1.1 | ) |
Amortization of Net Actuarial Loss | 0.7 |
| | 1.1 |
| | 0.3 |
| | 0.1 |
|
Net Periodic Benefit Cost (Credit) | $ | 0.9 |
| | $ | 1.3 |
| | $ | (1.2 | ) | | $ | (1.6 | ) |
|
| | | | | | | | | | | | | | | |
| Pension Plans | | OPEB |
| Nine Months Ended September 30, | | Nine Months Ended September 30, |
| 2019 | | 2018 | | 2019 | | 2018 |
| (in millions) |
Service Cost | $ | 4.9 |
| | $ | 5.3 |
| | $ | 0.5 |
| | $ | 0.5 |
|
Interest Cost | 7.9 |
| | 7.4 |
| | 2.0 |
| | 1.8 |
|
Expected Return on Plan Assets | (12.2 | ) | | (12.1 | ) | | (3.9 | ) | | (4.1 | ) |
Amortization of Prior Service Credit | — |
| | — |
| | (3.2 | ) | | (3.2 | ) |
Amortization of Net Actuarial Loss | 2.2 |
| | 3.3 |
| | 0.9 |
| | 0.4 |
|
Net Periodic Benefit Cost (Credit) | $ | 2.8 |
| | $ | 3.9 |
| | $ | (3.7 | ) | | $ | (4.6 | ) |
SWEPCo
| | | | | | | | | | | | | | | | | | | | | | | |
| Pension Plans | | | | OPEB | | |
| Three Months Ended September 30, | | | | Three Months Ended September 30, | | |
| 2020 | | 2019 | | 2020 | | 2019 |
| (in millions) | | | | | | |
Service Cost | $ | 2.6 | | | $ | 2.1 | | | $ | 0.2 | | | $ | 0.2 | |
Interest Cost | 2.5 | | | 3.1 | | | 0.6 | | | 0.7 | |
Expected Return on Plan Assets | (3.9) | | | (4.4) | | | (1.5) | | | (1.5) | |
Amortization of Prior Service Credit | 0 | | | 0 | | | (1.3) | | | (1.3) | |
Amortization of Net Actuarial Loss | 1.4 | | | 0.9 | | | 0.1 | | | 0.4 | |
Net Periodic Benefit Cost (Credit) | $ | 2.6 | | | $ | 1.7 | | | $ | (1.9) | | | $ | (1.5) | |
| | | | | | | |
| Pension Plans | | | | OPEB | | |
| Nine Months Ended September 30, | | | | Nine Months Ended September 30, | | |
| 2020 | | 2019 | | 2020 | | 2019 |
| (in millions) | | | | | | |
Service Cost | $ | 7.5 | | | $ | 6.4 | | | $ | 0.6 | | | $ | 0.6 | |
Interest Cost | 7.6 | | | 9.3 | | | 1.9 | | | 2.3 | |
Expected Return on Plan Assets | (11.7) | | | (13.3) | | | (4.7) | | | (4.5) | |
Amortization of Prior Service Credit | 0 | | | 0 | | | (3.9) | | | (3.9) | |
Amortization of Net Actuarial Loss | 4.2 | | | 2.6 | | | 0.3 | | | 1.1 | |
Net Periodic Benefit Cost (Credit) | $ | 7.6 | | | $ | 5.0 | | | $ | (5.8) | | | $ | (4.4) | |
|
| | | | | | | | | | | | | | | |
| Pension Plans | | OPEB |
| Three Months Ended September 30, | | Three Months Ended September 30, |
| 2019 | | 2018 | | 2019 | | 2018 |
| (in millions) |
Service Cost | $ | 2.1 |
| | $ | 2.4 |
| | $ | 0.2 |
| | $ | 0.2 |
|
Interest Cost | 3.1 |
| | 2.8 |
| | 0.7 |
| | 0.7 |
|
Expected Return on Plan Assets | (4.4 | ) | | (4.4 | ) | | (1.5 | ) | | (1.6 | ) |
Amortization of Prior Service Credit | — |
| | — |
| | (1.3 | ) | | (1.3 | ) |
Amortization of Net Actuarial Loss | 0.9 |
| | 1.3 |
| | 0.4 |
| | 0.2 |
|
Net Periodic Benefit Cost (Credit) | $ | 1.7 |
| | $ | 2.1 |
| | $ | (1.5 | ) | | $ | (1.8 | ) |
|
| | | | | | | | | | | | | | | |
| Pension Plans | | OPEB |
| Nine Months Ended September 30, | | Nine Months Ended September 30, |
| 2019 | | 2018 | | 2019 | | 2018 |
| (in millions) |
Service Cost | $ | 6.4 |
| | $ | 7.0 |
| | $ | 0.6 |
| | $ | 0.7 |
|
Interest Cost | 9.3 |
| | 8.5 |
| | 2.3 |
| | 2.1 |
|
Expected Return on Plan Assets | (13.3 | ) | | (13.1 | ) | | (4.5 | ) | | (4.8 | ) |
Amortization of Prior Service Credit | — |
| | — |
| | (3.9 | ) | | (3.9 | ) |
Amortization of Net Actuarial Loss | 2.6 |
| | 3.8 |
| | 1.1 |
| | 0.5 |
|
Net Periodic Benefit Cost (Credit) | $ | 5.0 |
| | $ | 6.2 |
| | $ | (4.4 | ) | | $ | (5.4 | ) |
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 SSOstandard 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
•Competitive generation in ERCOT and PJM.
•Contracted renewable energy investments and management services.
•Marketing, risk management and retail activities in ERCOT, PJM, SPP and MISO.
Contracted renewable energy investments and management services.
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 present AEP’s reportable segment income statement information for the three and nine months ended September 30, 20192020 and 20182019 and reportable segment balance sheet information as of September 30, 20192020 and December 31, 2018.2019.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, 2020 | | | | | | | | | | | | |
| Vertically Integrated Utilities | | Transmission and Distribution Utilities | | AEP Transmission Holdco | | Generation & Marketing | | Corporate and Other (a) | | Reconciling Adjustments | | Consolidated |
| (in millions) | | | | | | | | | | | | |
Revenues from: | | | | | | | | | | | | | |
External Customers | $ | 2,400.1 | | | $ | 1,124.1 | | | $ | 73.4 | | | $ | 464.8 | | | $ | 4.0 | | | $ | 0 | | | $ | 4,066.4 | |
Other Operating Segments | 34.7 | | | 41.2 | | | 244.5 | | | 25.2 | | | 28.6 | | | (374.2) | | | 0 | |
Total Revenues | $ | 2,434.8 | | | $ | 1,165.3 | | | $ | 317.9 | | | $ | 490.0 | | | $ | 32.6 | | | $ | (374.2) | | | $ | 4,066.4 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Net Income (Loss) | $ | 394.2 | | | $ | 147.4 | | | $ | 139.3 | | | $ | 114.6 | | | $ | (47.3) | | | $ | 0 | | | $ | 748.2 | |
| | | | | | | | | | | | | |
| Three Months Ended September 30, 2019 | | | | | | | | | | | | |
| Vertically Integrated Utilities | | Transmission and Distribution Utilities | | AEP Transmission Holdco | | Generation & Marketing | | Corporate and Other (a) | | Reconciling Adjustments | | Consolidated |
| (in millions) | | | | | | | | | | | | |
Revenues from: | | | | | | | | | | | | | |
External Customers | $ | 2,598.9 | | | $ | 1,147.3 | | | $ | 65.5 | | | $ | 501.2 | | | $ | 2.1 | | | $ | 0 | | | $ | 4,315.0 | |
Other Operating Segments | 46.6 | | | 39.3 | | | 207.5 | | | 32.5 | | | 22.3 | | | (348.2) | | | 0 | |
Total Revenues | $ | 2,645.5 | | | $ | 1,186.6 | | | $ | 273.0 | | | $ | 533.7 | | | $ | 24.4 | | | $ | (348.2) | | | $ | 4,315.0 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Net Income (Loss) | $ | 438.4 | | | $ | 133.7 | | | $ | 127.0 | | | $ | 88.7 | | | $ | (53.9) | | | $ | 0 | | | $ | 733.9 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| Nine Months Ended September 30, 2020 | | | | | | | | | | | | |
| Vertically Integrated Utilities | | Transmission and Distribution Utilities | | AEP Transmission Holdco | | Generation & Marketing | | Corporate and Other (a) | | Reconciling Adjustments | | Consolidated |
| (in millions) | | | | | | | | | | | | |
Revenues from: | | | | | | | | | | | | | |
External Customers | $ | 6,655.4 | | | $ | 3,208.7 | | | $ | 215.7 | | | $ | 1,223.4 | | | $ | 4.7 | | | $ | 0 | | | $ | 11,307.9 | |
Other Operating Segments | 98.1 | | | 98.0 | | | 662.1 | | | 82.1 | | | 67.3 | | | (1,007.6) | | | 0 | |
Total Revenues | $ | 6,753.5 | | | $ | 3,306.7 | | | $ | 877.8 | | | $ | 1,305.5 | | | $ | 72.0 | | | $ | (1,007.6) | | | $ | 11,307.9 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Net Income (Loss) | $ | 896.8 | | | $ | 403.1 | | | $ | 373.1 | | | $ | 203.6 | | | $ | (114.6) | | | $ | 0 | | | $ | 1,762.0 | |
| | | | | | | | | | | | | |
| Nine Months Ended September 30, 2019 | | | | | | | | | | | | |
| Vertically Integrated Utilities | | Transmission and Distribution Utilities | | AEP Transmission Holdco | | Generation & Marketing | | Corporate and Other (a) | | Reconciling Adjustments | | Consolidated |
| (in millions) | | | | | | | | | | | | |
Revenues from: | | | | | | | | | | | | | |
External Customers | $ | 7,087.6 | | | $ | 3,328.7 | | | $ | 196.5 | | | $ | 1,323.8 | | | $ | 8.8 | | | $ | 0 | | | $ | 11,945.4 | |
Other Operating Segments | 85.0 | | | 125.6 | | | 611.8 | | | 104.4 | | | 64.9 | | | (991.7) | | | 0 | |
Total Revenues | $ | 7,172.6 | | | $ | 3,454.3 | | | $ | 808.3 | | | $ | 1,428.2 | | | $ | 73.7 | | | $ | (991.7) | | | $ | 11,945.4 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Net Income (Loss) | $ | 920.8 | | | $ | 421.6 | | | $ | 407.6 | | | $ | 133.1 | | | $ | (116.0) | | | $ | 0 | | | $ | 1,767.1 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, 2019 |
| Vertically Integrated Utilities | | Transmission and Distribution Utilities | | AEP Transmission Holdco | | Generation & Marketing | | Corporate and Other (a) | | Reconciling Adjustments | | Consolidated |
| (in millions) |
Revenues from: | |
| | |
| | |
| | |
| | |
| | | | |
|
External Customers | $ | 2,598.9 |
| | $ | 1,147.3 |
| | $ | 65.5 |
| | $ | 501.2 |
| | $ | 2.1 |
| | $ | — |
| | $ | 4,315.0 |
|
Other Operating Segments | 46.6 |
| | 39.3 |
| | 207.5 |
| | 32.5 |
| | 22.3 |
| | (348.2 | ) | | — |
|
Total Revenues | $ | 2,645.5 |
| | $ | 1,186.6 |
| | $ | 273.0 |
| | $ | 533.7 |
| | $ | 24.4 |
| | $ | (348.2 | ) | | $ | 4,315.0 |
|
| | | | | | | | | | | | | |
Net Income (Loss) | $ | 438.4 |
| | $ | 133.7 |
| | $ | 127.0 |
| | $ | 88.7 |
| | $ | (53.9 | ) | | $ | — |
| | $ | 733.9 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | September 30, 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 | | $ | 48,533.5 | | | $ | 20,738.7 | | | $ | 11,377.1 | | | $ | 1,854.4 | | | $ | 399.3 | | | $ | 0 | | | $ | 82,903.0 | |
Accumulated Depreciation and Amortization | | 15,340.1 | | | 3,891.6 | | | 553.1 | | | 150.1 | | | 181.7 | | | 0 | | | 20,116.6 | |
Total Property Plant and Equipment - Net | | $ | 33,193.4 | | | $ | 16,847.1 | | | $ | 10,824.0 | | | $ | 1,704.3 | | | $ | 217.6 | | | $ | 0 | | | $ | 62,786.4 | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
Total Assets | | $ | 42,110.4 | | | $ | 19,250.3 | | | $ | 12,035.8 | | | $ | 3,368.6 | | | $ | 5,718.9 | | (b) | $ | (3,794.7) | | (c) | $ | 78,689.3 | |
| | | | | | | | | | | | | | |
Long-term Debt Due Within One Year: | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
Nonaffiliated | | 1,313.7 | | | 87.8 | | | 2.3 | | | 0 | | | 507.8 | | (d) | 0 | | | 1,911.6 | |
| | | | | | | | | | | | | | |
Long-term Debt: | | | | | | | | | | | | | | |
Affiliated | | 59.0 | | | 0 | | | 0 | | | 0 | | | 0 | | | (59.0) | | | 0 | |
Nonaffiliated | | 12,048.7 | | | 7,196.7 | | | 4,123.2 | | | 0 | | | 4,786.9 | | (d) | 0 | | | 28,155.5 | |
| | | | | | | | | | | | | | |
Total Long-term Debt | | $ | 13,421.4 | | | $ | 7,284.5 | | | $ | 4,125.5 | | | $ | 0 | | | $ | 5,294.7 | | | $ | (59.0) | | | $ | 30,067.1 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| | December 31, 2019 | | | | | | | | | | | | |
| | 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 | | $ | 47,323.7 | | | $ | 19,773.3 | | | $ | 10,334.0 | | | $ | 1,650.8 | | | $ | 418.4 | | | $ | (354.5) | | (e) | $ | 79,145.7 | |
Accumulated Depreciation and Amortization | | 14,580.4 | | | 3,911.2 | | | 418.9 | | | 99.0 | | | 184.5 | | | (186.4) | | (e) | 19,007.6 | |
Total Property Plant and Equipment - Net | | $ | 32,743.3 | | | $ | 15,862.1 | | | $ | 9,915.1 | | | $ | 1,551.8 | | | $ | 233.9 | | | $ | (168.1) | | (e) | $ | 60,138.1 | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
Total Assets | | $ | 41,228.8 | | | $ | 18,757.5 | | | $ | 11,143.5 | | | $ | 3,123.8 | | | $ | 5,440.0 | | (b) | $ | (3,801.3) | | (c) (e) | $ | 75,892.3 | |
| | | | | | | | | | | | | | |
Long-term Debt Due Within One Year: | | | | | | | | | | | | | | |
Affiliated | | $ | 20.0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | (20.0) | | | $ | 0 | |
Nonaffiliated | | 704.7 | | | 392.2 | | | 0 | | | 0 | | | 501.8 | | (d) | 0 | | | 1,598.7 | |
| | | | | | | | | | | | | | |
Long-term Debt: | | | | | | | | | | | | | | |
Affiliated | | 39.0 | | | 0 | | | 0 | | | 0 | | | 0 | | | (39.0) | | | 0 | |
Nonaffiliated | | 12,162.0 | | | 6,248.1 | | | 3,593.8 | | | 0 | | | 3,122.9 | | (d) | 0 | | | 25,126.8 | |
| | | | | | | | | | | | | | |
Total Long-term Debt | | $ | 12,925.7 | | | $ | 6,640.3 | | | $ | 3,593.8 | | | $ | 0 | | | $ | 3,624.7 | | | $ | (59.0) | | | $ | 26,725.5 | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, 2018 |
| Vertically Integrated Utilities | | Transmission and Distribution Utilities | | AEP Transmission Holdco | | Generation & Marketing | | Corporate and Other (a) | | Reconciling Adjustments | | Consolidated |
| (in millions) |
Revenues from: | |
| | |
| | |
| | |
| | |
| | | | |
|
External Customers | $ | 2,610.2 |
| | $ | 1,180.9 |
| | $ | 51.9 |
| | $ | 486.5 |
| | $ | 3.6 |
| | $ | — |
| | $ | 4,333.1 |
|
Other Operating Segments | 26.5 |
| | 30.6 |
| | 135.3 |
| | 35.1 |
| | 20.1 |
| | (247.6 | ) | | — |
|
Total Revenues | $ | 2,636.7 |
| | $ | 1,211.5 |
| | $ | 187.2 |
| | $ | 521.6 |
| | $ | 23.7 |
| | $ | (247.6 | ) | | $ | 4,333.1 |
|
| | | | | | | | | | | | | |
Net Income (Loss) | $ | 345.6 |
| | $ | 145.2 |
| | $ | 74.2 |
| | $ | 5.1 |
| | $ | 9.6 |
| | $ | — |
| | $ | 579.7 |
|
(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. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2019 |
| Vertically Integrated Utilities | | Transmission and Distribution Utilities | | AEP Transmission Holdco | | Generation & Marketing | | Corporate and Other (a) | | Reconciling Adjustments | | Consolidated |
| (in millions) |
Revenues from: | |
| | |
| | |
| | |
| | |
| | | | |
|
External Customers | $ | 7,087.6 |
| | $ | 3,328.7 |
| | $ | 196.5 |
| | $ | 1,323.8 |
| | $ | 8.8 |
| | $ | — |
| | $ | 11,945.4 |
|
Other Operating Segments | 85.0 |
| | 125.6 |
| | 611.8 |
| | 104.4 |
| | 64.9 |
| | (991.7 | ) | | — |
|
Total Revenues | $ | 7,172.6 |
| | $ | 3,454.3 |
| | $ | 808.3 |
| | $ | 1,428.2 |
| | $ | 73.7 |
| | $ | (991.7 | ) | | $ | 11,945.4 |
|
| | | | | | | | | | | | | |
Net Income (Loss) | $ | 920.8 |
| | $ | 421.6 |
| | $ | 407.6 |
| | $ | 133.1 |
| | $ | (116.0 | ) | | $ | — |
| | $ | 1,767.1 |
|
(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. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2018 |
| Vertically Integrated Utilities | | Transmission and Distribution Utilities | | AEP Transmission Holdco | | Generation & Marketing | | Corporate and Other (a) | | Reconciling Adjustments | | Consolidated |
| (in millions) |
Revenues from: | |
| | |
| | |
| | |
| | |
| | | | |
|
External Customers | $ | 7,332.4 |
| | $ | 3,450.0 |
| | $ | 196.5 |
| | $ | 1,399.3 |
| | $ | 16.4 |
| | $ | — |
| | $ | 12,394.6 |
|
Other Operating Segments | 61.3 |
| | 60.9 |
| | 408.7 |
| | 88.1 |
| | 55.1 |
| | (674.1 | ) | | — |
|
Total Revenues | $ | 7,393.7 |
| | $ | 3,510.9 |
| | $ | 605.2 |
| | $ | 1,487.4 |
| | $ | 71.5 |
| | $ | (674.1 | ) | | $ | 12,394.6 |
|
| | | | | | | | | | | | | |
Net Income (Loss) | $ | 856.3 |
| | $ | 384.6 |
| | $ | 280.9 |
| | $ | 61.8 |
| | $ | (17.1 | ) | | $ | — |
| | $ | 1,566.5 |
|
(d)Amounts are inclusive of the impact of fair value hedge accounting. See “Accounting for Fair Value Hedging Strategies” section of Note 10 for additional information.
(e)Includes eliminations due to an intercompany finance lease.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | September 30, 2019 |
| | 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 | | $ | 46,739.8 |
| | $ | 19,283.9 |
| | $ | 9,700.4 |
| | $ | 1,661.6 |
| | $ | 421.7 |
| | $ | (354.5 | ) | (b) | $ | 77,452.9 |
|
Accumulated Depreciation and Amortization | | 14,359.3 |
| | 3,907.3 |
| | 383.8 |
| | 99.8 |
| | 196.4 |
| | (186.4 | ) | (b) | 18,760.2 |
|
Total Property Plant and Equipment - Net | | $ | 32,380.5 |
| | $ | 15,376.6 |
| | $ | 9,316.6 |
| | $ | 1,561.8 |
| | $ | 225.3 |
| | $ | (168.1 | ) | (b) | $ | 58,692.7 |
|
| | | | | | | | | | | | | | |
Total Assets | | $ | 40,746.1 |
| | $ | 17,967.6 |
| | $ | 10,606.7 |
| | $ | 3,315.9 |
| | $ | 5,002.3 |
| (c) | $ | (3,737.9 | ) | (b) (d) | $ | 73,900.7 |
|
| | | | | | | | | | | | | | |
Long-term Debt Due Within One Year: | | | | | | | | | | | | | | |
Nonaffiliated | | $ | 687.4 |
| | $ | 391.5 |
| | $ | 249.0 |
| | $ | — |
| | $ | (0.2 | ) | (e) | $ | — |
| | $ | 1,327.7 |
|
| | | | | | | | | | | | | | |
Long-term Debt: | | | | | | | | | | | | | | |
Affiliated | | 59.0 |
| | — |
| | — |
| | 32.2 |
| | — |
| | (91.2 | ) | | — |
|
Nonaffiliated | | 12,161.1 |
| | 5,868.9 |
| | 3,426.9 |
| | (0.3 | ) | | 3,096.9 |
| | — |
| | 24,553.5 |
|
| | | | | | | | | | | | | | |
Total Long-term Debt | | $ | 12,907.5 |
| | $ | 6,260.4 |
| | $ | 3,675.9 |
| | $ | 31.9 |
| | $ | 3,096.7 |
| (e) | $ | (91.2 | ) | | $ | 25,881.2 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2018 |
| | 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 | | $ | 45,365.1 |
| | $ | 18,126.7 |
| | $ | 8,659.5 |
| | $ | 893.3 |
| | $ | 395.2 |
| | $ | (354.6 | ) | (b) | $ | 73,085.2 |
|
Accumulated Depreciation and Amortization | | 13,822.5 |
| | 3,833.7 |
| | 282.8 |
| | 47.0 |
| | 186.6 |
| | (186.5 | ) | (b) | 17,986.1 |
|
Total Property Plant and Equipment - Net | | $ | 31,542.6 |
| | $ | 14,293.0 |
| | $ | 8,376.7 |
| | $ | 846.3 |
| | $ | 208.6 |
| | $ | (168.1 | ) | (b) | $ | 55,099.1 |
|
| | | | | | | | | | | | | | |
Total Assets | | $ | 38,874.3 |
| | $ | 17,083.4 |
| | $ | 9,543.7 |
| | $ | 1,979.7 |
| | $ | 4,036.5 |
| (c) | $ | (2,714.8 | ) | (b) (d) | $ | 68,802.8 |
|
| | | | | | | | | | | | | | |
Long-term Debt Due Within One Year: | | | | | | | | | | | | | | |
Nonaffiliated | | $ | 1,066.3 |
| | $ | 549.1 |
| | $ | 85.0 |
| | $ | 0.1 |
| | $ | (2.0 | ) | (e) | $ | — |
| | $ | 1,698.5 |
|
| | | | | | | | | | | | | | |
Long-term Debt: | | | | | | | | | | | | | | |
Affiliated | | 50.0 |
| | — |
| | — |
| | 32.2 |
| | — |
| | (82.2 | ) | | — |
|
Nonaffiliated | | 11,442.7 |
| | 5,048.8 |
| | 2,888.6 |
| | (0.3 | ) | | 2,268.4 |
| | — |
| | 21,648.2 |
|
| | | | | | | | | | | | | | |
Total Long-term Debt | | $ | 12,559.0 |
| | $ | 5,597.9 |
| | $ | 2,973.6 |
| | $ | 32.0 |
| | $ | 2,266.4 |
| (e) | $ | (82.2 | ) | | $ | 23,346.7 |
|
| |
(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 eliminations due to an intercompany finance lease. |
| |
(c) | Includes elimination of AEP Parent’s investments in wholly-owned subsidiary companies. |
| |
(d) | Reconciling Adjustments for Total Assets primarily include elimination of intercompany advances to affiliates and intercompany accounts receivable. |
| |
(e) | Amounts reflect the impact of fair value hedge accounting. See “Accounting for Fair Value Hedging Strategies” section of Note 10 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, 20192020 and 20182019 and reportable segment balance sheet information as of September 30, 20192020 and December 31, 2018.2019.
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, 2020 | | | | | | |
| State Transcos | | AEPTCo Parent | | Reconciling Adjustments | | AEPTCo Consolidated |
| (in millions) | | | | | | |
Revenues from: | | | | | | | |
External Customers | $ | 62.9 | | | $ | 0 | | | $ | 0 | | | $ | 62.9 | |
Sales to AEP Affiliates | 241.2 | | | 0 | | | 0 | | | 241.2 | |
| | | | | | | |
Total Revenues | $ | 304.1 | | | $ | 0 | | | $ | 0 | | | $ | 304.1 | |
| | | | | | | |
Interest Income | $ | 0 | | | $ | 38.4 | | | $ | (38.2) | | (a) | $ | 0.2 | |
Interest Expense | 32.7 | | | 38.2 | | | (38.2) | | (a) | 32.7 | |
Income Tax Expense | 31.7 | | | 0 | | | 0 | | | 31.7 | |
| | | | | | | |
| | | | | | | |
Net Income | $ | 117.5 | | | $ | 0.1 | | (b) | $ | 0 | | | $ | 117.6 | |
| | | | | | | |
| Three Months Ended September 30, 2019 | | | | | | |
| State Transcos | | AEPTCo Parent | | Reconciling Adjustments | | AEPTCo Consolidated |
| (in millions) | | | | | | |
Revenues from: | | | | | | | |
External Customers | $ | 54.0 | | | $ | 0 | | | $ | 0 | | | $ | 54.0 | |
Sales to AEP Affiliates | 205.7 | | | 0 | | | 0 | | | 205.7 | |
| | | | | | | |
Total Revenues | $ | 259.7 | | | $ | 0 | | | $ | 0 | | | $ | 259.7 | |
| | | | | | | |
Interest Income | $ | 0.4 | | | $ | 32.3 | | | $ | (31.9) | | (a) | $ | 0.8 | |
Interest Expense | 26.4 | | | 31.9 | | | (31.9) | | (a) | 26.4 | |
Income Tax Expense | 30.0 | | | 0.1 | | | 0 | | | 30.1 | |
| | | | | | | |
| | | | | | | |
Net Income | $ | 107.3 | | | $ | 0.3 | | (b) | $ | 0 | | | $ | 107.6 | |
| | | Three Months Ended September 30, 2019 | | Nine Months Ended September 30, 2020 | |
| State Transcos | | AEPTCo Parent | | Reconciling Adjustments | | AEPTCo Consolidated | | State Transcos | | AEPTCo Parent | | Reconciling Adjustments | | AEPTCo Consolidated |
| (in millions) | | (in millions) | |
Revenues from: | | | | | | | | Revenues from: | |
External Customers | $ | 54.0 |
| | $ | — |
| | $ | — |
| | $ | 54.0 |
| External Customers | $ | 184.6 | | | $ | 0 | | | $ | 0 | | | $ | 184.6 | |
Sales to AEP Affiliates | 205.7 |
| | — |
| | — |
| | 205.7 |
| Sales to AEP Affiliates | 652.6 | | 0 | | | 0 | | | 652.6 | |
Other Revenues | — |
| | — |
| | — |
| | — |
| Other Revenues | 0.6 | | | 0 | | | 0 | | | 0.6 | |
Total Revenues | $ | 259.7 |
| | $ | — |
| | $ | — |
| | $ | 259.7 |
| Total Revenues | $ | 837.8 | | | $ | 0 | | | $ | 0 | | | $ | 837.8 | |
| | | | | | | | | | | | | | | |
Interest Income | $ | 0.4 |
| | $ | 32.3 |
| | $ | (31.9 | ) | (a) | $ | 0.8 |
| Interest Income | $ | 0.9 | | | $ | 111.3 | | | $ | (109.9) | | (a) | $ | 2.3 | |
Interest Expense | 26.4 |
| | 31.9 |
| | (31.9 | ) | (a) | 26.4 |
| Interest Expense | 95.1 | | | 109.9 | | | (109.9) | | (a) | 95.1 | |
Income Tax Expense | 30.0 |
| | 0.1 |
| | — |
| | 30.1 |
| Income Tax Expense | 82.7 | | | 0.1 | | | 0 | | | 82.8 | |
| | | | | | | | |
| Net Income | $ | 107.3 |
| | $ | 0.3 |
| (b) | $ | — |
| | $ | 107.6 |
| Net Income | $ | 308.0 | | | $ | 1.1 | | (b) | $ | 0 | | | $ | 309.1 | |
| | | | Nine Months Ended September 30, 2019 | |
| | | State Transcos | | AEPTCo Parent | | Reconciling Adjustments | | AEPTCo Consolidated |
| | | (in millions) | |
Revenues from: | | Revenues from: | |
External Customers | | External Customers | $ | 162.1 | | | $ | 0 | | | $ | 0 | | | $ | 162.1 | |
Sales to AEP Affiliates | | Sales to AEP Affiliates | 608.0 | | 0 | | | 0 | | | 608.0 | |
| Total Revenues | | Total Revenues | $ | 770.1 | | | $ | 0 | | | $ | 0 | | | $ | 770.1 | |
| Interest Income | | Interest Income | $ | 0.8 | | | $ | 89.7 | | | $ | (88.4) | | (a) | $ | 2.1 | |
Interest Expense | | Interest Expense | 69.5 | | 88.4 | | (88.4) | | (a) | 69.5 |
Income Tax Expense | | Income Tax Expense | 90.5 | | | 0.2 | | | 0 | | | 90.7 | |
| | Net Income | | Net Income | $ | 347.1 | | | $ | 0.8 | | (b) | $ | 0 | | | $ | 347.9 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| September 30, 2020 | | | | | | |
| State Transcos | | AEPTCo Parent | | Reconciling Adjustments | | AEPTCo Consolidated |
| (in millions) | | | | | | |
Total Transmission Property | $ | 10,921.3 | | | $ | 0 | | | $ | 0 | | | $ | 10,921.3 | |
Accumulated Depreciation and Amortization | 531.8 | | | 0 | | | 0 | | | 531.8 | |
Total Transmission Property – Net | $ | 10,389.5 | | | $ | 0 | | | $ | 0 | | | $ | 10,389.5 | |
| | | | | | | |
Notes Receivable - Affiliated | $ | 0 | | | $ | 3,947.9 | | | $ | (3,947.9) | | (c) | $ | 0 | |
| | | | | | | |
Total Assets | $ | 10,641.8 | | | $ | 4,104.1 | | (d) | $ | (4,047.2) | | (e) | $ | 10,698.7 | |
| | | | | | | |
Total Long-term Debt | $ | 3,990.0 | | | $ | 3,947.9 | | | $ | (3,990.0) | | (c) | $ | 3,947.9 | |
| | | | | | | |
| December 31, 2019 | | | | | | |
| State Transcos | | AEPTCo Parent | | Reconciling Adjustments | | AEPTCo Consolidated |
| (in millions) | | | | | | |
Total Transmission Property | $ | 9,893.2 | | | $ | 0 | | | $ | 0 | | | $ | 9,893.2 | |
Accumulated Depreciation and Amortization | 402.3 | | | 0 | | | 0 | | | 402.3 | |
Total Transmission Property – Net | $ | 9,490.9 | | | $ | 0 | | | $ | 0 | | | $ | 9,490.9 | |
| | | | | | | |
Notes Receivable - Affiliated | $ | — | | | $ | 3,427.3 | | | $ | (3,427.3) | | (c) | $ | 0 | |
| | | | | | | |
Total Assets | $ | 9,865.0 | | | $ | 3,519.1 | | (d) | $ | (3,493.3) | | (e) | $ | 9,890.8 | |
| | | | | | | |
Total Long-term Debt | $ | 3,465.0 | | | $ | 3,427.3 | | | $ | (3,465.0) | | (c) | $ | 3,427.3 | |
(a)Elimination of intercompany interest income/interest expense on affiliated debt arrangement.
(b)Includes the elimination of AEPTCo Parent’s equity earnings in the State Transcos.
(c)Elimination of intercompany debt.
(d)Includes the elimination of AEPTCo Parent’s investments in State Transcos.
(e)Primarily relates to the elimination of Notes Receivable from the State Transcos.
|
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, 2018 |
| State Transcos | | AEPTCo Parent | | Reconciling Adjustments | | AEPTCo Consolidated |
| (in millions) |
Revenues from: | | | | | | | |
External Customers | $ | 46.0 |
| | $ | — |
| | $ | — |
| | $ | 46.0 |
|
Sales to AEP Affiliates | 148.4 |
| | — |
| | — |
| | 148.4 |
|
Other Revenues | — |
| | — |
| | — |
| | — |
|
Total Revenues | $ | 194.4 |
| | $ | — |
| | $ | — |
| | $ | 194.4 |
|
| | | | | | | |
Interest Income | $ | 0.2 |
| | $ | 26.0 |
| | $ | (25.7 | ) | (a) | $ | 0.5 |
|
Interest Expense | 19.8 |
| | 25.7 |
| | (25.7 | ) | (a) | 19.8 |
|
Income Tax Expense | 18.4 |
| | (0.8 | ) | | — |
| | 17.6 |
|
| | | | | | | |
Net Income | $ | 77.1 |
| | $ | 1.0 |
| (b) | $ | — |
| | $ | 78.1 |
|
|
| | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2019 |
| State Transcos | | AEPTCo Parent | | Reconciling Adjustments | | AEPTCo Consolidated |
| (in millions) |
Revenues from: | | | | | | | |
External Customers | $ | 162.1 |
| | $ | — |
| | $ | — |
| | $ | 162.1 |
|
Sales to AEP Affiliates | 608.0 |
| | — |
| | — |
| | 608.0 |
|
Other Revenues | — |
| | — |
| | — |
| | — |
|
Total Revenues | $ | 770.1 |
| | $ | — |
| | $ | — |
| | $ | 770.1 |
|
| | | | | | | |
Interest Income | $ | 0.8 |
| | $ | 89.7 |
| | $ | (88.4 | ) | (a) | $ | 2.1 |
|
Interest Expense | 69.5 |
| | 88.4 |
| | (88.4 | ) | (a) | 69.5 |
|
Income Tax Expense | 90.5 |
| | 0.2 |
| | — |
| | 90.7 |
|
| | | | | | | |
Net Income | $ | 347.1 |
| | $ | 0.8 |
| (b) | $ | — |
| | $ | 347.9 |
|
|
| | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2018 |
| State Transcos | | AEPTCo Parent | | Reconciling Adjustments | | AEPTCo Consolidated |
| (in millions) |
Revenues from: | | | | | | | |
External Customers | $ | 132.3 |
| | $ | — |
| | $ | — |
| | $ | 132.3 |
|
Sales to AEP Affiliates | 453.8 |
| | — |
| | — |
| | 453.8 |
|
Other Revenues | 0.1 |
| | — |
| | — |
| | 0.1 |
|
Total Revenues | $ | 586.2 |
| | $ | — |
| | $ | — |
| | $ | 586.2 |
|
| | | | | | | |
Interest Income | $ | 0.4 |
| | $ | 76.2 |
| | $ | (75.3 | ) | (a) | $ | 1.3 |
|
Interest Expense | 60.7 |
| | 75.3 |
| | (75.3 | ) | (a) | 60.7 |
|
Income Tax Expense | 63.7 |
| | — |
| | — |
| | 63.7 |
|
| | | | | | | |
Net Income | $ | 243.6 |
| | $ | 0.6 |
| (b) | $ | — |
| | $ | 244.2 |
|
|
| | | | | | | | | | | | | | | |
| September 30, 2019 |
| State Transcos | | AEPTCo Parent | | Reconciling Adjustments | | AEPTCo Consolidated |
| (in millions) |
Total Transmission Property | $ | 9,267.4 |
| | $ | — |
| | $ | — |
| | $ | 9,267.4 |
|
Accumulated Depreciation and Amortization | 368.8 |
| | — |
| | — |
| | 368.8 |
|
Total Transmission Property – Net | $ | 8,898.6 |
| | $ | — |
| | $ | — |
| | $ | 8,898.6 |
|
| | | | | | | |
Notes Receivable - Affiliated | $ | — |
| | $ | 3,511.9 |
| | $ | (3,511.9 | ) | (c) | $ | — |
|
| | | | | | | |
Total Assets | $ | 9,363.5 |
| | $ | 3,589.0 |
| (d) | $ | (3,599.8 | ) | (e) | $ | 9,352.7 |
|
| | | | | | | |
Total Long-term Debt | $ | 3,550.0 |
| | $ | 3,511.9 |
| | $ | (3,550.0 | ) | (c) | $ | 3,511.9 |
|
|
| | | | | | | | | | | | | | | |
| December 31, 2018 |
| State Transcos | | AEPTCo Parent | | Reconciling Adjustments | | AEPTCo Consolidated |
| (in millions) |
Total Transmission Property | $ | 8,268.1 |
| | $ | — |
| | $ | — |
| | $ | 8,268.1 |
|
Accumulated Depreciation and Amortization | 271.9 |
| | — |
| | — |
| | 271.9 |
|
Total Transmission Property – Net | $ | 7,996.2 |
| | $ | — |
| | $ | — |
| | $ | 7,996.2 |
|
| | | | | | | |
Notes Receivable - Affiliated | $ | — |
| | $ | 2,823.0 |
| | $ | (2,823.0 | ) | (c) | $ | — |
|
| | | | | | | |
Total Assets | $ | 8,406.8 |
| | $ | 2,857.1 |
| (d) | $ | (2,869.8 | ) | (e) | $ | 8,394.1 |
|
| | | | | | | |
Total Long-term Debt | $ | 2,850.0 |
| | $ | 2,823.0 |
| | $ | (2,850.0 | ) | (c) | $ | 2,823.0 |
|
| |
(a) | Elimination of intercompany interest income/interest expense on affiliated debt arrangement. |
| |
(b) | Includes the elimination of AEPTCo Parent’s equity earnings in the State Transcos. |
| |
(c) | Elimination of intercompany debt. |
| |
(d) | Includes the elimination of AEPTCo Parent’s investments in State Transcos. |
| |
(e) | Primarily relates to the elimination of Notes Receivable from the State Transcos. |
9. DERIVATIVES AND HEDGING
The disclosures in this note apply to all Registrants unless indicated otherwise. For the periods presented, AEPTCo did not have any derivative and hedging activity.
OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS
AEPSC is agent for and transacts on behalf of AEP subsidiaries, including the Registrant Subsidiaries. AEPEP is agent for and transacts on behalf of other AEP subsidiaries.
The Registrants are exposed to certain market risks as major power producers and participants in the electricity, capacity, natural gas, coal and emission allowance markets. These risks include commodity price risks which may be subject to capacity risk, interest rate risk and credit risk. These risks represent the risk of loss that may impact the Registrants due to changes in the underlying market prices or rates. Management utilizes derivative instruments to manage these risks.
STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES
Risk Management Strategies
The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes which focus on seizing market opportunities to create value driven by expected changes in the market prices of the commodities. To accomplish these objectives, the Registrants primarily employ risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance.
The Registrants utilize power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. The Registrants utilize interest rate derivative contracts in order to manage the interest rate exposure associated with the commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. The Registrants also utilize derivative contracts to manage interest rate risk associated with debt financing. For disclosure purposes, these risks are grouped as “Interest Rate.” The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors.
The following tables represent the gross notional volume of the Registrants’ outstanding derivative contracts:
Notional Volume of Derivative Instruments
September 30, 20192020
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Primary Risk Exposure | | Unit of Measure | | AEP | | AEP Texas | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | | (in millions) |
Commodity: | | | | | | | | | | |
| | |
| | |
| | |
|
Power | | MWhs | | 424.3 |
| | — |
| | 94.7 |
| | 37.1 |
| | 7.3 |
| | 21.6 |
| | 6.9 |
|
Natural Gas | | MMBtus | | 53.2 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 12.5 |
|
Heating Oil and Gasoline | | Gallons | | 8.4 |
| | 1.8 |
| | 1.6 |
| | 0.8 |
| | 2.0 |
| | 0.8 |
| | 0.9 |
|
Interest Rate | | USD | | $ | 140.1 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| | | | | | | | | | | | | | | | |
Interest Rate | | USD | | $ | 600.0 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Notional Volume of Derivative Instruments | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Primary Risk Exposure | | Unit of Measure | | AEP | | AEP Texas | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | | (in millions) | | | | | | | | | | | | |
Commodity: | | | | | | | | | | | | | | | | |
Power | | MWhs | | 390.6 | | | 0 | | | 71.7 | | | 28.9 | | | 3.1 | | | 19.8 | | | 5.6 | |
| | | | | | | | | | | | | | | | |
Natural Gas | | MMBtus | | 33.3 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 8.8 | |
Heating Oil and Gasoline | | Gallons | | 8.3 | | | 2.2 | | | 1.3 | | | 0.8 | | | 1.7 | | | 0.9 | | | 1.1 | |
Interest Rate | | USD | | $ | 129.8 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | |
| | | | | | | | | | | | | | | | |
Interest Rate on Long-term Debt | | USD | | $ | 200.0 | | | $ | 0 | | | $ | 200.0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
December 31, 20182019
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Primary Risk Exposure | | Unit of Measure | | AEP | | AEP Texas | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | | (in millions) | | | | | | | | | | | | |
Commodity: | | | | | | | | | | | | | | | | |
Power | | MWhs | | 365.9 | | | 0 | | | 61.0 | | | 26.8 | | | 7.1 | | | 14.9 | | | 4.4 | |
| | | | | | | | | | | | | | | | |
Natural Gas | | MMBtus | | 40.7 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 11.6 | |
Heating Oil and Gasoline | | Gallons | | 6.9 | | | 1.8 | | | 1.1 | | | 0.6 | | | 1.4 | | | 0.7 | | | 0.9 | |
Interest Rate | | USD | | $ | 140.1 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | |
| | | | | | | | | | | | | | | | |
Interest Rate on Long-term Debt | | USD | | $ | 625.0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Primary Risk Exposure | | Unit of Measure | | AEP | | AEP Texas | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | | (in millions) |
Commodity: | | | | | | | | | | |
| | |
| | |
| | |
|
Power | | MWhs | | 371.1 |
| | — |
| | 66.4 |
| | 40.9 |
| | 7.8 |
| | 15.2 |
| | 4.5 |
|
Natural Gas | | MMBtus | | 87.9 |
| | — |
| | 4.0 |
| | 2.3 |
| | — |
| | — |
| | 15.2 |
|
Heating Oil and Gasoline | | Gallons | | 7.4 |
| | 1.5 |
| | 1.4 |
| | 0.7 |
| | 1.8 |
| | 0.7 |
| | 0.8 |
|
Interest Rate | | USD | | $ | 37.7 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| | | | | | | | | | | | | | | | |
Interest Rate | | USD | | $ | 500.0 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
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, supply and demand market data and 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. AEP netted cash collateral received from third-parties against short-term and long-term
risk management assets in the amounts of $0 million and $18$5 million as of September 30, 20192020 and December 31, 2018,2019, respectively. AEP netted cash collateral paid to third-parties against short-term and long-term risk management liabilities in the amounts of $21$9 million and $4$39 million as of September 30, 20192020 and December 31, 2018,2019, respectively. The netted cash collateral from third-parties against short-term and long-term risk management assets and netted cash collateral paid to third-parties against short-term and long-term risk management liabilities were immaterial for the other RegistrantsRegistrant Subsidiaries as of September 30, 20192020 and December 31, 2018.2019.
The following tables represent the gross fair value of the Registrants’ derivative activity on the balance sheets:
AEP
Fair Value of Derivative Instruments
September 30, 20192020
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Risk Management Contracts | | Hedging Contracts | | | | Gross Amounts of Risk Management Assets/ Liabilities Recognized | | Gross Amounts Offset in the Statement of Financial Position (b) | | Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) |
Balance Sheet Location | | Commodity (a) | | Commodity (a) | | Interest Rate (a) | | | | | | |
| | (in millions) | | | | | | | | | | |
Current Risk Management Assets | | $ | 253.7 | | | $ | 24.5 | | | $ | 0.6 | | | $ | 278.8 | | | $ | (163.6) | | | $ | 115.2 | |
Long-term Risk Management Assets | | 283.3 | | | 17.5 | | | 0 | | | 300.8 | | | (57.9) | | | 242.9 | |
Total Assets | | 537.0 | | | 42.0 | | | 0.6 | | | 579.6 | | | (221.5) | | | 358.1 | |
| | | | | | | | | | | | |
Current Risk Management Liabilities | | 183.1 | | | 40.6 | | | 5.3 | | | 229.0 | | | (166.6) | | | 62.4 | |
Long-term Risk Management Liabilities | | 239.0 | | | 57.0 | | | 0 | | | 296.0 | | | (63.6) | | | 232.4 | |
Total Liabilities | | 422.1 | | | 97.6 | | | 5.3 | | | 525.0 | | | (230.2) | | | 294.8 | |
| | | | | | | | | | | | |
Total MTM Derivative Contract Net Assets (Liabilities) | | $ | 114.9 | | | $ | (55.6) | | | $ | (4.7) | | | $ | 54.6 | | | $ | 8.7 | | | $ | 63.3 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Risk Management Contracts | | Hedging Contracts | | Gross Amounts of Risk Management Assets/ Liabilities Recognized | | Gross Amounts Offset in the Statement of Financial Position (b) | | Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) |
Balance Sheet Location | | Commodity (a) | | Commodity (a) | | Interest Rate (a) | | | |
| | (in millions) |
Current Risk Management Assets | | $ | 337.0 |
| | $ | 16.5 |
| | $ | 1.9 |
| | $ | 355.4 |
| | $ | (168.7 | ) | | $ | 186.7 |
|
Long-term Risk Management Assets | | 319.0 |
| | 10.0 |
| | 25.3 |
| | 354.3 |
| | (55.3 | ) | | 299.0 |
|
Total Assets | | 656.0 |
| | 26.5 |
| | 27.2 |
| | 709.7 |
| | (224.0 | ) | | 485.7 |
|
| | | | | | | | | | | | |
Current Risk Management Liabilities | | 213.4 |
| | 36.4 |
| | 0.2 |
| | 250.0 |
| | (174.7 | ) | | 75.3 |
|
Long-term Risk Management Liabilities | | 281.7 |
| | 87.4 |
| | — |
| | 369.1 |
| | (70.5 | ) | | 298.6 |
|
Total Liabilities | | 495.1 |
| | 123.8 |
| | 0.2 |
| | 619.1 |
| | (245.2 | ) | | 373.9 |
|
| | | | | | | | | | | | |
Total MTM Derivative Contract Net Assets (Liabilities) | | $ | 160.9 |
| | $ | (97.3 | ) | | $ | 27.0 |
| | $ | 90.6 |
| | $ | 21.2 |
| | $ | 111.8 |
|
December 31, 20182019
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Risk Management Contracts | | Hedging Contracts | | | | Gross Amounts of Risk Management Assets/ Liabilities Recognized | | Gross Amounts Offset in the Statement of Financial Position (b) | | Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) |
Balance Sheet Location | | Commodity (a) | | Commodity (a) | | Interest Rate (a) | | | | | | |
| | (in millions) | | | | | | | | | | |
Current Risk Management Assets | | $ | 513.9 | | | $ | 11.5 | | | $ | 6.5 | | | $ | 531.9 | | | $ | (359.1) | | | $ | 172.8 | |
Long-term Risk Management Assets | | 290.8 | | | 11.0 | | | 12.6 | | | 314.4 | | | (47.8) | | | 266.6 | |
Total Assets | | 804.7 | | | 22.5 | | | 19.1 | | | 846.3 | | | (406.9) | | | 439.4 | |
| | | | | | | | | | | | |
Current Risk Management Liabilities | | 424.5 | | | 72.3 | | | 0 | | | 496.8 | | | (382.5) | | | 114.3 | |
Long-term Risk Management Liabilities | | 244.5 | | | 75.7 | | | 0 | | | 320.2 | | | (58.4) | | | 261.8 | |
Total Liabilities | | 669.0 | | | 148.0 | | | 0 | | | 817.0 | | | (440.9) | | | 376.1 | |
| | | | | | | | | | | | |
Total MTM Derivative Contract Net Assets (Liabilities) | | $ | 135.7 | | | $ | (125.5) | | | $ | 19.1 | | | $ | 29.3 | | | $ | 34.0 | | | $ | 63.3 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Risk Management Contracts | | Hedging Contracts | | Gross Amounts of Risk Management Assets/ Liabilities Recognized | | Gross Amounts Offset in the Statement of Financial Position (b) | | Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) |
Balance Sheet Location | | Commodity (a) | | Commodity (a) | | Interest Rate (a) | | | |
| | (in millions) |
Current Risk Management Assets | | $ | 397.5 |
| | $ | 28.5 |
| | $ | — |
| | $ | 426.0 |
| | $ | (263.2 | ) | | $ | 162.8 |
|
Long-term Risk Management Assets | | 276.4 |
| | 16.0 |
| | — |
| | 292.4 |
| | (38.4 | ) | | 254.0 |
|
Total Assets | | 673.9 |
| | 44.5 |
| | — |
| | 718.4 |
| | (301.6 | ) | | 416.8 |
|
| | | | | | | | | | | | |
Current Risk Management Liabilities | | 293.8 |
| | 13.2 |
| | 2.0 |
| | 309.0 |
| | (254.0 | ) | | 55.0 |
|
Long-term Risk Management Liabilities | | 225.7 |
| | 56.1 |
| | 15.4 |
| | 297.2 |
| | (33.8 | ) | | 263.4 |
|
Total Liabilities | | 519.5 |
| | 69.3 |
| | 17.4 |
| | 606.2 |
| | (287.8 | ) | | 318.4 |
|
| | | | | | | | | | | | |
Total MTM Derivative Contract Net Assets (Liabilities) | | $ | 154.4 |
| | $ | (24.8 | ) | | $ | (17.4 | ) | | $ | 112.2 |
| | $ | (13.8 | ) | | $ | 98.4 |
|
AEP Texas
Fair Value of Derivative Instruments
September 30, 20192020
| | | | | | | | | | | | | | | | | | | | |
| | Risk Management | | Gross Amounts Offset | | Net Amounts of Assets/Liabilities |
| | Contracts – | | in the Statement of | | Presented in the Statement of |
Balance Sheet Location | | Commodity (a) | | Financial Position (b) | | Financial Position (c) |
| | (in millions) | | | | |
Current Risk Management Assets | | $ | 0 | | | $ | 0 | | | $ | 0 | |
Long-term Risk Management Assets | | 0 | | | 0 | | | 0 | |
Total Assets | | 0 | | | 0 | | | 0 | |
| | | | | | |
Current Risk Management Liabilities | | 0.2 | | | (0.1) | | | 0.1 | |
Long-term Risk Management Liabilities | | 0 | | | 0 | | | 0 | |
Total Liabilities | | 0.2 | | | (0.1) | | | 0.1 | |
| | | | | | |
Total MTM Derivative Contract Net Assets (Liabilities) | | $ | (0.2) | | | $ | 0.1 | | | $ | (0.1) | |
|
| | | | | | | | | | | | |
| | Risk Management | | Gross Amounts Offset | | Net Amounts of Assets/Liabilities |
| | Contracts – | | in the Statement of | | Presented in the Statement of |
Balance Sheet Location | | Commodity (a) | | Financial Position (b) | | Financial Position (c) |
| | (in millions) |
Current Risk Management Assets | | $ | — |
| | $ | — |
| | $ | — |
|
Long-term Risk Management Assets | | — |
| | — |
| | — |
|
Total Assets | | — |
| | — |
| | — |
|
| | | | | | |
Current Risk Management Liabilities | | 0.4 |
| | (0.1 | ) | | 0.3 |
|
Long-term Risk Management Liabilities | | — |
| | 0.1 |
| | 0.1 |
|
Total Liabilities | | 0.4 |
| | — |
| | 0.4 |
|
| | | | | | |
Total MTM Derivative Contract Net Liabilities | | $ | (0.4 | ) | | $ | — |
| | $ | (0.4 | ) |
December 31, 20182019
| | | | | | | | | | | | | | | | | | | | |
| | Risk Management | | Gross Amounts Offset | | Net Amounts of Assets/Liabilities |
| | Contracts – | | in the Statement of | | Presented in the Statement of |
Balance Sheet Location | | Commodity (a) | | Financial Position (b) | | Financial Position (c) |
| | (in millions) | | | | |
Current Risk Management Assets | | $ | 0 | | | $ | 0 | | | $ | 0 | |
Long-term Risk Management Assets | | 0 | | | 0 | | | 0 | |
Total Assets | | 0 | | | 0 | | | 0 | |
| | | | | | |
Current Risk Management Liabilities | | 0 | | | 0 | | | 0 | |
Long-term Risk Management Liabilities | | 0 | | | 0 | | | 0 | |
Total Liabilities | | 0 | | | 0 | | | 0 | |
| | | | | | |
Total MTM Derivative Contract Net Assets | | $ | 0 | | | $ | 0 | | | $ | 0 | |
|
| | | | | | | | | | | | |
| | Risk Management | | Gross Amounts Offset | | Net Amounts of Assets/Liabilities |
| | Contracts – | | in the Statement of | | Presented in the Statement of |
Balance Sheet Location | | Commodity (a) | | Financial Position (b) | | Financial Position (c) |
| | (in millions) |
Current Risk Management Assets | | $ | — |
| | $ | — |
| | $ | — |
|
Long-term Risk Management Assets | | — |
| | — |
| | — |
|
Total Assets | | — |
| | — |
| | — |
|
| | | | | | |
Current Risk Management Liabilities | | 0.7 |
| | (0.5 | ) | | 0.2 |
|
Long-term Risk Management Liabilities | | — |
| | — |
| | — |
|
Total Liabilities | | 0.7 |
| | (0.5 | ) | | 0.2 |
|
| | | | | | |
Total MTM Derivative Contract Net Assets (Liabilities) | | $ | (0.7 | ) | | $ | 0.5 |
| | $ | (0.2 | ) |
APCo
Fair Value of Derivative Instruments
September 30, 20192020
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Risk Management | | Hedging | | Gross Amounts Offset | | Net Amounts of Assets/Liabilities |
| | Contracts – | | Contracts – | | in the Statement of | | Presented in the Statement of |
Balance Sheet Location | | Commodity (a) | | Interest Rate (a) | | Financial Position (b) | | Financial Position (c) |
| | (in millions) | | | | | | |
Current Risk Management Assets | | $ | 49.6 | | | $ | 0.6 | | | $ | (19.5) | | | $ | 30.7 | |
Long-term Risk Management Assets | | 1.6 | | | 0 | | | (1.5) | | | 0.1 | |
Total Assets | | 51.2 | | | 0.6 | | | (21.0) | | | 30.8 | |
| | | | | | | | |
Current Risk Management Liabilities | | 20.7 | | | 5.3 | | | (20.4) | | | 5.6 | |
Long-term Risk Management Liabilities | | 1.8 | | | 0 | | | (1.6) | | | 0.2 | |
Total Liabilities | | 22.5 | | | 5.3 | | | (22.0) | | | 5.8 | |
| | | | | | | | |
Total MTM Derivative Contract Net Assets (Liabilities) | | $ | 28.7 | | | $ | (4.7) | | | $ | 1.0 | | | $ | 25.0 | |
|
| | | | | | | | | | | | |
| | Risk Management | | Gross Amounts Offset | | Net Amounts of Assets/Liabilities |
| | Contracts – | | in the Statement of | | Presented in the Statement of |
Balance Sheet Location | | Commodity (a) | | Financial Position (b) | | Financial Position (c) |
| | (in millions) |
Current Risk Management Assets | | $ | 86.3 |
| | $ | (29.8 | ) | | $ | 56.5 |
|
Long-term Risk Management Assets | | 4.1 |
| | (3.9 | ) | | 0.2 |
|
Total Assets | | 90.4 |
| | (33.7 | ) | | 56.7 |
|
| | | | | | |
Current Risk Management Liabilities | | 32.3 |
| | (31.2 | ) | | 1.1 |
|
Long-term Risk Management Liabilities | | 4.4 |
| | (4.1 | ) | | 0.3 |
|
Total Liabilities | | 36.7 |
| | (35.3 | ) | | 1.4 |
|
| | | | | | |
Total MTM Derivative Contract Net Assets | | $ | 53.7 |
| | $ | 1.6 |
| | $ | 55.3 |
|
December 31, 20182019
| | | | | | | | | | | | | | | | | | | | |
| | Risk Management | | Gross Amounts Offset | | Net Amounts of Assets/Liabilities |
| | Contracts – | | in the Statement of | | Presented in the Statement of |
Balance Sheet Location | | Commodity (a) | | Financial Position (b) | | Financial Position (c) |
| | (in millions) | | | | |
Current Risk Management Assets | | $ | 124.4 | | | $ | (85.0) | | | $ | 39.4 | |
Long-term Risk Management Assets | | 0.9 | | | (0.8) | | | 0.1 | |
Total Assets | | 125.3 | | | (85.8) | | | 39.5 | |
| | | | | | |
Current Risk Management Liabilities | | 86.2 | | | (84.3) | | | 1.9 | |
Long-term Risk Management Liabilities | | 0.7 | | | (0.7) | | | 0 | |
Total Liabilities | | 86.9 | | | (85.0) | | | 1.9 | |
| | | | | | |
Total MTM Derivative Contract Net Assets (Liabilities) | | $ | 38.4 | | | $ | (0.8) | | | $ | 37.6 | |
|
| | | | | | | | | | | | |
| | Risk Management | | Gross Amounts Offset | | Net Amounts of Assets/Liabilities |
| | Contracts – | | in the Statement of | | Presented in the Statement of |
Balance Sheet Location | | Commodity (a) | | Financial Position (b) | | Financial Position (c) |
| | (in millions) |
Current Risk Management Assets | | $ | 114.4 |
| | $ | (57.2 | ) | | $ | 57.2 |
|
Long-term Risk Management Assets | | 3.1 |
| | (2.2 | ) | | 0.9 |
|
Total Assets | | 117.5 |
| | (59.4 | ) | | 58.1 |
|
| | | | | | |
Current Risk Management Liabilities | | 56.7 |
| | (56.3 | ) | | 0.4 |
|
Long-term Risk Management Liabilities | | 2.4 |
| | (2.2 | ) | | 0.2 |
|
Total Liabilities | | 59.1 |
| | (58.5 | ) | | 0.6 |
|
| | | | | | |
Total MTM Derivative Contract Net Assets (Liabilities) | | $ | 58.4 |
| | $ | (0.9 | ) | | $ | 57.5 |
|
180
I&M
Fair Value of Derivative Instruments
September 30, 20192020
| | | | | | | | | | | | | | | | | | | | |
| | Risk Management | | Gross Amounts Offset | | Net Amounts of Assets/Liabilities |
| | Contracts – | | in the Statement of | | Presented in the Statement of |
Balance Sheet Location | | Commodity (a) | | Financial Position (b) | | Financial Position (c) |
| | (in millions) | | | | |
Current Risk Management Assets | | $ | 16.5 | | | $ | (12.4) | | | $ | 4.1 | |
Long-term Risk Management Assets | | 1.0 | | | (1.0) | | | 0 | |
Total Assets | | 17.5 | | | (13.4) | | | 4.1 | |
| | | | | | |
Current Risk Management Liabilities | | 13.1 | | | (12.9) | | | 0.2 | |
Long-term Risk Management Liabilities | | 1.1 | | | (1.0) | | | 0.1 | |
Total Liabilities | | 14.2 | | | (13.9) | | | 0.3 | |
| | | | | | |
Total MTM Derivative Contract Net Assets | | $ | 3.3 | | | $ | 0.5 | | | $ | 3.8 | |
|
| | | | | | | | | | | | |
| | Risk Management | | Gross Amounts Offset | | Net Amounts of Assets/Liabilities |
| | Contracts – | | in the Statement of | | Presented in the Statement of |
Balance Sheet Location | | Commodity (a) | | Financial Position (b) | | Financial Position (c) |
| | (in millions) |
Current Risk Management Assets | | $ | 30.5 |
| | $ | (20.0 | ) | | $ | 10.5 |
|
Long-term Risk Management Assets | | 2.7 |
| | (2.6 | ) | | 0.1 |
|
Total Assets | | 33.2 |
| | (22.6 | ) | | 10.6 |
|
| | | | | | |
Current Risk Management Liabilities | | 21.0 |
| | (20.8 | ) | | 0.2 |
|
Long-term Risk Management Liabilities | | 2.7 |
| | (2.7 | ) | | — |
|
Total Liabilities | | 23.7 |
| | (23.5 | ) | | 0.2 |
|
| | | | | | |
Total MTM Derivative Contract Net Assets | | $ | 9.5 |
| | $ | 0.9 |
| | $ | 10.4 |
|
December 31, 20182019
| | | | | | | | | | | | | | | | | | | | |
| | Risk Management | | Gross Amounts Offset | | Net Amounts of Assets/Liabilities |
| | Contracts – | | in the Statement of | | Presented in the Statement of |
Balance Sheet Location | | Commodity (a) | | Financial Position (b) | | Financial Position (c) |
| | (in millions) | | | | |
Current Risk Management Assets | | $ | 66.9 | | | $ | (57.1) | | | $ | 9.8 | |
Long-term Risk Management Assets | | 0.5 | | | (0.4) | | | 0.1 | |
Total Assets | | 67.4 | | | (57.5) | | | 9.9 | |
| | | | | | |
Current Risk Management Liabilities | | 55.2 | | | (54.7) | | | 0.5 | |
Long-term Risk Management Liabilities | | 0.4 | | | (0.4) | | | 0 | |
Total Liabilities | | 55.6 | | | (55.1) | | | 0.5 | |
| | | | | | |
Total MTM Derivative Contract Net Assets (Liabilities) | | $ | 11.8 | | | $ | (2.4) | | | $ | 9.4 | |
|
| | | | | | | | | | | | |
| | Risk Management | | Gross Amounts Offset | | Net Amounts of Assets/Liabilities |
| | Contracts – | | in the Statement of | | Presented in the Statement of |
Balance Sheet Location | | Commodity (a) | | Financial Position (b) | | Financial Position (c) |
| | (in millions) |
Current Risk Management Assets | | $ | 50.4 |
| | $ | (41.8 | ) | | $ | 8.6 |
|
Long-term Risk Management Assets | | 2.0 |
| | (1.4 | ) | | 0.6 |
|
Total Assets | | 52.4 |
| | (43.2 | ) | | 9.2 |
|
| | | | | | |
Current Risk Management Liabilities | | 41.1 |
| | (40.8 | ) | | 0.3 |
|
Long-term Risk Management Liabilities | | 1.6 |
| | (1.5 | ) | | 0.1 |
|
Total Liabilities | | 42.7 |
| | (42.3 | ) | | 0.4 |
|
| | | | | | |
Total MTM Derivative Contract Net Assets (Liabilities) | | $ | 9.7 |
| | $ | (0.9 | ) | | $ | 8.8 |
|
OPCo
Fair Value of Derivative Instruments
September 30, 20192020
| | | | | | | | | | | | | | | | | | | | |
| | Risk Management | | Gross Amounts Offset | | Net Amounts of Assets/Liabilities |
| | Contracts – | | in the Statement of | | Presented in the Statement of |
Balance Sheet Location | | Commodity (a) | | Financial Position (b) | | Financial Position (c) |
| | (in millions) | | | | |
Current Risk Management Assets | | $ | 0 | | | $ | 0 | | | $ | 0 | |
Long-term Risk Management Assets | | 0 | | | 0 | | | 0 | |
Total Assets | | 0 | | | 0 | | | 0 | |
| | | | | | |
Current Risk Management Liabilities | | 8.3 | | | (0.1) | | | 8.2 | |
Long-term Risk Management Liabilities | | 105.1 | | | 0 | | | 105.1 | |
Total Liabilities | | 113.4 | | | (0.1) | | | 113.3 | |
| | | | | | |
Total MTM Derivative Contract Net Assets (Liabilities) | | $ | (113.4) | | | $ | 0.1 | | | $ | (113.3) | |
|
| | | | | | | | | | | | |
| | Risk Management | | Gross Amounts Offset | | Net Amounts of Assets/Liabilities |
| | Contracts – | | in the Statement of | | Presented in the Statement of |
Balance Sheet Location | | Commodity (a) | | Financial Position (b) | | Financial Position (c) |
| | (in millions) |
Current Risk Management Assets | | $ | — |
| | $ | — |
| | $ | — |
|
Long-term Risk Management Assets | | — |
| | — |
| | — |
|
Total Assets | | — |
| | — |
| | — |
|
| | | | | | |
Current Risk Management Liabilities | | 7.2 |
| | — |
| | 7.2 |
|
Long-term Risk Management Liabilities | | 105.7 |
| | — |
| | 105.7 |
|
Total Liabilities | | 112.9 |
| | — |
| | 112.9 |
|
| | | | | | |
Total MTM Derivative Contract Net Liabilities | | $ | (112.9 | ) | | $ | — |
| | $ | (112.9 | ) |
December 31, 20182019
| | | | | | | | | | | | | | | | | | | | |
| | Risk Management | | Gross Amounts Offset | | Net Amounts of Assets/Liabilities |
| | Contracts – | | in the Statement of | | Presented in the Statement of |
Balance Sheet Location | | Commodity (a) | | Financial Position (b) | | Financial Position (c) |
| | (in millions) | | | | |
Current Risk Management Assets | | $ | 0 | | | $ | 0 | | | $ | 0 | |
Long-term Risk Management Assets | | 0 | | | 0 | | | 0 | |
Total Assets | | 0 | | | 0 | | | 0 | |
| | | | | | |
Current Risk Management Liabilities | | 7.3 | | | 0 | | | 7.3 | |
Long-term Risk Management Liabilities | | 96.3 | | | 0 | | | 96.3 | |
Total Liabilities | | 103.6 | | | 0 | | | 103.6 | |
| | | | | | |
Total MTM Derivative Contract Net Liabilities | | $ | (103.6) | | | $ | 0 | | | $ | (103.6) | |
|
| | | | | | | | | | | | |
| | Risk Management | | Gross Amounts Offset | | Net Amounts of Assets/Liabilities |
| | Contracts – | | in the Statement of | | Presented in the Statement of |
Balance Sheet Location | | Commodity (a) | | Financial Position (b) | | Financial Position (c) |
| | (in millions) |
Current Risk Management Assets | | $ | — |
| | $ | — |
| | $ | — |
|
Long-term Risk Management Assets | | — |
| | — |
| | — |
|
Total Assets | | — |
| | — |
| | — |
|
| | | | | | |
Current Risk Management Liabilities | | 6.4 |
| | (0.6 | ) | | 5.8 |
|
Long-term Risk Management Liabilities | | 93.8 |
| | — |
| | 93.8 |
|
Total Liabilities | | 100.2 |
| | (0.6 | ) | | 99.6 |
|
| | | | | | |
Total MTM Derivative Contract Net Assets (Liabilities) | | $ | (100.2 | ) | | $ | 0.6 |
| | $ | (99.6 | ) |
181
PSO
Fair Value of Derivative Instruments
September 30, 20192020
| | | | | | | | | | | | | | | | | | | | |
| | Risk Management | | Gross Amounts Offset | | Net Amounts of Assets/Liabilities |
| | Contracts – | | in the Statement of | | Presented in the Statement of |
Balance Sheet Location | | Commodity (a) | | Financial Position (b) | | Financial Position (c) |
| | (in millions) | | | | |
Current Risk Management Assets | | $ | 16.6 | | | $ | 0 | | | $ | 16.6 | |
Long-term Risk Management Assets | | 0 | | | 0 | | | 0 | |
Total Assets | | 16.6 | | | 0 | | | 16.6 | |
| | | | | | |
Current Risk Management Liabilities | | 0.6 | | | (0.1) | | | 0.5 | |
Long-term Risk Management Liabilities | | 0 | | | 0 | | | 0 | |
Total Liabilities | | 0.6 | | | (0.1) | | | 0.5 | |
| | | | | | |
Total MTM Derivative Contract Net Assets | | $ | 16.0 | | | $ | 0.1 | | | $ | 16.1 | |
|
| | | | | | | | | | | | |
| | Risk Management | | Gross Amounts Offset | | Net Amounts of Assets/Liabilities |
| | Contracts – | | in the Statement of | | Presented in the Statement of |
Balance Sheet Location | | Commodity (a) | | Financial Position (b) | | Financial Position (c) |
| | (in millions) |
Current Risk Management Assets | | $ | 21.9 |
| | $ | (0.2 | ) | | $ | 21.7 |
|
Long-term Risk Management Assets | | — |
| | — |
| | — |
|
Total Assets | | 21.9 |
| | (0.2 | ) | | 21.7 |
|
| | | | | | |
Current Risk Management Liabilities | | 0.5 |
| | (0.2 | ) | | 0.3 |
|
Long-term Risk Management Liabilities | | — |
| | — |
| | — |
|
Total Liabilities | | 0.5 |
| | (0.2 | ) | | 0.3 |
|
| | | | | | |
Total MTM Derivative Contract Net Assets | | $ | 21.4 |
| | $ | — |
| | $ | 21.4 |
|
December 31, 20182019
| | | | | | | | | | | | | | | | | | | | |
| | Risk Management | | Gross Amounts Offset | | Net Amounts of Assets/Liabilities |
| | Contracts – | | in the Statement of | | Presented in the Statement of |
Balance Sheet Location | | Commodity (a) | | Financial Position (b) | | Financial Position (c) |
| | (in millions) | | | | |
Current Risk Management Assets | | $ | 16.3 | | | $ | (0.5) | | | $ | 15.8 | |
Long-term Risk Management Assets | | 0 | | | 0 | | | 0 | |
Total Assets | | 16.3 | | | (0.5) | | | 15.8 | |
| | | | | | |
Current Risk Management Liabilities | | 0.5 | | | (0.5) | | | 0 | |
Long-term Risk Management Liabilities | | 0 | | | 0 | | | 0 | |
Total Liabilities | | 0.5 | | | (0.5) | | | 0 | |
| | | | | | |
Total MTM Derivative Contract Net Assets | | $ | 15.8 | | | $ | 0 | | | $ | 15.8 | |
|
| | | | | | | | | | | | |
| | Risk Management | | Gross Amounts Offset | | Net Amounts of Assets/Liabilities |
| | Contracts – | | in the Statement of | | Presented in the Statement of |
Balance Sheet Location | | Commodity (a) | | Financial Position (b) | | Financial Position (c) |
| | (in millions) |
Current Risk Management Assets | | $ | 10.9 |
| | $ | (0.5 | ) | | $ | 10.4 |
|
Long-term Risk Management Assets | | — |
| | — |
| | — |
|
Total Assets | | 10.9 |
| | (0.5 | ) | | 10.4 |
|
| | | | | | |
Current Risk Management Liabilities | | 1.7 |
| | (0.7 | ) | | 1.0 |
|
Long-term Risk Management Liabilities | | — |
| | — |
| | — |
|
Total Liabilities | | 1.7 |
| | (0.7 | ) | | 1.0 |
|
| | | | | | |
Total MTM Derivative Contract Net Assets | | $ | 9.2 |
| | $ | 0.2 |
| | $ | 9.4 |
|
SWEPCo
Fair Value of Derivative Instruments
September 30, 20192020
| | | | | | | | | | | | | | | | | | | | |
| | Risk Management | | Gross Amounts Offset | | Net Amounts of Assets/Liabilities |
| | Contracts – | | in the Statement of | | Presented in the Statement of |
Balance Sheet Location | | Commodity (a) | | Financial Position (b) | | Financial Position (c) |
| | (in millions) | | | | |
Current Risk Management Assets | | $ | 4.5 | | | $ | 0 | | | $ | 4.5 | |
Long-term Risk Management Assets | | 0 | | | 0 | | | 0 | |
Total Assets | | 4.5 | | | 0 | | | 4.5 | |
| | | | | | |
Current Risk Management Liabilities | | 0.2 | | | (0.1) | | | 0.1 | |
Long-term Risk Management Liabilities | | 0.7 | | | 0 | | | 0.7 | |
Total Liabilities | | 0.9 | | | (0.1) | | | 0.8 | |
| | | | | | |
Total MTM Derivative Contract Net Assets | | $ | 3.6 | | | $ | 0.1 | | | $ | 3.7 | |
|
| | | | | | | | | | | | |
| | Risk Management | | Gross Amounts Offset | | Net Amounts of Assets/Liabilities |
| | Contracts – | | in the Statement of | | Presented in the Statement of |
Balance Sheet Location | | Commodity (a) | | Financial Position (b) | | Financial Position (c) |
| | (in millions) |
Current Risk Management Assets | | $ | 9.8 |
| | $ | (0.4 | ) | | $ | 9.4 |
|
Long-term Risk Management Assets | | — |
| | — |
| | — |
|
Total Assets | | 9.8 |
| | (0.4 | ) | | 9.4 |
|
| | | | | | |
Current Risk Management Liabilities | | 2.1 |
| | (0.4 | ) | | 1.7 |
|
Long-term Risk Management Liabilities | | 3.0 |
| | — |
| | 3.0 |
|
Total Liabilities | | 5.1 |
| | (0.4 | ) | | 4.7 |
|
| | | | | | |
Total MTM Derivative Contract Net Assets | | $ | 4.7 |
| | $ | — |
| | $ | 4.7 |
|
December 31, 20182019
| | | | | | | | | | | | | | | | | | | | |
| | Risk Management | | Gross Amounts Offset | | Net Amounts of Assets/Liabilities |
| | Contracts – | | in the Statement of | | Presented in the Statement of |
Balance Sheet Location | | Commodity (a) | | Financial Position (b) | | Financial Position (c) |
| | (in millions) | | | | |
Current Risk Management Assets | | $ | 6.5 | | | $ | (0.1) | | | $ | 6.4 | |
Long-term Risk Management Assets | | 0 | | | 0 | | | 0 | |
Total Assets | | 6.5 | | | (0.1) | | | 6.4 | |
| | | | | | |
Current Risk Management Liabilities | | 2.0 | | | (0.1) | | | 1.9 | |
Long-term Risk Management Liabilities | | 3.1 | | | 0 | | | 3.1 | |
Total Liabilities | | 5.1 | | | (0.1) | | | 5.0 | |
| | | | | | |
Total MTM Derivative Contract Net Assets | | $ | 1.4 | | | $ | 0 | | | $ | 1.4 | |
(a)Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.”
(b)Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.”
(c)All derivative contracts subject to a master netting arrangement or similar agreement are offset in the statement of financial position.
|
| | | | | | | | | | | | |
| | Risk Management | | Gross Amounts Offset | | Net Amounts of Assets/Liabilities |
| | Contracts – | | in the Statement of | | Presented in the Statement of |
Balance Sheet Location | | Commodity (a) | | Financial Position (b) | | Financial Position (c) |
| | (in millions) |
Current Risk Management Assets | | $ | 5.6 |
| | $ | (0.8 | ) | | $ | 4.8 |
|
Long-term Risk Management Assets | | — |
| | — |
| | — |
|
Total Assets | | 5.6 |
| | (0.8 | ) | | 4.8 |
|
| | | | | | |
Current Risk Management Liabilities | | 1.5 |
| | (1.1 | ) | | 0.4 |
|
Long-term Risk Management Liabilities | | 2.2 |
| | — |
| | 2.2 |
|
Total Liabilities | | 3.7 |
| | (1.1 | ) | | 2.6 |
|
| | | | | | |
Total MTM Derivative Contract Net Assets | | $ | 1.9 |
| | $ | 0.3 |
| | $ | 2.2 |
|
| |
(a) | Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” |
| |
(b) | Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” |
| |
(c) | All derivative contracts subject to a master netting arrangement or similar agreement are offset in the statement of financial position. |
The tables below present the Registrants’ activity of derivative risk management contracts:
Amount of Gain (Loss) Recognized on
Risk Management Contracts
Three Months Ended September 30, 20192020
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Location of Gain (Loss) | | AEP | | AEP Texas | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in millions) | | | | | | | | | | | | |
Vertically Integrated Utilities Revenues | | $ | 0.5 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | |
| | | | | | | | | | | | | | |
Generation & Marketing Revenues | | 11.5 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
Electric Generation, Transmission and Distribution Revenues | | 0 | | | 0 | | | 0.3 | | | 0 | | | 0 | | | 0 | | | 0 | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
Purchased Electricity for Resale | | 0.3 | | | 0 | | | 0.2 | | | 0.1 | | | 0 | | | 0 | | | 0 | |
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 | | | (0.1) | |
Regulatory Assets (a) | | 7.9 | | | 0.2 | | | 0.4 | | | 0.2 | | | 4.4 | | | (0.4) | | | 2.9 | |
Regulatory Liabilities (a) | | 17.0 | | | 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 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Location of Gain (Loss) | | AEP | | AEP Texas | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in millions) |
Vertically Integrated Utilities Revenues | | $ | 0.5 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Generation & Marketing Revenues | | 21.0 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Electric Generation, Transmission and Distribution Revenues | | — |
| | — |
| | 0.2 |
| | 0.2 |
| | — |
| | — |
| �� | — |
|
Purchased Electricity for Resale | | 0.4 |
| | — |
| | 0.3 |
| | — |
| | — |
| | — |
| | — |
|
Other Operation | | (0.1 | ) | | — |
| | (0.1 | ) | | (0.1 | ) | | (0.1 | ) | | (0.1 | ) | | — |
|
Maintenance | | (0.2 | ) | | — |
| | — |
| | (0.1 | ) | | — |
| | — |
| | — |
|
Regulatory Assets (a) | | (4.8 | ) | | (0.2 | ) | | 0.2 |
| | — |
| | (2.6 | ) | | (0.1 | ) | | (1.6 | ) |
Regulatory Liabilities (a) | | 26.3 |
| | — |
| | 10.0 |
| | 3.2 |
| | — |
| | 4.3 |
| | 4.5 |
|
Total Gain (Loss) on Risk Management Contracts | | $ | 43.1 |
| | $ | (0.2 | ) | | $ | 10.6 |
| | $ | 3.2 |
| | $ | (2.7 | ) | | $ | 4.1 |
| | $ | 2.9 |
|
Amount of Gain (Loss) Recognized on
Risk Management Contracts
Three Months Ended September 30, 20182019
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Location of Gain (Loss) | | AEP | | AEP Texas | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in millions) | | | | | | | | | | | | |
Vertically Integrated Utilities Revenues | | $ | 0.5 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | |
| | | | | | | | | | | | | | |
Generation & Marketing Revenues | | 21.0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
Electric Generation, Transmission and Distribution Revenues | | 0 | | | 0 | | | 0.2 | | | 0.2 | | | 0 | | | 0 | | | 0 | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
Purchased Electricity for Resale | | 0.4 | | | 0 | | | 0.3 | | | 0 | | | 0 | | | 0 | | | 0 | |
Other Operation | | (0.1) | | | 0 | | | (0.1) | | | (0.1) | | | (0.1) | | | (0.1) | | | 0 | |
Maintenance | | (0.2) | | | 0 | | | 0 | | | (0.1) | | | 0 | | | 0 | | | 0 | |
Regulatory Assets (a) | | (4.8) | | | (0.2) | | | 0.2 | | | 0 | | | (2.6) | | | (0.1) | | | (1.6) | |
Regulatory Liabilities (a) | | 26.3 | | | 0 | | | 10.0 | | | 3.2 | | | 0 | | | 4.3 | | | 4.5 | |
Total Gain (Loss) on Risk Management Contracts | | $ | 43.1 | | | $ | (0.2) | | | $ | 10.6 | | | $ | 3.2 | | | $ | (2.7) | | | $ | 4.1 | | | $ | 2.9 | |
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 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | |
| | | | | | | | | | | | | | |
Generation & Marketing Revenues | | 11.1 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
Electric Generation, Transmission and Distribution Revenues | | 0 | | | 0 | | | 0.4 | | | 0.1 | | | 0 | | | 0 | | | 0.1 | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
Purchased Electricity for Resale | | 1.2 | | | 0 | | | 1.0 | | | 0.1 | | | 0 | | | 0 | | | 0 | |
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 | | | 0 | | | 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 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Location of Gain (Loss) | | AEP | | AEP Texas | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in millions) |
Vertically Integrated Utilities Revenues | | $ | (0.7 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Generation & Marketing Revenues | | 19.3 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Electric Generation, Transmission and Distribution Revenues | | — |
| | — |
| | (0.5 | ) | | (0.1 | ) | | — |
| | — |
| | — |
|
Purchased Electricity for Resale | | 0.3 |
| | — |
| | 0.3 |
| | — |
| | — |
| | — |
| | — |
|
Other Operation | | 0.5 |
| | 0.1 |
| | 0.1 |
| | 0.1 |
| | 0.1 |
| | 0.1 |
| | 0.1 |
|
Maintenance | | 0.6 |
| | 0.1 |
| | 0.1 |
| | 0.1 |
| | 0.1 |
| | 0.1 |
| | 0.1 |
|
Regulatory Assets (a) | | (14.0 | ) | | — |
| | — |
| | (3.5 | ) | | (9.3 | ) | | (0.6 | ) | | (0.6 | ) |
Regulatory Liabilities (a) | | 33.8 |
| | — |
| | 24.0 |
| | — |
| | — |
| | 3.9 |
| | 1.5 |
|
Total Gain (Loss) on Risk Management Contracts | | $ | 39.8 |
| | $ | 0.2 |
| | $ | 24.0 |
| | $ | (3.4 | ) | | $ | (9.1 | ) | | $ | 3.5 |
| | $ | 1.1 |
|
Amount of Gain (Loss) Recognized on
Risk Management Contracts
Nine Months Ended September 30, 2019
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Location of Gain (Loss) | | AEP | | AEP Texas | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in millions) | | | | | | | | | | | | |
Vertically Integrated Utilities Revenues | | $ | 1.0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | |
| | | | | | | | | | | | | | |
Generation & Marketing Revenues | | 27.2 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
Electric Generation, Transmission and Distribution Revenues | | 0 | | | 0 | | | 0.2 | | | 0.5 | | | 0 | | | 0 | | | 0.1 | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
Purchased Electricity for Resale | | 1.6 | | | 0 | | | 1.4 | | | 0.1 | | | 0 | | | 0 | | | 0 | |
Other Operation | | (0.6) | | | (0.1) | | | (0.1) | | | (0.1) | | | (0.2) | | | (0.1) | | | (0.1) | |
Maintenance | | (0.6) | | | (0.1) | | | (0.1) | | | (0.1) | | | (0.1) | | | 0 | | | (0.1) | |
Regulatory Assets (a) | | (19.4) | | | 0.3 | | | 0.4 | | | 0.2 | | | (19.8) | | | 0.9 | | | (0.4) | |
Regulatory Liabilities (a) | | 64.5 | | | 0 | | | (5.3) | | | 17.2 | | | 0 | | | 26.6 | | | 22.9 | |
Total Gain (Loss) on Risk Management Contracts | | $ | 73.7 | | | $ | 0.1 | | | $ | (3.5) | | | $ | 17.8 | | | $ | (20.1) | | | $ | 27.4 | | | $ | 22.4 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Location of Gain (Loss) | | AEP | | AEP Texas | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in millions) |
Vertically Integrated Utilities Revenues | | $ | 1.0 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Generation & Marketing Revenues | | 27.2 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Electric Generation, Transmission and Distribution Revenues | | — |
| | — |
| | 0.2 |
| | 0.5 |
| | — |
| | — |
| | 0.1 |
|
Purchased Electricity for Resale | | 1.6 |
| | — |
| | 1.4 |
| | 0.1 |
| | — |
| | — |
| | — |
|
Other Operation | | (0.6 | ) | | (0.1 | ) | | (0.1 | ) | | (0.1 | ) | | (0.2 | ) | | (0.1 | ) | | (0.1 | ) |
Maintenance | | (0.6 | ) | | (0.1 | ) | | (0.1 | ) | | (0.1 | ) | | (0.1 | ) | | — |
| | (0.1 | ) |
Regulatory Assets (a) | | (19.4 | ) | | 0.3 |
| | 0.4 |
| | 0.2 |
| | (19.8 | ) | | 0.9 |
| | (0.4 | ) |
Regulatory Liabilities (a) | | 64.5 |
| | — |
| | (5.3 | ) | | 17.2 |
| | — |
| | 26.6 |
| | 22.9 |
|
Total Gain (Loss) on Risk Management Contracts | | $ | 73.7 |
| | $ | 0.1 |
| | $ | (3.5 | ) | | $ | 17.8 |
| | $ | (20.1 | ) | | $ | 27.4 |
| | $ | 22.4 |
|
Amount of Gain (Loss) Recognized on
Risk Management Contracts
Nine Months Ended September 30, 2018
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Location of Gain (Loss) | | AEP | | AEP Texas | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in millions) |
Vertically Integrated Utilities Revenues | | $ | (9.4 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Generation & Marketing Revenues | | 31.7 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Electric Generation, Transmission and Distribution Revenues | | — |
| | — |
| | (1.3 | ) | | (7.8 | ) | | — |
| | — |
| | 0.1 |
|
Purchased Electricity for Resale | | 8.3 |
| | — |
| | 7.3 |
| | 0.8 |
| | — |
| | — |
| | — |
|
Other Operation | | 1.3 |
| | 0.3 |
| | 0.2 |
| | 0.2 |
| | 0.3 |
| | 0.2 |
| | 0.2 |
|
Maintenance | | 1.5 |
| | 0.3 |
| | 0.3 |
| | 0.2 |
| | 0.3 |
| | 0.2 |
| | 0.2 |
|
Regulatory Assets (a) | | 29.2 |
| | — |
| | — |
| | (0.3 | ) | | 31.8 |
| | (0.6 | ) | | (1.7 | ) |
Regulatory Liabilities (a) | | 206.2 |
| | — |
| | 127.3 |
| | 11.7 |
| | 0.6 |
| | 34.8 |
| | 7.6 |
|
Total Gain on Risk Management Contracts | | $ | 268.8 |
| | $ | 0.6 |
| | $ | 133.8 |
| | $ | 4.8 |
| | $ | 33.0 |
| | $ | 34.6 |
| | $ | 6.4 |
|
(a)Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.
| |
(a) | Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets. |
Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the statements of income on an accrual basis.
The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge.
For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the statements of income as that of the associated risk. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.”
Accounting for Fair Value Hedging Strategies (Applies to AEP)
For fair value hedges (i.e. hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof attributable to a particular risk), the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item associated with the hedged risk impacts net income during the period of change.
AEP records realized and unrealized gains or losses on interest rate swaps that are designated and qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the statements of income.
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, 2020 | | December 31, 2019 | | September 30, 2020 | | December 31, 2019 |
| | (in millions) | | | | | | |
Long-term Debt (a) (b) | | $ | (551.9) | | | $ | (510.8) | | | $ | (55.2) | | | $ | (14.5) | |
|
| | | | | | | | | | | | | | | | |
| | Carrying Amount of the Hedged Assets/(Liabilities) | | Cumulative Amount of Fair Value Hedging Adjustment Included in the Carrying Amount of the Hedged Assets/(Liabilities) |
| | September 30, 2019 | | December 31, 2018 | | September 30, 2019 | | December 31, 2018 |
| | (in millions) |
Long-term Debt (a) | | $ | (521.2 | ) | | $ | (478.3 | ) | | $ | (25.1 | ) | | $ | 17.4 |
|
(a)Amounts included on the balance sheets within Long-term Debt Due within One Year and Long-term Debt, respectively.
(b)Amounts include $(55) million and $0 as of September 30, 2020 and December 31, 2019, respectively, for the fair value hedge adjustment of hedged debt obligations for which hedge accounting has been discontinued.
| |
(a) | Amounts included on the balance sheets within Long-term Debt Due within One Year and Long-term Debt, respectively. |
The pretax effects of fair value hedge accounting on income were as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | | | Nine Months Ended September 30, | | |
| 2020 | | 2019 | | 2020 | | 2019 |
| (in millions) | | | | | | |
Gain (Loss) on Interest Rate Contracts: | | | | | | | |
Gain on Fair Value Hedging Instruments (a) | $ | 0 | | | $ | 13.2 | | | $ | 42.6 | | | $ | 42.5 | |
Loss on Fair Value Portion of Long-term Debt (a) | 0 | | | (13.2) | | | (42.6) | | | (42.5) | |
|
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2019 | | 2018 | | 2019 | | 2018 |
| (in millions) |
Gain (Loss) on Interest Rate Contracts: | | | | | | | |
Gain (Loss) on Fair Value Hedging Instruments (a) | $ | 13.2 |
| | $ | (6.3 | ) | | $ | 42.5 |
| | $ | (28.1 | ) |
Gain (Loss) on Fair Value Portion of Long-term Debt (a) | (13.2 | ) | | 6.3 |
| | (42.5 | ) | | 28.1 |
|
(a)Gain (Loss) is included in Interest Expense on the statements of income.
| |
(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 statement of cash flows. Subsequent to the discontinuation of hedge accounting, the remaining adjustment to the carrying amount of the hedged item of $57 million will be amortized on a straight line basis through November 2027 in Interest Expense on the statements of income.
Accounting for Cash Flow Hedging Strategies
For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrants initially report the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the balance sheets until the period the hedged item affects net income.
Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Total Revenues or Purchased Electricity for Resale on the statements of income or in Regulatory Assets or Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged. During the three and nine months ended September 30, 20192020 and 2018,2019, AEP applied cash flow hedging to outstanding power derivatives. During the three and nine months ended September 30, 20192020 and 2018,2019, the Registrant Subsidiaries did not apply cash flow hedging to outstanding power derivatives.
The Registrants reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Interest Expense on the statements of income in those periods in which hedged interest payments occur. During the three and nine months ended September 30, 20192020, AEP and APCo applied cash flow hedging to outstanding interest rate derivatives and the other Registrant Subsidiaries did not. During the three and nine months ended September 30, 20182019, AEP and SWEPCo 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, 2020 | | | | December 31, 2019 | | |
| | Commodity | | Interest Rate | | Commodity | | Interest Rate |
| | (in millions) | | | | | | |
AOCI Gain (Loss) Net of Tax | | $ | (45.1) | | | $ | (52.3) | | | $ | (103.5) | | | $ | (11.5) | |
Portion Expected to be Reclassed to Net Income During the Next Twelve Months | | (13.9) | | | (5.3) | | | (51.7) | | | (2.1) | |
|
| | | | | | | | | | | | | | | | |
| | September 30, 2019 | | December 31, 2018 |
| | Commodity | | Interest Rate | | Commodity | | Interest Rate |
| | (in millions) |
AOCI Gain (Loss) Net of Tax | | $ | (82.2 | ) | | $ | (16.7 | ) | (a) | $ | (23.0 | ) | | $ | (12.6 | ) |
Portion Expected to be Reclassed to Net Income During the Next Twelve Months | | (24.2 | ) | | (3.7 | ) | | 10.4 |
| | (1.1 | ) |
| |
(a) | Includes $6 million related to AEP's investment in joint venture wind farms acquired as part of the purchase of Sempra Renewables LLC. See “Sempra Renewables LLC” section of Note 14 for additional information. |
As of September 30, 20192020 the maximum length of time that AEP is hedging its exposure to variability in future cash flows related to forecasted transactions is 123126 months and 135123 months for commodity and interest rate hedges, respectively.
Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | September 30, 2020 | | | | December 31, 2019 | | |
| | Interest Rate | | | | | | |
| | | | Expected to be | | | | Expected to be |
| | | | Reclassified to | | | | Reclassified to |
| | | | Net Income During | | | | Net Income During |
| | AOCI Gain (Loss) | | the Next | | AOCI Gain (Loss) | | the Next |
Company | | Net of Tax | | Twelve Months | | Net of Tax | | Twelve Months |
| | (in millions) | | | | | | |
AEP Texas | | $ | (2.6) | | | $ | (1.1) | | | $ | (3.4) | | | $ | (1.1) | |
APCo | | (3.5) | | | 0.6 | | | 0.9 | | | 0.9 | |
I&M | | (8.7) | | | (1.6) | | | (9.9) | | | (1.6) | |
| | | | | | | | |
PSO | | 0.3 | | | 0.3 | | | 1.1 | | | 1.0 | |
SWEPCo | | (0.7) | | | (1.5) | | | (1.8) | | | (1.5) | |
|
| | | | | | | | | | | | | | | | |
| | September 30, 2019 | | December 31, 2018 |
| | Interest Rate |
| | | | Expected to be | | | | Expected to be |
| | | | Reclassified to | | | | Reclassified to |
| | | | Net Income During | | | | Net Income During |
| | AOCI Gain (Loss) | | the Next | | AOCI Gain (Loss) | | the Next |
Company | | Net of Tax | | Twelve Months | | Net of Tax | | Twelve Months |
| | (in millions) |
AEP Texas | | $ | (3.6 | ) | | $ | (1.1 | ) | | $ | (4.4 | ) | | $ | (1.1 | ) |
APCo | | 1.1 |
| | 0.9 |
| | 1.8 |
| | 0.9 |
|
I&M | | (10.3 | ) | | (1.6 | ) | | (11.5 | ) | | (1.6 | ) |
OPCo | | — |
| | — |
| | 1.0 |
| | 1.0 |
|
PSO | | 1.4 |
| | 1.0 |
| | 2.1 |
| | 1.0 |
|
SWEPCo | | (2.2 | ) | | (1.5 | ) | | (3.3 | ) | | (1.5 | ) |
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 Events
Credit Downgrade Triggers (Applies to AEP, APCo, I&M, PSO and SWEPCo)
A limited number of derivative contracts include collateral triggering events, which include a requirement to maintain certain credit ratings. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering events in contracts. The Registrants have not experienced a downgrade below a specified credit rating threshold that would require the posting of additional collateral. The Registrants had no derivative contracts with collateral triggering events in a net liability position as of September 30, 20192020 and December 31, 2018,2019, respectively.
Cross-Default Triggers (Applies to AEP, APCo, I&M and SWEPCo)
In addition, a majority of non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third-party obligation that is $50 million or greater. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-default provisions in the contracts. The following tables represent: (a) the fair value of these derivative liabilities subject to cross-default provisions prior to consideration of contractual netting arrangements, (b) the amount that the exposure has been reduced by cash collateral posted and (c) if a cross-default provision would have been triggered, the settlement amount that would be required after considering contractual netting arrangements:
| | | | | | | | | | | | | | | | | | | | |
| | September 30, 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 | | $ | 189.7 | | | $ | 0 | | | $ | 162.3 | |
APCo | | 5.7 | | | 0 | | | 5.3 | |
I&M | | 0.3 | | | 0 | | | 0 | |
| | | | | | |
| | | | | | |
SWEPCo | | 0.9 | | | 0 | | | 0.9 | |
| | | | | | | | | | | | | | | | | | | | |
| | December 31, 2019 | | | | |
| | 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 | | $ | 267.3 | | | $ | 3.7 | | | $ | 246.7 | |
APCo | | 2.3 | | | 0 | | | 0.4 | |
I&M | | 1.3 | | | 0 | | | 0.2 | |
SWEPCo | | 5.1 | | | 0 | | | 5.1 | |
| | | | | | |
| | | | | | |
| | | | | | |
|
| | | | | | | | | | | | |
| | September 30, 2019 |
| | 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 | | $ | 261.0 |
| | $ | 3.4 |
| | $ | 230.7 |
|
APCo | | 3.9 |
| | — |
| | 0.2 |
|
I&M | | 2.3 |
| | — |
| | 0.1 |
|
SWEPCo | | 4.7 |
| | — |
| | 2.8 |
|
|
| | | | | | | | | | | | |
| | December 31, 2018 |
| | 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 | | $ | 225.5 |
| | $ | 1.8 |
| | $ | 181.0 |
|
APCo | | 0.9 |
| | — |
| | — |
|
I&M | | 0.5 |
| | — |
| | — |
|
SWEPCo | | 2.3 |
| | — |
| | 2.3 |
|
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. The trustee uses multiple pricing vendors for the assets held in the trusts.
Assets in the nuclear trusts, cash and cash equivalents, other temporary investments and restricted cash for securitized funding are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and equity securities. They are valued based on observable inputs, primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities 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, 2020 | | | | December 31, 2019 | | |
Company | | Book Value | | Fair Value | | Book Value | | Fair Value |
| | (in millions) | | | | | | |
AEP (a) | | $ | 30,067.1 | | | $ | 35,603.2 | | | $ | 26,725.5 | | | $ | 30,172.0 | |
AEP Texas | | 4,854.7 | | | 5,590.0 | | | 4,558.4 | | | 4,981.5 | |
AEPTCo | | 3,947.9 | | | 4,859.5 | | | 3,427.3 | | | 3,868.0 | |
APCo | | 4,833.3 | | | 6,167.6 | | | 4,363.8 | | | 5,253.1 | |
I&M | | 2,981.9 | | | 3,637.4 | | | 3,050.2 | | | 3,453.8 | |
OPCo | | 2,429.9 | | | 3,137.5 | | | 2,082.0 | | | 2,554.3 | |
PSO | | 1,373.7 | | | 1,694.9 | | | 1,386.2 | | | 1,603.3 | |
SWEPCo | | 2,637.3 | | | 3,119.2 | | | 2,655.6 | | | 2,927.9 | |
|
| | | | | | | | | | | | | | | | |
| | September 30, 2019 | | December 31, 2018 |
Company | | Book Value | | Fair Value | | Book Value | | Fair Value |
| | (in millions) |
AEP (a) | | $ | 25,881.2 |
| | $ | 29,729.1 |
| | $ | 23,346.7 |
| | $ | 24,093.9 |
|
AEP Texas | | 4,146.5 |
| | 4,631.5 |
| | 3,881.3 |
| | 3,964.6 |
|
AEPTCo | | 3,511.9 |
| | 3,984.9 |
| | 2,823.0 |
| | 2,782.4 |
|
APCo | | 4,362.9 |
| | 5,370.2 |
| | 4,062.6 |
| | 4,473.3 |
|
I&M | | 3,031.5 |
| | 3,497.3 |
| | 3,035.4 |
| | 3,070.2 |
|
OPCo | | 2,113.9 |
| | 2,618.5 |
| | 1,716.6 |
| | 1,919.7 |
|
PSO | | 1,386.4 |
| | 1,632.9 |
| | 1,287.0 |
| | 1,361.9 |
|
SWEPCo | | 2,656.9 |
| | 2,983.0 |
| | 2,713.4 |
| | 2,670.2 |
|
(a)The fair value amounts include debt related to AEP’s Equity Units and had a fair value of $1.6 billion and $871 million as of September 30, 2020 and December 31, 2019, respectively. See “Equity Units” section of Note 12 for additional information.
| |
(a) | The fair value amount includes debt related to AEP’s Equity Units issued in March 2019 and has a fair value of $887 million as of September 30, 2019. See “Equity Units” section of Note 13 for additional information. |
Fair Value Measurements of Other Temporary Investments (Applies to AEP)
Other Temporary Investments include marketable securities that management intends to hold for less than one year and investments by AEP’s protected cell of EIS.
The following is a summary of Other Temporary Investments:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | September 30, 2020 | | | | | | |
| | | | Gross | | Gross | | |
| | | | Unrealized | | Unrealized | | Fair |
Other Temporary Investments | | Cost | | Gains | | Losses | | Value |
| | (in millions) | | | | | | |
Restricted Cash and Other Cash Deposits (a) | | $ | 79.6 | | | $ | 0 | | | $ | 0 | | | $ | 79.6 | |
Fixed Income Securities – Mutual Funds (b) | | 127.9 | | | 2.9 | | | 0 | | | 130.8 | |
Equity Securities – Mutual Funds | | 30.2 | | | 22.5 | | | 0 | | | 52.7 | |
Total Other Temporary Investments | | $ | 237.7 | | | $ | 25.4 | | | $ | 0 | | | $ | 263.1 | |
| | | | September 30, 2019 | | December 31, 2019 | |
| | | | Gross | | Gross | | | | | Gross | | Gross | |
| | | | Unrealized | | Unrealized | | Fair | | Unrealized | | Unrealized | | Fair |
Other Temporary Investments | | Cost | | Gains | | Losses | | Value | Other Temporary Investments | | Cost | | Gains | | Losses | | Value |
| | (in millions) | | | (in millions) | |
Restricted Cash and Other Cash Deposits (a) | | $ | 160.1 |
| | $ | — |
| | $ | — |
| | $ | 160.1 |
| Restricted Cash and Other Cash Deposits (a) | | $ | 214.7 | | | $ | 0 | | | $ | 0 | | | $ | 214.7 | |
Fixed Income Securities – Mutual Funds (b) | | 133.4 |
| | — |
| | (0.2 | ) | | 133.2 |
| Fixed Income Securities – Mutual Funds (b) | | 123.2 | | | 0.1 | | | 0 | | | 123.3 | |
Equity Securities – Mutual Funds | | 28.5 |
| | 17.6 |
| | — |
| | 46.1 |
| Equity Securities – Mutual Funds | | 29.2 | | | 21.3 | | | 0 | | | 50.5 | |
Total Other Temporary Investments | | $ | 322.0 |
| | $ | 17.6 |
| | $ | (0.2 | ) | | $ | 339.4 |
| Total Other Temporary Investments | | $ | 367.1 | | | $ | 21.4 | | | $ | 0 | | | $ | 388.5 | |
(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.
|
| | | | | | | | | | | | | | | | |
| | December 31, 2018 |
| | | | Gross | | Gross | | |
| | | | Unrealized | | Unrealized | | Fair |
Other Temporary Investments | | Cost | | Gains | | Losses | | Value |
| | (in millions) |
Restricted Cash and Other Cash Deposits (a) | | $ | 230.6 |
| | $ | — |
| | $ | — |
| | $ | 230.6 |
|
Fixed Income Securities – Mutual Funds (b) | | 106.6 |
| | — |
| | (2.3 | ) | | 104.3 |
|
Equity Securities – Mutual Funds | | 17.8 |
| | 16.4 |
| | — |
| | 34.2 |
|
Total Other Temporary Investments | | $ | 355.0 |
| | $ | 16.4 |
| | $ | (2.3 | ) | | $ | 369.1 |
|
| |
(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, | | |
| 2020 | | 2019 | | 2020 | | 2019 |
| (in millions) | | | | | | |
Proceeds from Investment Sales | $ | 5.1 | | | $ | 2.8 | | | $ | 35.9 | | | $ | 2.8 | |
Purchases of Investments | 22.5 | | | 26.9 | | | 39.5 | | | 35.8 | |
Gross Realized Gains on Investment Sales | 0.2 | | | 0 | | | 2.4 | | | 0 | |
Gross Realized Losses on Investment Sales | 0 | | | 0 | | | 0.2 | | | 0 | |
|
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2019 | | 2018 | | 2019 | | 2018 |
| (in millions) |
Proceeds from Investment Sales | $ | 2.8 |
| | $ | — |
| | $ | 2.8 |
| | $ | — |
|
Purchases of Investments | 26.9 |
| | 0.8 |
| | 35.8 |
| | 2.2 |
|
Gross Realized Gains on Investment Sales | — |
| | — |
| | — |
| | — |
|
Gross Realized Losses on Investment Sales | — |
| | — |
| | — |
| | — |
|
For details of the reasons for changes in Securities Available for Sale included in Accumulated Other Comprehensive Income (Loss) for the three and nine months ended September 30, 2018, see Note 3 - Comprehensive Income.
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 external investment managers who 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 securities in the trust funds as available-for-sale due to their long-term purpose. With the adoption of ASU 2016-01, effective January 2018, available-for-saleAvailable-for-sale classification only applies to investment in debt securities.securities in accordance with ASU 2016-01. Additionally, the adoption of ASU 2016-01 requiredrequires changes in fair value of equity securities to be recognized in earnings. However, due to the regulatory treatment described below, this is not applicable for I&M’s trust fund securities.
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, 2020 | | | | | | December 31, 2019 | | | | |
| | | Gross | | Other-Than- | | | | Gross | | Other-Than- |
| Fair | | Unrealized | | Temporary | | Fair | | Unrealized | | Temporary |
| Value | | Gains | | Impairments | | Value | | Gains | | Impairments |
| (in millions) | | | | | | | | | | |
Cash and Cash Equivalents | $ | 33.7 | | | $ | 0 | | | $ | 0 | | | $ | 15.3 | | | $ | 0 | | | $ | 0 | |
Fixed Income Securities: | | | | | | | | | | | |
United States Government | 1,039.2 | | | 112.3 | | | (5.8) | | | 1,112.5 | | | 55.5 | | | (6.1) | |
Corporate Debt | 85.6 | | | 8.9 | | | (1.5) | | | 72.4 | | | 5.3 | | | (1.6) | |
State and Local Government | 123.9 | | | 1.5 | | | (0.3) | | | 7.6 | | | 0.7 | | | (0.2) | |
Subtotal Fixed Income Securities | 1,248.7 | | | 122.7 | | | (7.6) | | | 1,192.5 | | | 61.5 | | | (7.9) | |
Equity Securities - Domestic (a) | 1,793.5 | | | 1,165.8 | | | 0 | | | 1,767.9 | | | 1,144.4 | | | 0 | |
Spent Nuclear Fuel and Decommissioning Trusts | $ | 3,075.9 | | | $ | 1,288.5 | | | $ | (7.6) | | | $ | 2,975.7 | | | $ | 1,205.9 | | | $ | (7.9) | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| September 30, 2019 | | December 31, 2018 |
| | | Gross | | Other-Than- | | | | Gross | | Other-Than- |
| Fair | | Unrealized | | Temporary | | Fair | | Unrealized | | Temporary |
| Value | | Gains | | Impairments | | Value | | Gains | | Impairments |
| (in millions) |
Cash and Cash Equivalents | $ | 17.4 |
| | $ | — |
| | $ | — |
| | $ | 22.5 |
| | $ | — |
| | $ | — |
|
Fixed Income Securities: | | | | | | | | | | | |
United States Government | 1,047.4 |
| | 67.8 |
| | (5.8 | ) | | 996.1 |
| | 26.7 |
| | (7.1 | ) |
Corporate Debt | 68.6 |
| | 6.1 |
| | (1.7 | ) | | 52.4 |
| | 1.1 |
| | (1.9 | ) |
State and Local Government | 7.5 |
| | 0.7 |
| | (0.2 | ) | | 8.6 |
| | 0.6 |
| | (0.2 | ) |
Subtotal Fixed Income Securities | 1,123.5 |
| | 74.6 |
| | (7.7 | ) | | 1,057.1 |
| | 28.4 |
| | (9.2 | ) |
Equity Securities - Domestic (a) | 1,694.3 |
| | 1,037.7 |
| | — |
| | 1,395.3 |
| | 766.3 |
| | — |
|
Spent Nuclear Fuel and Decommissioning Trusts | $ | 2,835.2 |
| | $ | 1,112.3 |
| | $ | (7.7 | ) | | $ | 2,474.9 |
| | $ | 794.7 |
| | $ | (9.2 | ) |
(a)Amount reported as Gross Unrealized Gains includes unrealized gains of $1.2 billion and $1.1 billion and unrealized losses of $17 million and $5 million as of September 30, 2020 and December 31, 2019, respectively.
| |
(a) | Amount reported as Gross Unrealized Gains includes unrealized gains of $1 billion and $784 million and unrealized losses of $9 million and $18 million as of September 30, 2019 and December 31, 2018, respectively. AEP adopted ASU 2016-01 during the first quarter of 2018 by means of a modified retrospective approach. Due to the adoption of the ASU, Other-Than-Temporary Impairments are no longer applicable to Equity Securities with readily determinable fair values. |
The following table provides the securities activity within the decommissioning and SNF trusts:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | | | Nine Months Ended September 30, | | |
| | 2020 | | 2019 | | 2020 | | 2019 |
| | (in millions) | | | | | | |
Proceeds from Investment Sales | | $ | 316.6 | | | $ | 671.9 | | | $ | 1,257.1 | | | $ | 871.4 | |
Purchases of Investments | | 318.6 | | | 689.1 | | | 1,290.0 | | | 915.7 | |
Gross Realized Gains on Investment Sales | | 3.4 | | | 10.9 | | | 25.4 | | | 26.6 | |
Gross Realized Losses on Investment Sales | | 0.5 | | | 7.1 | | | 25.2 | | | 15.1 | |
|
| | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | 2019 | | 2018 | | 2019 | | 2018 |
| | (in millions) |
Proceeds from Investment Sales | | $ | 671.9 |
| | $ | 513.1 |
| | $ | 871.4 |
| | $ | 1,550.9 |
|
Purchases of Investments | | 689.1 |
| | 521.2 |
| | 915.7 |
| | 1,589.0 |
|
Gross Realized Gains on Investment Sales | | 10.9 |
| | 3.9 |
| | 26.6 |
| | 27.7 |
|
Gross Realized Losses on Investment Sales | | 7.1 |
| | 3.5 |
| | 15.1 |
| | 22.2 |
|
The base cost of fixed income securities was $1$1.1 billion and $1$1.1 billion as of September 30, 20192020 and December 31, 2018,2019, respectively. The base cost of equity securities was $657$628 million and $629$623 million as of September 30, 20192020 and December 31, 2018,2019, respectively.
The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of September 30, 20192020 was as follows:
| | | | | |
| Fair Value of Fixed |
| Income Securities |
| (in millions) |
Within 1 year | $ | 291.6 | |
After 1 year through 5 years | 355.9 | |
After 5 years through 10 years | 255.1 | |
After 10 years | 346.1 | |
Total | $ | 1,248.7 | |
|
| | | |
| Fair Value of Fixed |
| Income Securities |
| (in millions) |
Within 1 year | $ | 334.9 |
|
After 1 year through 5 years | 390.9 |
|
After 5 years through 10 years | 199.2 |
|
After 10 years | 198.5 |
|
Total | $ | 1,123.5 |
|
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, 20192020
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | | (in millions) | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
Other Temporary Investments | | | | | | | | | | |
Restricted Cash and Other Cash Deposits (a) | | $ | 66.3 | | | $ | 0 | | | $ | 0 | | | $ | 13.3 | | | $ | 79.6 | |
Fixed Income Securities – Mutual Funds | | 130.8 | | | 0 | | | 0 | | | 0 | | | 130.8 | |
Equity Securities – Mutual Funds (b) | | 52.7 | | | 0 | | | 0 | | | 0 | | | 52.7 | |
Total Other Temporary Investments | | 249.8 | | | 0 | | | 0 | | | 13.3 | | | 263.1 | |
| | | | | | | | | | |
Risk Management Assets | | | | | | | | | | |
Risk Management Commodity Contracts (c) (d) | | 3.2 | | | 247.1 | | | 280.3 | | | (185.3) | | | 345.3 | |
Cash Flow Hedges: | | | | | | | | | | |
Commodity Hedges (c) | | 0 | | | 36.1 | | | 4.3 | | | (28.2) | | | 12.2 | |
Interest Rate Hedges | | 0 | | | 0.6 | | | 0 | | | 0 | | | 0.6 | |
| | | | | | | | | | |
Total Risk Management Assets | | 3.2 | | | 283.8 | | | 284.6 | | | (213.5) | | | 358.1 | |
| | | | | | | | | | |
Spent Nuclear Fuel and Decommissioning Trusts | | | | | | | | | | |
Cash and Cash Equivalents (e) | | 24.7 | | | 0 | | | 0 | | | 9.0 | | | 33.7 | |
Fixed Income Securities: | | | | | | | | | | |
United States Government | | 0 | | | 1,039.2 | | | 0 | | | 0 | | | 1,039.2 | |
Corporate Debt | | 0 | | | 85.6 | | | 0 | | | 0 | | | 85.6 | |
State and Local Government | | 0 | | | 123.9 | | | 0 | | | 0 | | | 123.9 | |
Subtotal Fixed Income Securities | | 0 | | | 1,248.7 | | | 0 | | | 0 | | | 1,248.7 | |
Equity Securities – Domestic (b) | | 1,793.5 | | | 0 | | | 0 | | | 0 | | | 1,793.5 | |
Total Spent Nuclear Fuel and Decommissioning Trusts | | 1,818.2 | | | 1,248.7 | | | 0 | | | 9.0 | | | 3,075.9 | |
| | | | | | | | | | |
Total Assets | | $ | 2,071.2 | | | $ | 1,532.5 | | | $ | 284.6 | | | $ | (191.2) | | | $ | 3,697.1 | |
| | | | | | | | | | |
Liabilities: | | | | | | | | | | |
| | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | |
Risk Management Commodity Contracts (c) (d) | | $ | 3.4 | | | $ | 239.1 | | | $ | 173.2 | | | $ | (194.0) | | | $ | 221.7 | |
Cash Flow Hedges: | | | | | | | | | | |
Commodity Hedges (c) | | 0 | | | 90.7 | | | 5.3 | | | (28.2) | | | 67.8 | |
Interest Rate Hedges | | 0 | | | 5.3 | | | 0 | | | 0 | | | 5.3 | |
| | | | | | | | | | |
Total Risk Management Liabilities | | $ | 3.4 | | | $ | 335.1 | | | $ | 178.5 | | | $ | (222.2) | | | $ | 294.8 | |
|
| | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | | (in millions) |
| | | | | | | | | | |
Other Temporary Investments | | | | | | | | | | |
Restricted Cash and Other Cash Deposits (a) | | $ | 152.9 |
| | $ | — |
| | $ | — |
| | $ | 7.2 |
| | $ | 160.1 |
|
Fixed Income Securities – Mutual Funds | | 133.2 |
| | — |
| | — |
| | — |
| | 133.2 |
|
Equity Securities – Mutual Funds (b) | | 46.1 |
| | — |
| | — |
| | — |
| | 46.1 |
|
Total Other Temporary Investments | | 332.2 |
| | — |
| | — |
| | 7.2 |
| | 339.4 |
|
| | | | | | | | | | |
Risk Management Assets | | | | | | | | | | |
Risk Management Commodity Contracts (c) (d) | | 5.6 |
| | 228.2 |
| | 407.7 |
| | (195.3 | ) | | 446.2 |
|
Cash Flow Hedges: | | | | | | | | | | |
Commodity Hedges (c) | | — |
| | 17.6 |
| | 2.9 |
| | (8.2 | ) | | 12.3 |
|
Interest Rate Hedges | | — |
| | 1.9 |
| | — |
| | — |
| | 1.9 |
|
Fair Value Hedges | | — |
| | 25.3 |
| | — |
| | — |
| | 25.3 |
|
Total Risk Management Assets | | 5.6 |
| | 273.0 |
| | 410.6 |
| | (203.5 | ) | | 485.7 |
|
| | | | | | | | | | |
Spent Nuclear Fuel and Decommissioning Trusts | | | | | | | | | | |
Cash and Cash Equivalents (e) | | 9.4 |
| | — |
| | — |
| | 8.0 |
| | 17.4 |
|
Fixed Income Securities: | | | | | | | | | | |
United States Government | | — |
| | 1,047.4 |
| | — |
| | — |
| | 1,047.4 |
|
Corporate Debt | | — |
| | 68.6 |
| | — |
| | — |
| | 68.6 |
|
State and Local Government | | — |
| | 7.5 |
| | — |
| | — |
| | 7.5 |
|
Subtotal Fixed Income Securities | | — |
| | 1,123.5 |
| | — |
| | — |
| | 1,123.5 |
|
Equity Securities – Domestic (b) | | 1,694.3 |
| | — |
| | — |
| | — |
| | 1,694.3 |
|
Total Spent Nuclear Fuel and Decommissioning Trusts | | 1,703.7 |
| | 1,123.5 |
| | — |
| | 8.0 |
| | 2,835.2 |
|
| | | | | | | | | | |
Total Assets | | $ | 2,041.5 |
| | $ | 1,396.5 |
| | $ | 410.6 |
| | $ | (188.3 | ) | | $ | 3,660.3 |
|
| | | | | | | | | | |
Liabilities: | | | | | | | | | | |
| | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | |
Risk Management Commodity Contracts (c) (d) | | $ | 5.1 |
| | $ | 243.9 |
| | $ | 231.6 |
| | $ | (216.5 | ) | | $ | 264.1 |
|
Cash Flow Hedges: | | | | | | | | | | |
Commodity Hedges (c) | | — |
| | 49.1 |
| | 68.7 |
| | (8.2 | ) | | 109.6 |
|
Fair Value Hedges | | — |
| | 0.2 |
| | — |
| | — |
| | 0.2 |
|
Total Risk Management Liabilities | | $ | 5.1 |
| | $ | 293.2 |
| | $ | 300.3 |
| | $ | (224.7 | ) | | $ | 373.9 |
|
AEP
Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 20182019
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | | (in millions) | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
Other Temporary Investments | | | | | | | | | | |
Restricted Cash and Other Cash Deposits (a) | | $ | 197.6 | | | $ | 0 | | | $ | 0 | | | $ | 17.1 | | | $ | 214.7 | |
Fixed Income Securities – Mutual Funds | | 123.3 | | | 0 | | | 0 | | | 0 | | | 123.3 | |
Equity Securities – Mutual Funds (b) | | 50.5 | | | 0 | | | 0 | | | 0 | | | 50.5 | |
Total Other Temporary Investments | | 371.4 | | | 0 | | | 0 | | | 17.1 | | | 388.5 | |
| | | | | | | | | | |
Risk Management Assets | | | | | | | | | | |
Risk Management Commodity Contracts (c) (f) | | 4.0 | | | 440.1 | | | 369.2 | | | (404.5) | | | 408.8 | |
Cash Flow Hedges: | | | | | | | | | | |
Commodity Hedges (c) | | 0 | | | 15.0 | | | 3.2 | | | (6.7) | | | 11.5 | |
Interest Rate Hedges | | 0 | | | 4.6 | | | 0 | | | 0 | | | 4.6 | |
Fair Value Hedges | | 0 | | | 14.5 | | | 0 | | | 0 | | | 14.5 | |
Total Risk Management Assets | | 4.0 | | | 474.2 | | | 372.4 | | | (411.2) | | | 439.4 | |
| | | | | | | | | | |
Spent Nuclear Fuel and Decommissioning Trusts | | | | | | | | | | |
Cash and Cash Equivalents (e) | | 6.7 | | | 0 | | | 0 | | | 8.6 | | | 15.3 | |
Fixed Income Securities: | | | | | | | | | | |
United States Government | | 0 | | | 1,112.5 | | | 0 | | | 0 | | | 1,112.5 | |
Corporate Debt | | 0 | | | 72.4 | | | 0 | | | 0 | | | 72.4 | |
State and Local Government | | 0 | | | 7.6 | | | 0 | | | 0 | | | 7.6�� | |
Subtotal Fixed Income Securities | | 0 | | | 1,192.5 | | | 0 | | | 0 | | | 1,192.5 | |
Equity Securities – Domestic (b) | | 1,767.9 | | | 0 | | | 0 | | | 0 | | | 1,767.9 | |
Total Spent Nuclear Fuel and Decommissioning Trusts | | 1,774.6 | | | 1,192.5 | | | 0 | | | 8.6 | | | 2,975.7 | |
| | | | | | | | | | |
Total Assets | | $ | 2,150.0 | | | $ | 1,666.7 | | | $ | 372.4 | | | $ | (385.5) | | | $ | 3,803.6 | |
| | | | | | | | | | |
Liabilities: | | | | | | | | | | |
| | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | |
Risk Management Commodity Contracts (c) (f) | | $ | 3.8 | | | $ | 450.0 | | | $ | 224.0 | | | $ | (438.8) | | | $ | 239.0 | |
Cash Flow Hedges: | | | | | | | | | | |
Commodity Hedges (c) | | 0 | | | 105.3 | | | 38.5 | | | (6.7) | | | 137.1 | |
| | | | | | | | | | |
| | | | | | | | | | |
Total Risk Management Liabilities | | $ | 3.8 | | | $ | 555.3 | | | $ | 262.5 | | | $ | (445.5) | | | $ | 376.1 | |
|
| | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | | (in millions) |
| | | | | | | | | | |
Other Temporary Investments | | | | | | | | | | |
Restricted Cash and Other Cash Deposits (a) | | $ | 221.5 |
| | $ | — |
| | $ | — |
| | $ | 9.1 |
| | $ | 230.6 |
|
Fixed Income Securities – Mutual Funds | | 104.3 |
| | — |
| | — |
| | — |
| | 104.3 |
|
Equity Securities – Mutual Funds (b) | | 34.2 |
| | — |
| | — |
| | — |
| | 34.2 |
|
Total Other Temporary Investments | | 360.0 |
| | — |
| | — |
| | 9.1 |
| | 369.1 |
|
| | | | | | | | | | |
Risk Management Assets | | | | | | | | | | |
Risk Management Commodity Contracts (c) (f) | | 3.8 |
| | 326.5 |
| | 340.9 |
| | (288.5 | ) | | 382.7 |
|
Cash Flow Hedges: | | | | | | | | | | |
Commodity Hedges (c) | | — |
| | 24.1 |
| | 12.7 |
| | (2.7 | ) | | 34.1 |
|
Total Risk Management Assets | | 3.8 |
| | 350.6 |
| | 353.6 |
| | (291.2 | ) | | 416.8 |
|
| | | | | | | | | | |
Spent Nuclear Fuel and Decommissioning Trusts | | | | | | | | | | |
Cash and Cash Equivalents (e) | | 12.3 |
| | — |
| | — |
| | 10.2 |
| | 22.5 |
|
Fixed Income Securities: | | | | | | | | | | |
United States Government | | — |
| | 996.1 |
| | — |
| | — |
| | 996.1 |
|
Corporate Debt | | — |
| | 52.4 |
| | — |
| | — |
| | 52.4 |
|
State and Local Government | | — |
| | 8.6 |
| | — |
| | — |
| | 8.6 |
|
Subtotal Fixed Income Securities | | — |
| | 1,057.1 |
| | — |
| | — |
| | 1,057.1 |
|
Equity Securities – Domestic (b) | | 1,395.3 |
| | — |
| | — |
| | — |
| | 1,395.3 |
|
Total Spent Nuclear Fuel and Decommissioning Trusts | | 1,407.6 |
| | 1,057.1 |
| | — |
| | 10.2 |
| | 2,474.9 |
|
| | | | | | | | | | |
Total Assets | | $ | 1,771.4 |
| | $ | 1,407.7 |
| | $ | 353.6 |
| | $ | (271.9 | ) | | $ | 3,260.8 |
|
| | | | | | | | | | |
Liabilities: | | | | | | | | | | |
| | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | |
Risk Management Commodity Contracts (c) (f) | | $ | 4.2 |
| | $ | 327.0 |
| | $ | 185.6 |
| | $ | (274.7 | ) | | $ | 242.1 |
|
Cash Flow Hedges: | | | | | | | | | | |
Commodity Hedges (c) | | — |
| | 24.8 |
| | 36.8 |
| | (2.7 | ) | | 58.9 |
|
Fair Value Hedges | | — |
| | 17.4 |
| | — |
| | — |
| | 17.4 |
|
Total Risk Management Liabilities | | $ | 4.2 |
| | $ | 369.2 |
| | $ | 222.4 |
| | $ | (277.4 | ) | | $ | 318.4 |
|
AEP Texas
Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 20192020
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | | (in millions) | | | | | | | | |
| | | | | | | | | | |
Restricted Cash for Securitized Funding | | $ | 44.8 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 44.8 | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
Liabilities: | | | | | | | | | | |
| | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | |
Risk Management Commodity Contracts (c) | | $ | 0 | | | $ | 0.2 | | | $ | 0 | | | $ | (0.1) | | | $ | 0.1 | |
|
| | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | | (in millions) |
| | | | | | | | | | |
Restricted Cash for Securitized Funding | | $ | 114.3 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 114.3 |
|
| | | | | | | | | | |
Liabilities: | | | | | | | | | | |
| | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | |
Risk Management Commodity Contracts (c) | | $ | — |
| | $ | 0.4 |
| | $ | — |
| | $ | — |
| | $ | 0.4 |
|
December 31, 20182019
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | | (in millions) | | | | | | | | |
| | | | | | | | | | |
Restricted Cash for Securitized Funding | | $ | 154.7 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 154.7 | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | | (in millions) |
| | | | | | | | | | |
Restricted Cash for Securitized Funding | | $ | 156.7 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 156.7 |
|
| | | | | | | | | | |
Liabilities: | | | | | | | | | | |
| | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | |
Risk Management Commodity Contracts (c) | | $ | — |
| | $ | 0.7 |
| | $ | — |
| | $ | (0.5 | ) | | $ | 0.2 |
|
APCo
Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 20192020
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | | (in millions) | | | | | | | | |
| | | | | | | | | | |
Restricted Cash for Securitized Funding | | $ | 9.3 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 9.3 | |
| | | | | | | | | | |
Risk Management Assets | | | | | | | | | | |
Risk Management Commodity Contracts (c) (g) | | 0 | | | 20.4 | | | 30.1 | | | (20.3) | | | 30.2 | |
Cash Flow Hedges: | | | | | | | | | | |
Interest Rate Hedges | | 0 | | | 0.6 | | | 0 | | | 0 | | | 0.6 | |
Total Risk Management Assets | | 0 | | | 21.0 | | | 30.1 | | | (20.3) | | | 30.8 | |
| | | | | | | | | | |
Total Assets | | $ | 9.3 | | | $ | 21.0 | | | $ | 30.1 | | | $ | (20.3) | | | $ | 40.1 | |
| | | | | | | | | | |
Liabilities: | | | | | | | | | | |
| | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | |
Risk Management Commodity Contracts (c) (g) | | $ | 0 | | | $ | 21.2 | | | $ | 0.5 | | | $ | (21.2) | | | $ | 0.5 | |
Cash Flow Hedges: | | | | | | | | | | |
Interest Rate Hedges | | 0 | | | 5.3 | | | 0 | | | 0 | | | 5.3 | |
Total Risk Management Liabilities | | $ | 0 | | | $ | 26.5 | | | $ | 0.5 | | | $ | (21.2) | | | $ | 5.8 | |
|
| | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | | (in millions) |
| | | | | | | | | | |
Restricted Cash for Securitized Funding | | $ | 17.1 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 17.1 |
|
| | | | | | | | | | |
Risk Management Assets | | | | | | | | | | |
Risk Management Commodity Contracts (c) (g) | | — |
| | 31.4 |
| | 57.3 |
| | (32.0 | ) | | 56.7 |
|
| | | | | | | | | | |
Total Assets | | $ | 17.1 |
| | $ | 31.4 |
| | $ | 57.3 |
| | $ | (32.0 | ) | | $ | 73.8 |
|
| | | | | | | | | | |
Liabilities: | | | | | | | | | | |
| | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | |
Risk Management Commodity Contracts (c) (g) | | $ | — |
| | $ | 33.2 |
| | $ | 1.8 |
| | $ | (33.6 | ) | | $ | 1.4 |
|
December 31, 20182019
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | | (in millions) | | | | | | | | |
| | | | | | | | | | |
Restricted Cash for Securitized Funding | | $ | 23.5 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 23.5 | |
| | | | | | | | | | |
Risk Management Assets | | | | | | | | | | |
Risk Management Commodity Contracts (c) (g) | | 0 | | | 84.6 | | | 40.5 | | | (85.6) | | | 39.5 | |
| | | | | | | | | | |
Total Assets | | $ | 23.5 | | | $ | 84.6 | | | $ | 40.5 | | | $ | (85.6) | | | $ | 63.0 | |
| | | | | | | | | | |
Liabilities: | | | | | | | | | | |
| | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | |
Risk Management Commodity Contracts (c) (g) | | $ | 0 | | | $ | 84.0 | | | $ | 2.8 | | | $ | (84.9) | | | $ | 1.9 | |
|
| | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | | (in millions) |
| | | | | | | | | | |
Restricted Cash for Securitized Funding | | $ | 25.6 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 25.6 |
|
| | | | | | | | | | |
Risk Management Assets | | | | | | | | | | |
Risk Management Commodity Contracts (c) (g) | | 0.1 |
| | 59.1 |
| | 58.3 |
| | (59.4 | ) | | 58.1 |
|
| | | | | | | | | | |
Total Assets | | $ | 25.7 |
| | $ | 59.1 |
| | $ | 58.3 |
| | $ | (59.4 | ) | | $ | 83.7 |
|
| | | | | | | | | | |
Liabilities: | | | | | | | | | | |
| | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | |
Risk Management Commodity Contracts (c) (g) | | $ | 0.2 |
| | $ | 58.4 |
| | $ | 0.5 |
| | $ | (58.5 | ) | | $ | 0.6 |
|
194
I&M
Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 20192020
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | | (in millions) | | | | | | | | |
| | | | | | | | | | |
Risk Management Assets | | | | | | | | | | |
Risk Management Commodity Contracts (c) (g) | | $ | 0 | | | $ | 12.9 | | | $ | 4.1 | | | $ | (12.9) | | | $ | 4.1 | |
| | | | | | | | | | |
Spent Nuclear Fuel and Decommissioning Trusts | | | | | | | | | | |
Cash and Cash Equivalents (e) | | 24.7 | | | 0 | | | 0 | | | 9.0 | | | 33.7 | |
Fixed Income Securities: | | | | | | | | | | |
United States Government | | 0 | | | 1,039.2 | | | 0 | | | 0 | | | 1,039.2 | |
Corporate Debt | | 0 | | | 85.6 | | | 0 | | | 0 | | | 85.6 | |
State and Local Government | | 0 | | | 123.9 | | | 0 | | | 0 | | | 123.9 | |
Subtotal Fixed Income Securities | | 0 | | | 1,248.7 | | | 0 | | | 0 | | | 1,248.7 | |
Equity Securities - Domestic (b) | | 1,793.5 | | | 0 | | | 0 | | | 0 | | | 1,793.5 | |
Total Spent Nuclear Fuel and Decommissioning Trusts | | 1,818.2 | | | 1,248.7 | | | 0 | | | 9.0 | | | 3,075.9 | |
| | | | | | | | | | |
Total Assets | | $ | 1,818.2 | | | $ | 1,261.6 | | | $ | 4.1 | | | $ | (3.9) | | | $ | 3,080.0 | |
| | | | | | | | | | |
Liabilities: | | | | | | | | | | |
| | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | |
Risk Management Commodity Contracts (c) (g) | | $ | 0 | | | $ | 13.4 | | | $ | 0.3 | | | $ | (13.4) | | | $ | 0.3 | |
|
| | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | | (in millions) |
| | | | | | | | | | |
Risk Management Assets | | | | | | | | | | |
Risk Management Commodity Contracts (c) (g) | | $ | — |
| | $ | 21.9 |
| | $ | 10.2 |
| | $ | (21.5 | ) | | $ | 10.6 |
|
| | | | | | | | | | |
Spent Nuclear Fuel and Decommissioning Trusts | | | | | | | | | | |
Cash and Cash Equivalents (e) | | 9.4 |
| | — |
| | — |
| | 8.0 |
| | 17.4 |
|
Fixed Income Securities: | | | | | | | | | | |
United States Government | | — |
| | 1,047.4 |
| | — |
| | — |
| | 1,047.4 |
|
Corporate Debt | | — |
| | 68.6 |
| | — |
| | — |
| | 68.6 |
|
State and Local Government | | — |
| | 7.5 |
| | — |
| | — |
| | 7.5 |
|
Subtotal Fixed Income Securities | | — |
| | 1,123.5 |
| | — |
| | — |
| | 1,123.5 |
|
Equity Securities - Domestic (b) | | 1,694.3 |
| | — |
| | — |
| | — |
| | 1,694.3 |
|
Total Spent Nuclear Fuel and Decommissioning Trusts | | 1,703.7 |
| | 1,123.5 |
| | — |
| | 8.0 |
| | 2,835.2 |
|
| | | | | | | | | | |
Total Assets | | $ | 1,703.7 |
| | $ | 1,145.4 |
| | $ | 10.2 |
| | $ | (13.5 | ) | | $ | 2,845.8 |
|
| | | | | | | | | | |
Liabilities: | | | | | | | | | | |
| | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | |
Risk Management Commodity Contracts (c) (g) | | $ | — |
| | $ | 21.3 |
| | $ | 1.3 |
| | $ | (22.4 | ) | | $ | 0.2 |
|
December 31, 20182019
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | | (in millions) | | | | | | | | |
| | | | | | | | | | |
Risk Management Assets | | | | | | | | | | |
Risk Management Commodity Contracts (c) (g) | | $ | 0 | | | $ | 59.5 | | | $ | 8.0 | | | $ | (57.6) | | | $ | 9.9 | |
| | | | | | | | | | |
Spent Nuclear Fuel and Decommissioning Trusts | | | | | | | | | | |
Cash and Cash Equivalents (e) | | 6.7 | | | 0 | | | 0 | | | 8.6 | | | 15.3 | |
Fixed Income Securities: | | | | | | | | | | |
United States Government | | 0 | | | 1,112.5 | | | 0 | | | 0 | | | 1,112.5 | |
Corporate Debt | | 0 | | | 72.4 | | | 0 | | | 0 | | | 72.4 | |
State and Local Government | | 0 | | | 7.6 | | | 0 | | | 0 | | | 7.6 | |
Subtotal Fixed Income Securities | | 0 | | | 1,192.5 | | | 0 | | | 0 | | | 1,192.5 | |
Equity Securities - Domestic (b) | | 1,767.9 | | | 0 | | | 0 | | | 0 | | | 1,767.9 | |
Total Spent Nuclear Fuel and Decommissioning Trusts | | 1,774.6 | | | 1,192.5 | | | 0 | | | 8.6 | | | 2,975.7 | |
| | | | | | | | | | |
Total Assets | | $ | 1,774.6 | | | $ | 1,252.0 | | | $ | 8.0 | | | $ | (49.0) | | | $ | 2,985.6 | |
| | | | | | | | | | |
Liabilities: | | | | | | | | | | |
| | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | |
Risk Management Commodity Contracts (c) (g) | | $ | 0 | | | $ | 53.4 | | | $ | 2.2 | | | $ | (55.1) | | | $ | 0.5 | |
|
| | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | | (in millions) |
| | | | | | | | | | |
Risk Management Assets | | | | | | | | | | |
Risk Management Commodity Contracts (c) (g) | | $ | — |
| | $ | 42.1 |
| | $ | 10.3 |
| | $ | (43.2 | ) | | $ | 9.2 |
|
| | | | | | | | | | |
Spent Nuclear Fuel and Decommissioning Trusts | | | | | | | | | | |
Cash and Cash Equivalents (e) | | 12.3 |
| | — |
| | — |
| | 10.2 |
| | 22.5 |
|
Fixed Income Securities: | | | | | | | | | |
|
|
United States Government | | — |
| | 996.1 |
| | — |
| | — |
| | 996.1 |
|
Corporate Debt | | — |
| | 52.4 |
| | — |
| | — |
| | 52.4 |
|
State and Local Government | | — |
| | 8.6 |
| | — |
| | — |
| | 8.6 |
|
Subtotal Fixed Income Securities | | — |
| | 1,057.1 |
| | — |
| | — |
| | 1,057.1 |
|
Equity Securities - Domestic (b) | | 1,395.3 |
| | — |
| | — |
| | — |
| | 1,395.3 |
|
Total Spent Nuclear Fuel and Decommissioning Trusts | | 1,407.6 |
| | 1,057.1 |
| | — |
| | 10.2 |
| | 2,474.9 |
|
| | | | | | | | | | |
Total Assets | | $ | 1,407.6 |
| | $ | 1,099.2 |
| | $ | 10.3 |
| | $ | (33.0 | ) | | $ | 2,484.1 |
|
| | | | | | | | | | |
Liabilities: | | | | | | | | | | |
| | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | |
Risk Management Commodity Contracts (c) (g) | | $ | 0.1 |
| | $ | 41.2 |
| | $ | 1.4 |
| | $ | (42.3 | ) | | $ | 0.4 |
|
195
OPCo
Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 20192020
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
Liabilities: | | (in millions) | | | | | | | | |
| | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | |
Risk Management Commodity Contracts (c) (g) | | $ | 0 | | | $ | 0.2 | | | $ | 113.2 | | | $ | (0.1) | | | $ | 113.3 | |
|
| | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Liabilities: | | (in millions) |
| | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | |
Risk Management Commodity Contracts (c) (g) | | $ | — |
| | $ | 0.4 |
| | $ | 112.5 |
| | $ | — |
| | $ | 112.9 |
|
December 31, 20182019
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
Liabilities: | | (in millions) | | | | | | | | |
| | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | |
Risk Management Commodity Contracts (c) (g) | | $ | 0 | | | $ | 0 | | | $ | 103.6 | | | $ | 0 | | | $ | 103.6 | |
|
| | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | | (in millions) |
| | | | | | | | | | |
Restricted Cash for Securitized Funding | | $ | 27.6 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 27.6 |
|
| | | | | | | | | | |
Liabilities: | | | | | | | | | | |
| | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | |
Risk Management Commodity Contracts (c) (g) | | $ | — |
| | $ | 0.8 |
| | $ | 99.4 |
| | $ | (0.6 | ) | | $ | 99.6 |
|
PSO
Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 20192020
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | | (in millions) | | | | | | | | |
| | | | | | | | | | |
Risk Management Assets | | | | | | | | | | |
Risk Management Commodity Contracts (c) (g) | | $ | 0 | | | $ | 0 | | | $ | 16.6 | | | $ | 0 | | | $ | 16.6 | |
| | | | | | | | | | |
Liabilities: | | | | | | | | | | |
| | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | |
Risk Management Commodity Contracts (c) (g) | | $ | 0 | | | $ | 0.1 | | | $ | 0.5 | | | $ | (0.1) | | | $ | 0.5 | |
|
| | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | | (in millions) |
| | | | | | | | | | |
Risk Management Assets | | | | | | | | | | |
Risk Management Commodity Contracts (c) (g) | | $ | — |
| | $ | — |
| | $ | 22.0 |
| | $ | (0.3 | ) | | $ | 21.7 |
|
| | | | | | | | | | |
Liabilities: | | | | | | | | | | |
| | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | |
Risk Management Commodity Contracts (c) (g) | | $ | — |
| | $ | 0.2 |
| | $ | 0.4 |
| | $ | (0.3 | ) | | $ | 0.3 |
|
December 31, 20182019
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | | (in millions) | | | | | | | | |
| | | | | | | | | | |
Risk Management Assets | | | | | | | | | | |
Risk Management Commodity Contracts (c) (g) | | $ | 0 | | | $ | 0 | | | $ | 16.3 | | | $ | (0.5) | | | $ | 15.8 | |
| | | | | | | | | | |
Liabilities: | | | | | | | | | | |
| | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | |
Risk Management Commodity Contracts (c) (g) | | $ | 0 | | | $ | 0 | | | $ | 0.5 | | | $ | (0.5) | | | $ | 0 | |
|
| | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | | (in millions) |
| | | | | | | | | | |
Risk Management Assets | | | | | | | | | | |
Risk Management Commodity Contracts (c) (g) | | $ | — |
| | $ | — |
| | $ | 10.8 |
| | $ | (0.4 | ) | | $ | 10.4 |
|
| | | | | | | | | | |
Liabilities: | | | | | | | | | | |
| | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | |
Risk Management Commodity Contracts (c) (g) | | $ | — |
| | $ | 0.3 |
| | $ | 1.3 |
| | $ | (0.6 | ) | | $ | 1.0 |
|
196
SWEPCo
Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 20192020
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | | (in millions) | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
Risk Management Assets | | | | | | | | | | |
Risk Management Commodity Contracts (c) (g) | | $ | 0 | | | $ | 0 | | | $ | 4.4 | | | $ | 0.1 | | | $ | 4.5 | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
Liabilities: | | | | | | | | | | |
| | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | |
Risk Management Commodity Contracts (c) (g) | | $ | 0 | | | $ | 0.1 | | | $ | 0.7 | | | $ | 0 | | | $ | 0.8 | |
|
| | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | | (in millions) |
| | | | | | | | | | |
Risk Management Assets | | | | | | | | | | |
Risk Management Commodity Contracts (c) (g) | | $ | — |
| | $ | — |
| | $ | 9.8 |
| | $ | (0.4 | ) | | $ | 9.4 |
|
| | | | | | | | | | |
Liabilities: | | | | | | | | | | |
| | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | |
Risk Management Commodity Contracts (c) (g) | | $ | — |
| | $ | 0.2 |
| | $ | 4.9 |
| | $ | (0.4 | ) | | $ | 4.7 |
|
December 31, 20182019
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | | (in millions) | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
Risk Management Assets | | | | | | | | | | |
Risk Management Commodity Contracts (c) (g) | | $ | 0 | | | $ | 0 | | | $ | 6.5 | | | $ | (0.1) | | | $ | 6.4 | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
Liabilities: | | | | | | | | | | |
| | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | |
Risk Management Commodity Contracts (c) (g) | | $ | 0 | | | $ | 0 | | | $ | 5.1 | | | $ | (0.1) | | | $ | 5.0 | |
|
| | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | | (in millions) |
| | | | | | | | | | |
Risk Management Assets | | | | | | | | | | |
Risk Management Commodity Contracts (c) (g) | | $ | — |
| | $ | — |
| | $ | 5.6 |
| | $ | (0.8 | ) | | $ | 4.8 |
|
| | | | | | | | | | |
Liabilities: | | | | | | | | | | |
| | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | |
Risk Management Commodity Contracts (c) (g) | | $ | — |
| | $ | 0.4 |
| | $ | 3.3 |
| | $ | (1.1 | ) | | $ | 2.6 |
|
| |
(a) | (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, 2019 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 2 matures $(6) million in 2019, $(8) million in periods 2020-2022 and $(1) million in periods 2025-2032; Level 3 matures $40 million in 2019, $114 million in periods 2020-2022, $26 million in periods 2023-2024 and $(4) million in periods 2025-2032. 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, 2018 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 2 matures $(4) million in 2019, $1 million in periods 2020-2022, $1 million in periods 2023-2024 and $1 million in periods 2025-2032; Level 3 matures $108 million in 2019, $37 million in periods 2020-2022, $23 million in periods 2023-2024 and $(12) million in periods 2025-2032. Risk management commodity contracts are substantially comprised of power contracts. |
| |
(g) | Substantially comprised of power contracts for the Registrant Subsidiaries. |
There were no transfers between Level 1 and Level 2 duringamounts 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 threeaccounting guidance for “Derivatives and nine months endedHedging.’’
(d)The September 30, 2020 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 2 matures $(6) million in 2020, $3 million in periods 2021-2023, $4 million in periods 2024-2025 and $7 million in periods 2026-2033; Level 3 matures $35 million in 2020, $63 million in periods 2021-2023, $21 million in periods 2024-2025 and $(12) million in periods 2026-2033. 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, 2019 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 2 matures $(7) million in 2020 and 2018.$(3) million in periods 2021-2023; Level 3 matures $96 million in 2020, $36 million in periods 2021-2023, $25 million in periods 2024-2025 and $(12) million in periods 2026-2032. Risk management commodity contracts are substantially comprised of power contracts.
(g)Substantially comprised of power contracts for the Registrant Subsidiaries.
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, 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 | | | 0 | | | 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 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c) | | 2.6 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
Settlements | | (37.0) | | | (11.1) | | | (5.0) | | | 1.3 | | | (10.3) | | | (3.5) | |
Transfers into Level 3 (d) (e) | | (1.0) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
Transfers out of Level 3 (e) | | 1.1 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
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 | |
| | | | | | | | | | | | |
Three Months Ended September 30, 2019 | | AEP | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in millions) | | | | | | | | | | |
Balance as of June 30, 2019 | | $ | 112.7 | | | $ | 68.5 | | | $ | 12.3 | | | $ | (111.5) | | | $ | 27.8 | | | $ | 8.5 | |
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) | | 30.2 | | | 13.8 | | | 3.1 | | | 0 | | | 4.1 | | | 3.6 | |
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) | | 2.9 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c) | | 22.1 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
Settlements | | (67.4) | | | (28.1) | | | (7.2) | | | 1.1 | | | (11.2) | | | (6.7) | |
Transfers into Level 3 (d) (e) | | 3.5 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
Transfers out of Level 3 (e) | | 6.6 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
Changes in Fair Value Allocated to Regulated Jurisdictions (f) | | (0.3) | | | 1.3 | | | 0.7 | | | (2.1) | | | 0.9 | | | (0.5) | |
Balance as of September 30, 2019 | | $ | 110.3 | | | $ | 55.5 | | | $ | 8.9 | | | $ | (112.5) | | | $ | 21.6 | | | $ | 4.9 | |
| | | | | | | | | | | | |
Nine Months Ended September 30, 2020 | | AEP | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in millions) | | | | | | | | | | |
Balance as of December 31, 2019 | | $ | 109.9 | | | $ | 37.7 | | | $ | 5.8 | | | $ | (103.6) | | | $ | 15.8 | | | $ | 1.4 | |
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) | | 39.6 | | | 13.1 | | | 2.4 | | | (1.2) | | | 11.9 | | | 2.8 | |
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) | | (2.4) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c) | | 21.7 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
Settlements | | (115.3) | | | (51.4) | | | (8.5) | | | 6.4 | | | (27.6) | | | (6.9) | |
Transfers into Level 3 (d) (e) | | (1.1) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
Transfers out of Level 3 (e) | | 5.6 | | | 0.7 | | | 0.4 | | | 0 | | | 0 | | | 0 | |
Changes in Fair Value Allocated to Regulated Jurisdictions (f) | | 48.1 | | | 29.5 | | | 3.7 | | | (14.8) | | | 16.0 | | | 6.4 | |
Balance as of September 30, 2020 | | $ | 106.1 | | | $ | 29.6 | | | $ | 3.8 | | | $ | (113.2) | | | $ | 16.1 | | | $ | 3.7 | |
| | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
Three Months Ended September 30, 2019 | | AEP | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in millions) |
Balance as of June 30, 2019 | | $ | 112.7 |
| | $ | 68.5 |
| | $ | 12.3 |
| | $ | (111.5 | ) | | $ | 27.8 |
| | $ | 8.5 |
|
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) | | 30.2 |
| | 13.8 |
| | 3.1 |
| | — |
| | 4.1 |
| | 3.6 |
|
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 | | 22.1 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Settlements | | (67.4 | ) | | (28.1 | ) | | (7.2 | ) | | 1.1 |
| | (11.2 | ) | | (6.7 | ) |
Transfers into Level 3 (c) (d) | | 3.5 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Transfers out of Level 3 (d) | | 6.6 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Changes in Fair Value Allocated to Regulated Jurisdictions (e) | | (0.3 | ) | | 1.3 |
| | 0.7 |
| | (2.1 | ) | | 0.9 |
| | (0.5 | ) |
Balance as of September 30, 2019 | | $ | 110.3 |
| | $ | 55.5 |
| | $ | 8.9 |
| | $ | (112.5 | ) | | $ | 21.6 |
| | $ | 4.9 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Nine Months Ended September 30, 2019 | | AEP | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in millions) | | | | | | | | | | |
Balance as of December 31, 2018 | | $ | 131.2 | | | $ | 57.8 | | | $ | 8.9 | | | $ | (99.4) | | | $ | 9.5 | | | $ | 2.3 | |
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) | | 14.6 | | | (14.1) | | | 4.6 | | | (0.9) | | | 13.5 | | | 6.0 | |
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) | | 32.9 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c) | | (42.8) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
Settlements | | (114.6) | | | (41.9) | | | (12.6) | | | 4.6 | | | (23.0) | | | (10.1) | |
Transfers into Level 3 (d) (e) | | 0.4 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
Transfers out of Level 3 (e) | | 1.4 | | | (0.7) | | | (0.4) | | | 0 | | | 0 | | | 0 | |
Changes in Fair Value Allocated to Regulated Jurisdictions (f) | | 87.2 | | | 54.4 | | | 8.4 | | | (16.8) | | | 21.6 | | | 6.7 | |
Balance as of September 30, 2019 | | $ | 110.3 | | | $ | 55.5 | | | $ | 8.9 | | | $ | (112.5) | | | $ | 21.6 | | | $ | 4.9 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
Three Months Ended September 30, 2018 | | AEP | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in millions) |
Balance as of June 30, 2018 | | $ | 172.3 |
| | $ | 60.0 |
| | $ | 13.2 |
| | $ | (86.9 | ) | | $ | 24.3 |
| | $ | 4.9 |
|
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) | | 19.9 |
| | 9.0 |
| | 1.9 |
| | — |
| | 3.7 |
| | 1.7 |
|
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) | | 1.5 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income | | 10.4 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Settlements | | (56.0 | ) | | (19.8 | ) | | (5.5 | ) | | 0.6 |
| | (10.8 | ) | | (2.7 | ) |
Transfers into Level 3 (c) (d) | | 2.3 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Transfers out of Level 3 (d) | | (1.2 | ) | | — |
| | — |
| | — |
| | — |
| | — |
|
Changes in Fair Value Allocated to Regulated Jurisdictions (e) | | 12.0 |
| | 17.3 |
| | (0.2 | ) | | (8.9 | ) | | 0.4 |
| | (0.4 | ) |
Balance as of September 30, 2018 | | $ | 161.2 |
| | $ | 66.5 |
| | $ | 9.4 |
| | $ | (95.2 | ) | | $ | 17.6 |
| | $ | 3.5 |
|
(a)Included in revenues on the statements of income.(b)Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract.
(c)Included in cash flow hedges on the statements of comprehensive income.
(d)Represents existing assets or liabilities that were previously categorized as Level 2.
(e)Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred.
(f)Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory assets/liabilities or accounts payable.
|
| | | | | | | | | | | | | | | | | | | | | | | | |
Nine Months Ended September 30, 2019 | | AEP | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in millions) |
Balance as of December 31, 2018 | | $ | 131.2 |
| | $ | 57.8 |
| | $ | 8.9 |
| | $ | (99.4 | ) | | $ | 9.5 |
| | $ | 2.3 |
|
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) | | 14.6 |
| | (14.1 | ) | | 4.6 |
| | (0.9 | ) | | 13.5 |
| | 6.0 |
|
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) | | 32.9 |
| | — |
| | — |
| �� | — |
| | — |
| | — |
|
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income | | (42.8 | ) | | — |
| | — |
| | — |
| | — |
| | — |
|
Settlements | | (114.6 | ) | | (41.9 | ) | | (12.6 | ) | | 4.6 |
| | (23.0 | ) | | (10.1 | ) |
Transfers into Level 3 (c) (d) | | 0.4 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Transfers out of Level 3 (d) | | 1.4 |
| | (0.7 | ) | | (0.4 | ) | | — |
| | — |
| | — |
|
Changes in Fair Value Allocated to Regulated Jurisdictions (e) | | 87.2 |
| | 54.4 |
| | 8.4 |
| | (16.8 | ) | | 21.6 |
| | 6.7 |
|
Balance as of September 30, 2019 | | $ | 110.3 |
| | $ | 55.5 |
| | $ | 8.9 |
| | $ | (112.5 | ) | | $ | 21.6 |
| | $ | 4.9 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | |
Nine Months Ended September 30, 2018 | | AEP | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in millions) |
Balance as of December 31, 2017 | | $ | 40.3 |
| | $ | 24.7 |
| | $ | 7.6 |
| | $ | (132.4 | ) | | $ | 6.2 |
| | $ | 5.9 |
|
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) | | 150.9 |
| | 104.4 |
| | 14.7 |
| | 1.3 |
| | 18.1 |
| | (4.8 | ) |
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) | | 9.5 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income | | 16.4 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Settlements | | (212.3 | ) | | (128.3 | ) | | (21.9 | ) | | 3.0 |
| | (24.3 | ) | | (1.3 | ) |
Transfers into Level 3 (c) (d) | | 16.5 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Transfers out of Level 3 (d) | | (2.5 | ) | | — |
| | (0.3 | ) | | — |
| | — |
| | — |
|
Changes in Fair Value Allocated to Regulated Jurisdictions (e) | | 142.4 |
| | 65.7 |
| | 9.3 |
| | 32.9 |
| | 17.6 |
| | 3.7 |
|
Balance as of September 30, 2018 | | $ | 161.2 |
| | $ | 66.5 |
| | $ | 9.4 |
| | $ | (95.2 | ) | | $ | 17.6 |
| | $ | 3.5 |
|
| |
(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) | Represents existing assets or liabilities that were previously categorized as Level 2. |
| |
(d) | Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. |
| |
(e) | Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory assets/liabilities or accounts payable. |
The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions:
AEP
Significant Unobservable Inputs
September 30, 20192020
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Significant | | Input/Range | | | | |
| Fair Value | | | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input | | Low | | High | | Average (c) |
| (in millions) | | | | | | | | | | | | |
Energy Contracts | $ | 219.2 | | | $ | 173.0 | | | Discounted Cash Flow | | Forward Market Price (a) | | $ | 3.36 | | | $ | 111.42 | | | $ | 32.62 | |
Natural Gas Contracts | 0 | | | 0.6 | | | Discounted Cash Flow | | Forward Market Price (b) | | 1.79 | | | 3.06 | | | 2.61 | |
FTRs | 65.4 | | | 4.9 | | | Discounted Cash Flow | | Forward Market Price (a) | | (6.15) | | | 10.66 | | | 0.23 | |
Total | $ | 284.6 | | | $ | 178.5 | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Significant | | Input/Range |
| Fair Value | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input | | Low | | High | | Average |
| (in millions) | | | | | | | | | | |
Energy Contracts | $ | 298.8 |
| | $ | 286.8 |
| | Discounted Cash Flow | | Forward Market Price (a) | | $ | (0.05 | ) | | $ | 180.10 |
| | $ | 31.34 |
|
Natural Gas Contracts | — |
| | 4.5 |
| | Discounted Cash Flow | | Forward Market Price (b) | | 1.96 |
| | 2.62 |
| | 2.25 |
|
FTRs | 111.8 |
| | 9.0 |
| | Discounted Cash Flow | | Forward Market Price (a) | | (10.40 | ) | | 11.65 |
| | 0.54 |
|
Total | $ | 410.6 |
| | $ | 300.3 |
| | | | | | | | | | |
December 31, 20182019
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Significant | | Input/Range | | | | |
| Fair Value | | | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input | | Low | | High | | Average (c) |
| (in millions) | | | | | | | | | | | | |
Energy Contracts | $ | 296.7 | | | $ | 249.3 | | | Discounted Cash Flow | | Forward Market Price (a) | | $ | (0.05) | | | $ | 177.30 | | | $ | 31.31 | |
Natural Gas Contracts | 0 | | | 4.9 | | | Discounted Cash Flow | | Forward Market Price (b) | | 1.89 | | | 2.51 | | | 2.19 | |
FTRs | 75.7 | | | 8.3 | | | Discounted Cash Flow | | Forward Market Price (a) | | (8.52) | | | 9.34 | | | 0.42 | |
Total | $ | 372.4 | | | $ | 262.5 | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Significant | | Input/Range |
| Fair Value | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input | | Low | | High | | Average |
| (in millions) | | | | | | | | | | |
Energy Contracts | $ | 257.1 |
| | $ | 212.5 |
| | Discounted Cash Flow | | Forward Market Price (a) | | $ | (0.05 | ) | | $ | 176.57 |
| | $ | 33.07 |
|
Natural Gas Contracts | — |
| | 2.5 |
| | Discounted Cash Flow | | Forward Market Price (b) | | 2.18 |
| | 3.54 |
| | 2.47 |
|
FTRs | 96.5 |
| | 7.4 |
| | Discounted Cash Flow | | Forward Market Price (a) | | (11.68 | ) | | 17.79 |
| | 1.09 |
|
Total | $ | 353.6 |
| | $ | 222.4 |
| | | | | | | | | | |
APCo
Significant Unobservable Inputs
September 30, 20192020
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Significant | | Input/Range | | | | |
| Fair Value | | | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average (c) |
| (in millions) | | | | | | | | | | | | |
Energy Contracts | $ | 0.8 | | | $ | 0.5 | | | Discounted Cash Flow | | Forward Market Price | | $ | 9.56 | | | $ | 41.80 | | | $ | 27.25 | |
FTRs | 29.3 | | | 0 | | | Discounted Cash Flow | | Forward Market Price | | (0.81) | | | 6.57 | | | 1.09 | |
Total | $ | 30.1 | | | $ | 0.5 | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Significant | | Input/Range |
| Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average |
| (in millions) | | | | | | | | | | |
Energy Contracts | $ | 3.6 |
| | $ | 1.1 |
| | Discounted Cash Flow | | Forward Market Price | | $ | 12.93 |
| | $ | 59.25 |
| | $ | 31.28 |
|
FTRs | 53.7 |
| | 0.7 |
| | Discounted Cash Flow | | Forward Market Price | | (0.91 | ) | | 10.14 |
| | 1.63 |
|
Total | $ | 57.3 |
| | $ | 1.8 |
| | | | | | | | | | |
December 31, 20182019
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Significant | | Input/Range | | | | |
| Fair Value | | | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average (c) |
| (in millions) | | | | | | | | | | | | |
Energy Contracts | $ | 5.7 | | | $ | 2.6 | | | Discounted Cash Flow | | Forward Market Price | | $ | 12.70 | | | $ | 41.20 | | | $ | 25.92 | |
FTRs | 34.8 | | | 0.2 | | | Discounted Cash Flow | | Forward Market Price | | (0.14) | | | 7.08 | | | 1.70 | |
Total | $ | 40.5 | | | $ | 2.8 | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Significant | | Input/Range |
| Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average |
| (in millions) | | | | | | | | | | |
Energy Contracts | $ | 2.4 |
| | $ | 0.5 |
| | Discounted Cash Flow | | Forward Market Price | | $ | 16.82 |
| | $ | 62.65 |
| | $ | 37.00 |
|
FTRs | 55.9 |
| | — |
| | Discounted Cash Flow | | Forward Market Price | | 0.10 |
| | 15.16 |
| | 3.27 |
|
Total | $ | 58.3 |
| | $ | 0.5 |
| | | | | | | | | | |
I&M
Significant Unobservable Inputs
September 30, 20192020
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Significant | | Input/Range | | | | |
| Fair Value | | | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average (c) |
| (in millions) | | | | | | | | | | | | |
Energy Contracts | $ | 0.5 | | | $ | 0.3 | | | Discounted Cash Flow | | Forward Market Price | | $ | 9.56 | | | $ | 41.80 | | | $ | 27.25 | |
FTRs | 3.6 | | | 0 | | | Discounted Cash Flow | | Forward Market Price | | (2.68) | | | 4.24 | | | 0.41 | |
Total | $ | 4.1 | | | $ | 0.3 | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Significant | | Input/Range |
| Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average |
| (in millions) | | | | | | | | | | |
Energy Contracts | $ | 2.2 |
| | $ | 0.7 |
| | Discounted Cash Flow | | Forward Market Price | | $ | 12.93 |
| | $ | 59.25 |
| | $ | 31.28 |
|
FTRs | 8.0 |
| | 0.6 |
| | Discounted Cash Flow | | Forward Market Price | | (1.76 | ) | | 7.26 |
| | 0.87 |
|
Total | $ | 10.2 |
| | $ | 1.3 |
| | | | | | | | | | |
December 31, 20182019
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Significant | | Input/Range | | | | |
| Fair Value | | | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average (c) |
| (in millions) | | | | | | | | | | | | |
Energy Contracts | $ | 3.4 | | | $ | 1.5 | | | Discounted Cash Flow | | Forward Market Price | | $ | 12.70 | | | $ | 41.20 | | | $ | 25.92 | |
FTRs | 4.6 | | | 0.7 | | | Discounted Cash Flow | | Forward Market Price | | (0.75) | | | 4.07 | | | 0.74 | |
Total | $ | 8.0 | | | $ | 2.2 | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Significant | | Input/Range |
| Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average |
| (in millions) | | | | | | | | | | |
Energy Contracts | $ | 1.4 |
| | $ | 0.9 |
| | Discounted Cash Flow | | Forward Market Price | | $ | 16.82 |
| | $ | 62.65 |
| | $ | 37.00 |
|
FTRs | 8.9 |
| | 0.5 |
| | Discounted Cash Flow | | Forward Market Price | | (2.11 | ) | | 6.21 |
| | 1.06 |
|
Total | $ | 10.3 |
| | $ | 1.4 |
| | | | | | | | | | |
OPCo
Significant Unobservable Inputs
September 30, 20192020
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Significant | | Input/Range | | | | |
| Fair Value | | | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average (c) |
| (in millions) | | | | | | | | | | | | |
Energy Contracts | $ | 0 | | | $ | 113.2 | | | Discounted Cash Flow | | Forward Market Price | | $ | 11.68 | | | $ | 47.28 | | | $ | 28.31 | |
| | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Significant | | Input/Range |
| Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average |
| (in millions) | | | | | | | | | | |
Energy Contracts | $ | — |
| | $ | 112.5 |
| | Discounted Cash Flow | | Forward Market Price | | $ | 27.47 |
| | $ | 65.81 |
| | $ | 40.30 |
|
December 31, 20182019
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Significant | | Input/Range | | | | |
| Fair Value | | | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average (c) |
| (in millions) | | | | | | | | | | | | |
Energy Contracts | $ | 0 | | | $ | 103.6 | | | Discounted Cash Flow | | Forward Market Price | | $ | 29.23 | | | $ | 61.43 | | | $ | 42.46 | |
| | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Significant | | Input/Range |
| Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average |
| (in millions) | | | | | | | | | | |
Energy Contracts | $ | — |
| | $ | 99.4 |
| | Discounted Cash Flow | | Forward Market Price | | $ | 26.29 |
| | $ | 62.74 |
| | $ | 42.50 |
|
PSO
Significant Unobservable Inputs
September 30, 20192020
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Significant | | Input/Range | | | | |
| Fair Value | | | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average (c) |
| (in millions) | | | | | | | | | | | | |
FTRs | $ | 16.6 | | | $ | 0.5 | | | Discounted Cash Flow | | Forward Market Price | | $ | (5.98) | | | $ | 0.70 | | | $ | (1.85) | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Significant | | Input/Range |
| Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average |
| (in millions) | | | | | | | | | | |
FTRs | $ | 22.0 |
| | $ | 0.4 |
| | Discounted Cash Flow | | Forward Market Price | | $ | (6.87 | ) | | $ | 0.93 |
| | $ | (2.19 | ) |
December 31, 20182019
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Significant | | Input/Range | | | | |
| Fair Value | | | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average (c) |
| (in millions) | | | | | | | | | | | | |
FTRs | $ | 16.3 | | | $ | 0.5 | | | Discounted Cash Flow | | Forward Market Price | | $ | (8.52) | | | $ | 0.85 | | | $ | (2.31) | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Significant | | Input/Range |
| Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average |
| (in millions) | | | | | | | | | | |
FTRs | $ | 10.8 |
| | $ | 1.3 |
| | Discounted Cash Flow | | Forward Market Price | | $ | (11.68 | ) | | $ | 10.30 |
| | $ | (1.40 | ) |
SWEPCo
Significant Unobservable Inputs
September 30, 20192020
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Significant | | Input/Range | | | | |
| Fair Value | | | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input | | Low | | High | | Average (c) |
| (in millions) | | | | | | | | | | | | |
Natural Gas Contracts | $ | 0 | | | $ | 0.6 | | | Discounted Cash Flow | | Forward Market Price (b) | | $ | 1.79 | | | $ | 3.02 | | | $ | 2.54 | |
FTRs | 4.4 | | | 0.1 | | | Discounted Cash Flow | | Forward Market Price (a) | | (5.98) | | | 0.70 | | | (1.85) | |
Total | $ | 4.4 | | | $ | 0.7 | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Significant | | Input/Range |
| Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input | | Low | | High | | Average |
| (in millions) | | | | | | | | | | |
Natural Gas Contracts | $ | — |
| | $ | 4.5 |
| | Discounted Cash Flow | | Forward Market Price (b) | | $ | 1.96 |
| | $ | 2.62 |
| | $ | 2.25 |
|
FTRs | 9.8 |
| | 0.4 |
| | Discounted Cash Flow | | Forward Market Price (a) | | (6.87 | ) | | 0.93 |
| | (2.19 | ) |
Total | $ | 9.8 |
| | $ | 4.9 |
| | | | | | | | | | |
December 31, 20182019
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Significant | | Input/Range | | | | |
| Fair Value | | | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input | | Low | | High | | Average (c) |
| (in millions) | | | | | | | | | | | | |
Natural Gas Contracts | $ | 0 | | | $ | 4.9 | | | Discounted Cash Flow | | Forward Market Price (b) | | $ | 1.89 | | | $ | 2.51 | | | $ | 2.18 | |
FTRs | 6.5 | | | 0.2 | | | Discounted Cash Flow | | Forward Market Price (a) | | (8.52) | | | 0.85 | | | (2.31) | |
Total | $ | 6.5 | | | $ | 5.1 | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Significant | | Input/Range |
| Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input | | Low | | High | | Average |
| (in millions) | | | | | | | | | | |
Natural Gas Contracts | $ | — |
| | $ | 2.5 |
| | Discounted Cash Flow | | Forward Market Price (b) | | $ | 2.18 |
| | $ | 3.54 |
| | $ | 2.47 |
|
FTRs | 5.6 |
| | 0.8 |
| | Discounted Cash Flow | | Forward Market Price (a) | | (11.68 | ) | | 10.30 |
| | (1.40 | ) |
Total | $ | 5.6 |
| | $ | 3.3 |
| | | | | | | | | | |
(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.
| |
(a) | Represents market prices in dollars per MWh. |
| |
(b) | Represents market prices in dollars per MMBtu. |
The following table provides sensitivitythe measurement uncertainty of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts, Natural Gas Contracts and FTRs for the Registrants as of September 30, 20192020 and December 31, 2018:2019:
SensitivityUncertainty 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) |
11. INCOME TAXES
The disclosures in this note apply to all Registrants unless indicated otherwise.
Status of Tax Reform Regulatory Proceedings
For AEP’s various regulatory jurisdictions where the regulatory effects of Tax Reform proceedings have not been fully resolved, the table below summarizes the current status. See Note 4 - Rate Matters for additional information related to regulatory filings in these jurisdictions.
|
| | | | | | |
Registrant (Jurisdiction) | | Change in Tax Rate | | Excess ADIT Subject to Normalization Requirements | | Excess ADIT Not Subject to Normalization Requirements |
AEP Texas (Texas-Distribution) | | Order Issued | | Order Issued | | Order Issued – Partial (a) |
AEP Texas (Texas-Transmission) | | Order Issued | | Case Pending | | Case Pending |
I&M (Michigan) | | Order Issued | | Case Pending | | Case Pending |
SWEPCo (Louisiana) | | Case Pending – Rates Implemented (b) | | Case Pending – Rates Implemented (b) | | Case Pending – Rates Implemented (b) |
SWEPCo (Texas) | | Order Issued | | To be addressed in a later filing | | To be addressed in a later filing |
Federal Legislation
| |
(a) | A portion of the Excess ADIT that is not subject to rate normalization requirements is addressed in a current pending case. |
| |
(b) | Rates have been implemented through a filed formula rate plan that is subject to true-up and final commission approval. |
In March 2020, the CARES Act was signed into law. The CARES Act includes tax relief provisions such as: (a) an Alternative Minimum Tax (AMT) Credit Refund, (b) a 5-year net operating losses (NOL) carryback from years 2018-2020 and (c) delayed payment of employer payroll taxes. In May 2020, the House passed the "Health and Economic Recovery Omnibus Emergency Solutions Act" (HEROES Act) pending decision by the Senate. If enacted, the HEROES Act would disallow NOL carrybacks to any tax year beginning before January 1, 2018. Pursuant to the CARES Act, AEP, APCo and OPCo requested and in July received a $20 million, $7 million and $9 million, respectively, refund of AMT credit. In the third quarter of 2020, AEP also requested a $95 million refund of taxes paid in 2014 under the 5-year NOL carryback provision of the CARES Act. AEP carried back an NOL generated on the 2019 Federal income 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 change in the corporate income tax rates between the two periods, AEP realized a tax benefit of $52 million, recorded discretely, primarily at the Generation & Marketing segment. On October 1, 2020, after AEP filed its request with the IRS, the House passed a revised version of the HEROES Act; which similar to the original legislation would disallow NOL carryback to years prior to 2018. Management will continue to monitor the potential impact of this legislation. The Registrants are currently deferring payments of the employer share of payroll taxes for the period March 27, 2020 through December 31, 2020 and will pay 50% of the obligation by December 31, 2021 and the remaining 50% by December 31, 2022.
Effective Tax Rates (ETR)
The Registrants’ interim ETR reflect the estimated annual ETR for 20192020 and 2018,2019, adjusted for tax expense associated with certain discrete items. The interim ETR differ from the federal statutory tax rate of 21% primarily due to increased amortization of Excess ADIT, tax credits and other book/tax differences which are accounted for on a flow-through basis.
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 table. Significant variances in the ETR are described below.tables:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three 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 | | 2.7 | % | | 2.0 | % | | 2.9 | % | | 3.1 | % | | 3.4 | % | | 0.8 | % | | 4.6 | % | | 2.4 | % |
Tax Reform Excess ADIT Reversal | | (11.0) | % | | (14.6) | % | | 0.4 | % | | (22.0) | % | | (16.7) | % | | (6.7) | % | | (20.3) | % | | (7.3) | % |
Production and Investment Tax Credits | | (4.6) | % | | (0.5) | % | | 0 | % | | 0 | % | | (1.6) | % | | 0 | % | | (1.1) | % | | (0.5) | % |
Flow Through | | 0.5 | % | | 0.2 | % | | 0.5 | % | | 1.6 | % | | 0.2 | % | | 0.9 | % | | 0.2 | % | | (1.2) | % |
AFUDC Equity | | (1.5) | % | | (3.5) | % | | (2.6) | % | | (1.1) | % | | (0.9) | % | | (0.9) | % | | (0.6) | % | | (0.3) | % |
Parent Company Loss Benefit | | 0 | % | | 0 | % | | (0.9) | % | | (3.1) | % | | (3.7) | % | | (0.3) | % | | (1.7) | % | | (2.0) | % |
Discrete Tax Adjustments | | (7.4) | % | | (3.6) | % | | (0.2) | % | | (6.6) | % | | 2.3 | % | | 8.4 | % | | (0.6) | % | | (0.6) | % |
Other | | 0.1 | % | | 0.3 | % | | 0.1 | % | | 0 | % | | 0 | % | | 0.3 | % | | 0.1 | % | | (0.6) | % |
Effective Income Tax Rate | | (0.2) | % | | 1.3 | % | | 21.2 | % | | (7.1) | % | | 4.0 | % | | 23.5 | % | | 1.6 | % | | 10.9 | % |
| | | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
Company | | 2019 | | 2018 | | 2019 | | 2018 |
AEP | | 5.2 | % | | (16.2 | )% | | 1.7 | % | | 5.6 | % |
AEP Texas | | 15.1 | % | | 12.6 | % | | (25.3 | )% | | 14.9 | % |
AEPTCo | | 21.9 | % | | 18.4 | % | | 20.7 | % | | 20.7 | % |
APCo | | (3.9 | )% | | (962.2 | )% | | (19.1 | )% | | (13.8 | )% |
I&M | | (2.7 | )% | | 15.9 | % | | (2.1 | )% | | 10.4 | % |
OPCo | | 13.9 | % | | (46.4 | )% | | 14.2 | % | | 4.6 | % |
PSO | | 6.4 | % | | 5.6 | % | | 4.6 | % | | 8.7 | % |
SWEPCo | | (0.6 | )% | | 9.8 | % | | — | % | | 11.4 | % |
204
AEP
Three Months Ended September 30, 2019 Compared to Three Months Ended September 30, 2018
The increase in the ETR was primarily due to $71 million of decreased amortization of Excess ADIT not subject to normalization requirements and $14 million of increased state tax expense which impacted the ETR by 19.1% and 1.3%, respectively.
Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018
The decrease in the ETR was primarily due to $93 million of increased amortization of Excess ADIT not subject to normalization requirements which impacted the ETR by (4.5)%. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, 2019 | | | | | | | | | | | | | | |
| | 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 | % | | 1.4 | % | | 3.1 | % | | 3.0 | % | | (0.1) | % | | 0.4 | % | | 4.8 | % | | 2.4 | % |
Tax Reform Excess ADIT Reversal | | (11.9) | % | | (6.1) | % | | 1.4 | % | | (26.6) | % | | (17.3) | % | | (6.9) | % | | (16.5) | % | | (19.5) | % |
Production and Investment Tax Credits | | (3.7) | % | | (0.2) | % | | 0 | % | | 0 | % | | (2.0) | % | | 0 | % | | (1.4) | % | | (0.9) | % |
Flow Through | | 0.4 | % | | 0 | % | | 0.1 | % | | 3.8 | % | | (0.7) | % | | 1.0 | % | | 0.7 | % | | (0.5) | % |
AFUDC Equity | | (1.5) | % | | (1.1) | % | | (2.6) | % | | (1.3) | % | | (1.7) | % | | (1.7) | % | | (0.3) | % | | (0.9) | % |
Parent Company Loss Benefit | | 0 | % | | (0.1) | % | | (1.3) | % | | (1.1) | % | | (1.0) | % | | 0.4 | % | | (1.8) | % | | (1.8) | % |
Discrete Tax Adjustments | | (1.7) | % | | 0 | % | | (0.1) | % | | (2.4) | % | | (1.3) | % | | 1.7 | % | | 0 | % | | 0 | % |
Other | | 0 | % | | 0.2 | % | | 0.3 | % | | (0.3) | % | | 0.4 | % | | (2.0) | % | | (0.1) | % | | (0.4) | % |
Effective Income Tax Rate | | 5.2 | % | | 15.1 | % | | 21.9 | % | | (3.9) | % | | (2.7) | % | | 13.9 | % | | 6.4 | % | | (0.6) | % |
| | | | | | | | | | | | | | | | |
| | 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) | % | | 0 | % | | 0 | % | | (1.6) | % | | 0 | % | | (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 | % | | 0 | % | | (0.9) | % | | (3.1) | % | | (3.7) | % | | (0.3) | % | | (1.7) | % | | (1.9) | % |
Discrete Tax Adjustments | | (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 | % |
AEP Texas
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| | Nine Months Ended September 30, 2019 | | | | | | | | | | | | | | |
| | 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 | | 2.1 | % | | 1.5 | % | | 3.0 | % | | 3.3 | % | | 1.2 | % | | 0.7 | % | | 4.7 | % | | 1.8 | % |
Tax Reform Excess ADIT Reversal | | (16.7) | % | | (43.9) | % | | 0.7 | % | | (40.2) | % | | (17.3) | % | | (7.4) | % | | (18.2) | % | | (18.7) | % |
Production and Investment Tax Credits | | (3.6) | % | | (0.5) | % | | 0 | % | | 0 | % | | (2.0) | % | | 0 | % | | (1.5) | % | | (0.8) | % |
Flow Through | | 0.1 | % | | 0.1 | % | | 0.2 | % | | 0.7 | % | | (1.8) | % | | 0.7 | % | | 0.6 | % | | (0.6) | % |
AFUDC Equity | | (1.5) | % | | (1.3) | % | | (2.5) | % | | (1.1) | % | | (1.9) | % | | (1.0) | % | | (0.3) | % | | (0.9) | % |
Parent Company Loss Benefit | | 0 | % | | (1.0) | % | | (1.1) | % | | (1.9) | % | | (1.5) | % | | (0.7) | % | | (1.8) | % | | (1.5) | % |
Discrete Tax Adjustments | | 0 | % | | (1.3) | % | | (0.6) | % | | (0.8) | % | | 0.2 | % | | 0.5 | % | | 0 | % | | (0.2) | % |
Other | | 0.3 | % | | 0.1 | % | | 0 | % | | (0.1) | % | | 0 | % | | 0.4 | % | | 0.1 | % | | (0.1) | % |
Effective Income Tax Rate | | 1.7 | % | | (25.3) | % | | 20.7 | % | | (19.1) | % | | (2.1) | % | | 14.2 | % | | 4.6 | % | | 0 | % |
Three Months Ended September 30, 2019 Compared to Three Months Ended September 30, 2018
The increase in ETR was primarily due to significantly higher pretax book income which reduced the impact that favorable tax deductions had on the ETR.
Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018
The decrease in the ETR was primarily due to $59 million of increased amortization of Excess ADIT not subject to normalization requirements which impacted the ETR by (38.9)%. Amortization of Excess ADIT not subject to normalization requirements for the nine months ended September 30, 2019 reflects Tax Reform elements of the Stipulation and Settlement agreement approved by the PUCT in August 2018 and the Texas Storm Cost Securitization financing order issued by the PUCT in June 2019.
AEPTCo
Three Months Ended September 30, 2019 Compared to Three Months Ended September 30, 2018
The increase in the ETR was primarily due to $3 million of increased state tax expense and $2 million of decreased amortization of Excess ADIT not subject to normalization requirements which impacted the ETR by 1.3% and 1%, respectively.
Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018
The ETR remained consistent for the nine months ended September 30, 2019 and 2018.
APCo
Three Months Ended September 30, 2019 Compared to Three Months Ended September 30, 2018
The increase in the ETR was primarily due to $56 million of decreased amortization of Excess ADIT not subject to normalization requirements and $6 million of increased state tax expense which impacted the ETR by 947.3% and 34.8%, respectively. Amortization of Excess ADIT not subject to normalization requirements primarily decreased from the prior year due to the discrete impact of the West Virginia Tax Reform order which enabled APCo to utilize $73 million of Excess ADIT not subject to normalization requirements to offset certain regulatory asset balances in the third quarter of 2018.
Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018
The decrease in the ETR was primarily due to $9 million of increased amortization of Excess ADIT not subject to normalization requirements which impacted the ETR by (4.6)%. Amortization of Excess ADIT not subject to normalization requirements for the nine months ended September 30, 2019 reflects the October 2018 and March 2019 Virginia SCC Tax Reform orders as well as the August 2018 and February 2019 WVPSC orders.
I&M
Three Months Ended September 30, 2019 Compared to Three Months Ended September 30, 2018
The decrease in the ETR was primarily due to $10 million of increased amortization of Excess ADIT, $3 million of increased favorable book/tax differences accounted for on a flow-through basis, $2 million of decreased state income tax expense and $1 million of increased parent company loss benefit which impacted the ETR by (11.3)%, (3.2)%, (1.8)% and (1.6)% respectively.
Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018
The decrease in the ETR was primarily due to $16 million of increased amortization of Excess ADIT not subject to normalization requirements and $12 million of increased favorable book/tax differences accounted for on a flow-through basis which impacted the ETR by (6.9)% and (4.8)%, respectively. Amortization of Excess ADIT not subject to normalization requirements for the nine months ended September 30, 2019 reflects the Tax Reform elements of the 2017 Indiana Base Rate Case approved by the IURC in May 2018.
OPCo
Three Months Ended September 30, 2019 Compared to Three Months Ended September 30, 2018
The increase in the ETR was primarily due to $35 million of decreased amortization of Excess ADIT not subject to normalization requirements and $1 million of decreased parent company loss benefit which impacted the ETR by 60% and 2%, respectively. Amortization of Excess ADIT not subject to amortization requirements decreased from the prior year primarily due to the discrete impact of the Ohio Tax Reform order which enabled OPCo to utilize $38 million of Excess ADIT not subject to rate normalization requirements to offset certain regulatory asset balances in the third quarter of 2018.
Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018
The increase in the ETR was primarily due to $24 million of decreased amortization of Excess ADIT not subject to normalization requirements which impacted the ETR by 10.8%. Amortization of Excess ADIT not subject to amortization requirements decreased from the prior year primarily due to the discrete impact of the Ohio Tax Reform order which enabled OPCo to utilize $38 million of Excess ADIT not subject to rate normalization requirements to offset certain regulatory asset balances in the third quarter of 2018.
PSO
Three Months Ended September 30, 2019 Compared to Three Months Ended September 30, 2018
The ETR remained comparable for the three months ended September 30, 2019 and 2018.
Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018
The decrease in the ETR was primarily due to $15 million of increased amortization of Excess ADIT not subject to normalization requirements which impacted the ETR by (6.8)%. Amortization of Excess ADIT not subject to normalization requirements for the nine months ended September 30, 2019 reflects the August 2018 OCC Tax Reform order as well as Tax Reform elements of the 2018 Oklahoma Base Rate Case approved by the OCC in March 2019.
SWEPCo
Three Months Ended September 30, 2019 Compared to Three Months Ended September 30, 2018
The decrease in the ETR was primarily due to $11 million of increased amortization of Excess ADIT not subject to normalization requirements which impacted the ETR by (9.7)%. Amortization of Excess ADIT not subject to normalization requirements for the nine months ended September 30, 2019 reflects Tax Reform elements incorporated in the Louisiana 2018 Formula Rate Filing as well as the Arkansas Tax Reform order issued by the APSC in September 2018.
Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018
The decrease in the ETR was primarily due to $15 million of increased amortization of Excess ADIT not subject to normalization requirements which impacted the ETR by (10.4)%. Amortization of Excess ADIT not subject to normalization requirements for the nine months ended September 30, 2019 reflects Tax Reform elements incorporated in the Louisiana 2018 Formula Rate Filing as well as the Arkansas Tax Reform order issued by the APSC in September 2018.
Federal and State Income Tax Audit Status
AEP and subsidiaries are no longer subject to U.S. federal examination by the IRS for all years through 2013. During the IRS examination of years 2011 through 2014, the statute of limitations for these years was extended to coincide with the examination of 2015. During the third quarter of 2019, AEP and subsidiaries elected to amend the 2014 and 2015 federal returns. Due toIn the amendmentfirst quarter of 2020, the IRS notified AEP that it was beginning an examination of these federalamended returns, including the 2014 andnet operating loss carryback to 2015 years will remain open for possiblethat originated in the 2017 return. The IRS examination formay examine only the amended items that were amended on the 2014 and 2015 federal returns.
The IRS examination of 2016 began in October 2018 and concluded in March 2019.
State Tax Legislation (Applies to AEP, AEPTCo, I&M and OPCo)
In April 2018, the Kentucky legislature enacted House Bill (H.B.) 487. H.B. 487 adopts mandatory unitary combined reporting for state corporate income tax purposes applicable for taxable years beginning on or after January 1, 2019. H.B. 487 also adopts the 80% federal net operating loss (NOL) limitation under Internal Revenue Code Sec. 172(a) for NOLs generated after January 1, 2018 and the federal unlimited carryforward period for unused NOLs generated after January 1, 2018. In addition, H.B. 366 was also enacted in April 2018, which among other things, replaces the graduated corporate tax rate structure with a flat 5% tax rate for business income and adopts a single-sales factor apportionment formula for apportioning a corporation’s business income to Kentucky. In the second quarter of 2018, AEP recorded an $18 million benefit to Income Tax Expense (Benefit) as a result of remeasuring Kentucky deferred taxes under a unitary filing group. The enacted legislation did not materially impact AEPTCo’s, I&M’s or OPCo’s net income.
12. LEASESFINANCING ACTIVITIES
The disclosures in this note apply to all Registrants, unless indicated otherwise.
The Registrants lease property, plant and equipment including, but not limited to, fleet, information technology and real estate leases.These leases require payments of non-lease components, including related property taxes, operating and maintenance costs. As of the adoption date of ASU 2016-02, management elected not to separate non-lease components from associated lease components in accordance with the accounting guidance for “Leases.” Many of these leases have purchase or renewal options. Leases not renewed are often replaced by other leases. Options to renew or purchase a lease are included in the measurement of lease assets and liabilities if it is reasonably certain the Registrant will exercise the option.
Lease obligations are measured using the discount rate implicit in the lease when that rate is readily determinable. When the implicit rate is not readily determinable, the Registrants measure their lease obligation using their estimated secured incremental borrowing rate. Incremental borrowing rates are comprised of an underlying risk free rate and a secured credit spread relative to the lessee on a matched maturity basis.
Lease rentals for both operating and finance leases are generally charged to Other Operation and Maintenance expense in accordance with rate-making treatment for regulated operations. Additionally, for regulated operations with finance leases, a finance lease asset and offsetting liability are recorded at the present value of the remaining lease payments for each reporting period. Finance leases for nonregulated property are accounted for as if the assets were owned and financed. The components of rental costs were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Three Months Ended September 30, 2019 | | AEP | | AEP Texas | | AEPTCo | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in millions) |
Operating Lease Cost | | $ | 64.4 |
| | $ | 4.0 |
| | $ | 0.6 |
| | $ | 4.9 |
| | $ | 23.7 |
| | $ | 4.9 |
| | $ | 1.5 |
| | $ | 1.8 |
|
Finance Lease Cost: | | | | | | | | | | | | | | | | |
Amortization of Right-of-Use Assets | | 16.5 |
| | 1.5 |
| | 0.1 |
| | 2.0 |
| | 1.6 |
| | 1.1 |
| | 0.8 |
| | 2.8 |
|
Interest on Lease Liabilities | | 4.1 |
| | 0.3 |
| | — |
| | 0.8 |
| | 0.8 |
| | 0.2 |
| | 0.1 |
| | 0.7 |
|
Total Lease Rental Costs (a) | | $ | 85.0 |
| | $ | 5.8 |
| | $ | 0.7 |
| | $ | 7.7 |
| | $ | 26.1 |
| | $ | 6.2 |
| | $ | 2.4 |
| | $ | 5.3 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Nine Months Ended September 30, 2019 | | AEP | | AEP Texas | | AEPTCo | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in millions) |
Operating Lease Cost | | $ | 200.3 |
| | $ | 12.2 |
| | $ | 1.7 |
| | $ | 14.5 |
| | $ | 70.0 |
| | $ | 13.8 |
| | $ | 5.0 |
| | $ | 5.7 |
|
Finance Lease Cost: | | | | | | | | | | | | | | | | |
Amortization of Right-of-Use Assets | | 45.0 |
| | 3.8 |
| | 0.1 |
| | 5.0 |
| | 4.2 |
| | 2.6 |
| | 2.2 |
| | 8.2 |
|
Interest on Lease Liabilities | | 12.2 |
| | 1.0 |
| | — |
| | 2.2 |
| | 2.3 |
| | 0.5 |
| | 0.4 |
| | 2.2 |
|
Total Lease Rental Costs (a) | | $ | 257.5 |
| | $ | 17.0 |
| | $ | 1.8 |
| | $ | 21.7 |
| | $ | 76.5 |
| | $ | 16.9 |
| | $ | 7.6 |
| | $ | 16.1 |
|
| |
(a) | Excludes variable and short-term lease costs, which were immaterial for the three and nine months ended September 30, 2019. |
Supplemental information related to leases are shown in the tables below:
|
| | | | | | | | | | | | | | | | | | | | | | | | |
September 30, 2019 | | AEP | | AEP Texas | | AEPTCo | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
Weighted-Average Remaining Lease Term (years): | | | | | | | | | | | | | | | | |
Operating Leases | | 5.31 |
| | 7.05 |
| | 2.43 |
| | 6.25 |
| | 4.05 |
| | 8.10 |
| | 7.06 |
| | 6.63 |
|
Finance Leases | | 5.87 |
| | 6.86 |
| | 0.58 |
| | 6.33 |
| | 6.72 |
| | 6.58 |
| | 6.24 |
| | 5.34 |
|
Weighted-Average Discount Rate: | | | | | | | | | | | | | | | | |
Operating Leases | | 3.61 | % | | 3.79 | % | | 3.13 | % | | 3.67 | % | | 3.45 | % | | 3.79 | % | | 3.68 | % | | 3.80 | % |
Finance Leases | | 6.02 | % | | 4.71 | % | | 9.33 | % | �� | 8.19 | % | | 8.61 | % | | 4.66 | % | | 4.73 | % | | 5.03 | % |
Reverse Stock Split (Applies to SWEPCo) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Nine Months Ended September 30, 2019 | | AEP | | AEP Texas | | AEPTCo | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in millions) |
Cash paid for amounts included in the measurement of lease liabilities: | | | | | | | | | | | | | | | | |
Operating Cash Flows Used for Operating Leases | | $ | 163.6 |
| | $ | 11.4 |
| | $ | 1.7 |
| | $ | 14.1 |
| | $ | 52.5 |
| | $ | 13.8 |
| | $ | 4.9 |
| | $ | 5.3 |
|
Operating Cash Flows Used for Finance Leases | | 11.0 |
| | 1.0 |
| | — |
| | 2.2 |
| | 2.2 |
| | 0.5 |
| | 0.4 |
| | 1.1 |
|
Financing Cash Flows Used for Finance Leases | | 44.5 |
| | 3.8 |
| | — |
| | 5.0 |
| | 4.0 |
| | 2.6 |
| | 2.2 |
| | 8.1 |
|
| | | | | | | | | | | | | | | | |
Non-cash Acquisitions Under Operating Leases | | $ | 108.9 |
| | $ | 12.7 |
| | $ | — |
| | $ | 8.6 |
| | $ | 16.6 |
| | $ | 34.6 |
| | $ | 7.3 |
| | $ | 10.6 |
|
The following tables show the property, plant and equipment under finance leases and noncurrent assets under operating leases and related obligations recorded on the Registrants’ balance sheets. Unless shown as a separate line on the balance sheets due to materiality, net operating lease assets are included in Deferred Charges and Other Noncurrent Assets, current finance lease obligations are included in Other Current Liabilities and long-term finance lease obligations are included in Deferred Credits and Other Noncurrent Liabilities on the Registrants’ balance sheets. Lease obligations are not recognized on the balance sheets for lease agreements with a lease term of less than twelve months.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
September 30, 2019 | | AEP | | AEP Texas | | AEPTCo | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in millions) |
Property, Plant and Equipment Under Finance Leases: | | | | | | | | | | | | | | | | |
Generation | | $ | 134.9 |
| | $ | — |
| | $ | — |
| | $ | 41.3 |
| | $ | 28.5 |
| | $ | — |
| | $ | 2.6 |
| | $ | 34.2 |
|
Other Property, Plant and Equipment | | 335.9 |
| | 41.9 |
| | 0.2 |
| | 18.4 |
| | 37.1 |
| | 24.7 |
| | 20.7 |
| | 50.0 |
|
Total Property, Plant and Equipment | | 470.8 |
| | 41.9 |
| | 0.2 |
| | 59.7 |
| | 65.6 |
| | 24.7 |
| | 23.3 |
| | 84.2 |
|
Accumulated Amortization | | 162.7 |
| | 10.9 |
| | 0.2 |
| | 17.8 |
| | 22.8 |
| | 6.6 |
| | 9.1 |
| | 26.2 |
|
Net Property, Plant and Equipment Under Finance Leases | | $ | 308.1 |
| | $ | 31.0 |
| | $ | — |
| | $ | 41.9 |
| | $ | 42.8 |
| | $ | 18.1 |
| | $ | 14.2 |
| | $ | 58.0 |
|
| | | | | | | | | | | | | | | | |
Obligations Under Finance Leases: | | | | | | | | | | | | | | | | |
Noncurrent Liability | | $ | 254.0 |
| | $ | 25.8 |
| | $ | — |
| | $ | 35.2 |
| | $ | 37.1 |
| | $ | 14.5 |
| | $ | 11.0 |
| | $ | 50.5 |
|
Liability Due Within One Year | | 61.4 |
| | 5.2 |
| | — |
| | 6.7 |
| | 6.0 |
| | 3.6 |
| | 3.2 |
| | 11.2 |
|
Total Obligations Under Finance Leases | | $ | 315.4 |
| | $ | 31.0 |
| | $ | — |
| | $ | 41.9 |
| | $ | 43.1 |
| | $ | 18.1 |
| | $ | 14.2 |
| | $ | 61.7 |
|
In August 2020, SWEPCo executed a reverse stock split with each 2,048 shares of common stock issued and outstanding being combined into 1 share of common stock. The common stock of SWEPCo is wholly-owned by Parent.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
September 30, 2019 | | AEP | | AEP Texas | | AEPTCo | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in millions) |
Operating Lease Assets | | $ | 990.0 |
| | $ | 82.0 |
| | $ | 4.6 |
| | $ | 79.4 |
| | $ | 295.3 |
| | $ | 88.2 |
| | $ | 37.1 |
| | $ | 40.8 |
|
| | | | | | | | | | | | | | | | |
Obligations Under Operating Leases: | | | | | | | | | | | | | | | | |
Noncurrent Liability | | $ | 801.1 |
| | $ | 71.1 |
| | $ | 2.2 |
| | $ | 64.8 |
| | $ | 234.0 |
| | $ | 75.9 |
| | $ | 31.2 |
| | $ | 32.5 |
|
Liability Due Within One Year | | 228.8 |
| | 11.7 |
| | 2.3 |
| | 15.3 |
| | 82.0 |
| | 12.8 |
| | 6.0 |
| | 5.9 |
|
Total Obligations Under Operating Leases | | $ | 1,029.9 |
| | $ | 82.8 |
| | $ | 4.5 |
| | $ | 80.1 |
| | $ | 316.0 |
| | $ | 88.7 |
| | $ | 37.2 |
| | $ | 38.4 |
|
Future minimum lease payments as of September 30, 2019 are presented on a rolling 12-month basis as shown in the tables below:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Finance Leases | | AEP | | AEP Texas | | AEPTCo | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in millions) |
Year 1 | | $ | 76.8 |
| | $ | 6.6 |
| | $ | — |
| | $ | 9.6 |
| | $ | 9.0 |
| | $ | 4.3 |
| | $ | 3.8 |
| | $ | 13.0 |
|
Year 2 | | 67.0 |
| | 6.1 |
| | — |
| | 8.8 |
| | 8.2 |
| | 3.9 |
| | 3.1 |
| | 11.6 |
|
Year 3 | | 58.0 |
| | 5.3 |
| | — |
| | 8.1 |
| | 7.6 |
| | 3.2 |
| | 2.3 |
| | 10.6 |
|
Year 4 | | 49.0 |
| | 4.9 |
| | — |
| | 7.5 |
| | 7.1 |
| | 2.5 |
| | 2.1 |
| | 9.5 |
|
Year 5 | | 50.0 |
| | 4.1 |
| | — |
| | 7.0 |
| | 6.7 |
| | 2.1 |
| | 1.7 |
| | 14.8 |
|
Later Years | | 76.1 |
| | 9.8 |
| | — |
| | 11.3 |
| | 20.9 |
| | 5.3 |
| | 3.7 |
| | 7.5 |
|
Total Future Minimum Lease Payments | | 376.9 |
| | 36.8 |
| | — |
| | 52.3 |
| | 59.5 |
| | 21.3 |
| | 16.7 |
| | 67.0 |
|
Less Imputed Interest | | 61.5 |
| | 5.8 |
| | — |
| | 10.4 |
| | 16.4 |
| | 3.2 |
| | 2.5 |
| | 5.3 |
|
Estimated Present Value of Future Minimum Lease Payments | | $ | 315.4 |
| | $ | 31.0 |
| | $ | — |
| | $ | 41.9 |
| | $ | 43.1 |
| | $ | 18.1 |
| | $ | 14.2 |
| | $ | 61.7 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Operating Leases | | AEP | | AEP Texas | | AEPTCo | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in millions) |
Year 1 | | $ | 267.5 |
| | $ | 15.7 |
| | $ | 2.4 |
| | $ | 18.4 |
| | $ | 92.2 |
| | $ | 16.6 |
| | $ | 7.4 |
| | $ | 8.4 |
|
Year 2 | | 252.4 |
| | 15.2 |
| | 1.5 |
| | 16.4 |
| | 88.4 |
| | 13.9 |
| | 6.6 |
| | 8.2 |
|
Year 3 | | 239.9 |
| | 14.1 |
| | 0.7 |
| | 14.7 |
| | 86.3 |
| | 13.3 |
| | 6.0 |
| | 7.5 |
|
Year 4 | | 154.2 |
| | 13.0 |
| | 0.3 |
| | 12.5 |
| | 48.0 |
| | 12.4 |
| | 5.5 |
| | 7.2 |
|
Year 5 | | 63.6 |
| | 11.4 |
| | — |
| | 9.8 |
| | 7.3 |
| | 10.8 |
| | 5.0 |
| | 5.0 |
|
Later Years | | 184.1 |
| | 27.8 |
| | — |
| | 20.1 |
| | 22.0 |
| | 38.3 |
| | 12.7 |
| | 12.4 |
|
Total Future Minimum Lease Payments | | 1,161.7 |
| | 97.2 |
| | 4.9 |
| | 91.9 |
| | 344.2 |
| | 105.3 |
| | 43.2 |
| | 48.7 |
|
Less Imputed Interest | | 131.8 |
| | 14.4 |
| | 0.4 |
| | 11.8 |
| | 28.2 |
| | 16.6 |
| | 6.0 |
| | 10.3 |
|
Estimated Present Value of Future Minimum Lease Payments | | $ | 1,029.9 |
| | $ | 82.8 |
| | $ | 4.5 |
| | $ | 80.1 |
| | $ | 316.0 |
| | $ | 88.7 |
| | $ | 37.2 |
| | $ | 38.4 |
|
Future minimum lease payments consisted of the following as of December 31, 2018:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Finance Leases | | AEP | | AEP Texas | | AEPTCo | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in millions) |
2019 | | $ | 70.8 |
| | $ | 5.8 |
| | $ | 0.1 |
| | $ | 9.0 |
| | $ | 8.2 |
| | $ | 3.3 |
| | $ | 3.4 |
| | $ | 13.1 |
|
2020 | | 60.2 |
| | 5.3 |
| | — |
| | 8.0 |
| | 7.2 |
| | 2.7 |
| | 2.6 |
| | 11.5 |
|
2021 | | 51.7 |
| | 4.7 |
| | — |
| | 7.3 |
| | 6.6 |
| | 2.3 |
| | 2.0 |
| | 10.5 |
|
2022 | | 43.8 |
| | 4.2 |
| | — |
| | 6.8 |
| | 6.1 |
| | 1.7 |
| | 1.6 |
| | 9.4 |
|
2023 | | 35.5 |
| | 3.7 |
| | — |
| | 6.3 |
| | 5.7 |
| | 1.2 |
| | 1.4 |
| | 8.6 |
|
Later Years | | 90.2 |
| | 10.1 |
| | — |
| | 13.3 |
| | 21.7 |
| | 2.8 |
| | 3.3 |
| | 18.7 |
|
Total Future Minimum Lease Payments | | 352.2 |
| | 33.8 |
| | 0.1 |
| | 50.7 |
| | 55.5 |
| | 14.0 |
| | 14.3 |
| | 71.8 |
|
Less Imputed Interest | | 63.2 |
| | 5.3 |
| | — |
| | 10.9 |
| | 16.8 |
| | 1.9 |
| | 2.0 |
| | 11.0 |
|
Estimated Present Value of Future Minimum Lease Payments | | $ | 289.0 |
| | $ | 28.5 |
| | $ | 0.1 |
| | $ | 39.8 |
| | $ | 38.7 |
| | $ | 12.1 |
| | $ | 12.3 |
| | $ | 60.8 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Operating Leases | | AEP | | AEP Texas | | AEPTCo | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in millions) |
2019 | | $ | 259.6 |
| | $ | 15.1 |
| | $ | 2.3 |
| | $ | 17.6 |
| | $ | 92.6 |
| | $ | 14.5 |
| | $ | 6.5 |
| | $ | 7.4 |
|
2020 | | 250.1 |
| | 14.1 |
| | 1.8 |
| | 16.5 |
| | 89.3 |
| | 13.2 |
| | 6.0 |
| | 7.2 |
|
2021 | | 232.7 |
| | 13.2 |
| | 1.0 |
| | 13.9 |
| | 84.8 |
| | 10.9 |
| | 5.0 |
| | 6.7 |
|
2022 | | 222.5 |
| | 12.2 |
| | 0.5 |
| | 12.8 |
| | 83.8 |
| | 10.0 |
| | 4.6 |
| | 6.1 |
|
2023 | | 58.3 |
| | 10.8 |
| | 0.1 |
| | 9.9 |
| | 6.5 |
| | 8.8 |
| | 4.1 |
| | 5.0 |
|
Later Years | | 165.2 |
| | 28.4 |
| | — |
| | 20.5 |
| | 19.5 |
| | 31.7 |
| | 10.7 |
| | 11.7 |
|
Total Future Minimum Lease Payments | | $ | 1,188.4 |
| | $ | 93.8 |
| | $ | 5.7 |
| | $ | 91.2 |
| | $ | 376.5 |
| | $ | 89.1 |
| | $ | 36.9 |
| | $ | 44.1 |
|
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, 2019, 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 | | $ | 46.6 |
|
AEP Texas | | 11.2 |
|
APCo | | 6.3 |
|
I&M | | 4.0 |
|
OPCo | | 7.4 |
|
PSO | | 4.3 |
|
SWEPCo | | 4.7 |
|
Rockport Lease (Applies to AEP and I&M)
AEGCo and I&M entered into a sale-and-leaseback transaction in 1989 with Wilmington Trust Company (Owner Trustee), an unrelated, unconsolidated trustee for Rockport Plant, Unit 2 (the Plant). The Owner Trustee was capitalized with equity from six owner participants with no relationship to AEP or any of its subsidiaries and debt from a syndicate of banks and securities in a private placement to certain institutional investors. In the first quarter of 2019, in accordance with ASU 2016-02, the $37 million unamortized gain ($15 million related to I&M) associated with the sale-and-leaseback of the Plant was recognized as an adjustment to equity. The adjustment to equity was then reclassified to regulatory liabilities in accordance with accounting guidance for “Regulated Operations” as AEGCo and I&M will continue to provide the benefit of the unamortized gain to customers in future periods.
The Owner Trustee owns the Plant and leases equal portions to AEGCo and I&M. The lease is accounted for as an operating lease with the payment obligations included in the future minimum lease payments schedule earlier in this note. The lease term is for 33 years and at the end of the lease term, AEGCo and I&M have the option to renew the lease at a rate that approximates fair value. The option to renew was not included in the measurement of the lease obligation as of September 30, 2019 as the execution of the option was not reasonably certain. AEP, AEGCo and I&M have no ownership interest in the Owner Trustee and do not guarantee its debt. The future minimum lease payments for this sale-and-leaseback transaction as of September 30, 2019 were as follows:
|
| | | | | | | | |
Future Minimum Lease Payments | | AEP (a) | | I&M |
| | (in millions) |
2019 | | $ | 74.2 |
| | $ | 37.1 |
|
2020 | | 147.8 |
| | 73.9 |
|
2021 | | 147.8 |
| | 73.9 |
|
2022 | | 147.2 |
| | 73.6 |
|
Total Future Minimum Lease Payments | | $ | 517.0 |
| | $ | 258.5 |
|
| |
(a) | AEP’s future minimum lease payments include equal shares from AEGCo and I&M. |
AEPRO Boat and Barge Leases (Applies to AEP)
In 2015, AEP sold its commercial barge transportation subsidiary, AEPRO, to a nonaffiliated party. Certain boat and barge leases acquired by the nonaffiliated party are subject to an AEP guarantee in favor of the lessor, ensuring future payments under such leases with maturities up to 2027. As of September 30, 2019, the maximum potential amount of future payments required under the guaranteed leases was $56 million. In certain instances, AEP has no recourse against the nonaffiliated party if required to pay a lessor under a guarantee, but AEP would have access to sell the leased assets in order to recover payments made by AEP under the guarantee. As of September 30, 2019, AEP’s boat and barge lease guarantee liability was $4 million, of which $1 million was recorded in Other Current Liabilities and $3 million was recorded in Deferred Credits and Other Noncurrent Liabilities on AEP’s balance sheet.
In January 2018, S&P Global Inc. downgraded the ratings of the nonaffiliated party and set their outlook to negative. In April 2018, Moody’s Investors Service Inc. (Moody’s) also downgraded their rating and set their outlook to negative. Moody’s further downgraded their rating in April 2019 and maintained a negative outlook. It is reasonably possible that enforcement of AEP’s liability for future payments under these leases could be exercised, which could reduce future net income and cash flows and impact financial condition.
Lessor Activity
The Registrants’ lessor activity was immaterial as of and for the three and nine months ended September 30, 2019.
13. FINANCING ACTIVITIES
The disclosures in this note apply to all Registrants, unless indicated otherwise.
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 | | September 30, 2020 | | December 31, 2019 |
| | (in millions) | | |
Senior Unsecured Notes | | $ | 24,125.4 | | | $ | 21,180.7 | |
Pollution Control Bonds | | 1,936.1 | | | 1,998.8 | |
Notes Payable | | 161.3 | | | 234.3 | |
Securitization Bonds | | 751.6 | | | 1,025.1 | |
Spent Nuclear Fuel Obligation (a) | | 281.1 | | | 279.8 | |
Junior Subordinated Notes (b) | | 1,622.1 | | | 787.8 | |
Other Long-term Debt | | 1,189.5 | | | 1,219.0 | |
Total Long-term Debt Outstanding | | 30,067.1 | | | 26,725.5 | |
Long-term Debt Due Within One Year | | 1,911.6 | | | 1,598.7 | |
Long-term Debt | | $ | 28,155.5 | | | $ | 25,126.8 | |
|
| | | | | | | | |
Type of Debt | | September 30, 2019 | | December 31, 2018 |
| | (in millions) |
Senior Unsecured Notes | | $ | 20,829.2 |
| | $ | 18,903.3 |
|
Pollution Control Bonds | | 1,516.5 |
| | 1,643.8 |
|
Notes Payable | | 189.1 |
| | 204.7 |
|
Securitization Bonds | | 1,059.4 |
| | 1,111.4 |
|
Spent Nuclear Fuel Obligation (a) | | 278.5 |
| | 273.6 |
|
Junior Subordinated Notes (b) | | 786.8 |
| | — |
|
Other Long-term Debt | | 1,221.7 |
| | 1,209.9 |
|
Total Long-term Debt Outstanding | | 25,881.2 |
| | 23,346.7 |
|
Long-term Debt Due Within One Year | | 1,327.7 |
| | 1,698.5 |
|
Long-term Debt | | $ | 24,553.5 |
| | $ | 21,648.2 |
|
(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 $326 million and $323 million as of September 30, 2020 and December 31, 2019, respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets.
(b)See “Equity Units” section below for additional information.
| |
(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 $322 million and $317 million as of September 30, 2019 and December 31, 2018, respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets. |
| |
(b) | See “Equity Units” section below 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 20192020 are shown in the following tables:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Principal | | Interest | | |
Company | | Type of Debt | | Amount (a) | | Rate | | Due Date |
Issuances: | | | | (in millions) | | (%) | | |
AEP | | Junior Subordinated Notes (b) | | $ | 850.0 | | | 1.30 | | 2025 |
AEP | | Senior Unsecured Notes | | 400.0 | | | 2.30 | | 2030 |
AEP | | Senior Unsecured Notes | | 400.0 | | | 3.25 | | 2050 |
AEP Texas | | Pollution Control Bonds | | 60.0 | | | 0.90 | | 2023 |
AEP Texas | | Senior Unsecured Notes | | 600.0 | | | 2.10 | | 2030 |
AEPTCo | | Senior Unsecured Notes | | 525.0 | | | 3.65 | | 2050 |
APCo | | Pollution Control Bonds | | 65.4 | | | 1.00 | | 2025 |
APCo | | Senior Unsecured Notes | | 500.0 | | | 3.70 | | 2050 |
OPCo | | Senior Unsecured Notes | | 350.0 | | | 2.60 | | 2030 |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Non-Registrant: | | | | | | | | |
KPCo | | Other Long-term Debt | | 125.0 | | | Variable | | 2022 |
Transource Energy | | Other Long-term Debt | | 4.4 | | | Variable | | 2020 |
Transource Energy | | Other Long-term Debt | | 7.1 | | | Variable | | 2023 |
Transource Energy | | Senior Unsecured Notes | | 150.0 | | | 2.75 | | 2050 |
Total Issuances | | | | $ | 4,036.9 | | | | | |
|
| | | | | | | | | | |
| | | | Principal | | Interest | | |
Company | | Type of Debt | | Amount (a) | | Rate | | Due Date |
Issuances: | | | | (in millions) | | (%) | | |
AEP | | Junior Subordinated Notes (b) | | $ | 805.0 |
| | 3.40 | | 2024 |
AEP Texas | | Securitization Bonds | | 117.6 |
| | 2.06 | | 2025 |
AEP Texas | | Securitization Bonds | | 117.6 |
| | 2.29 | | 2029 |
AEP Texas | | Pollution Control Bonds | | 100.6 |
| | 2.60 | | 2029 |
AEP Texas | | Senior Unsecured Notes | | 300.0 |
| | 4.15 | | 2049 |
AEPTCo | | Senior Unsecured Notes | | 350.0 |
| | 3.80 | | 2049 |
AEPTCo | | Senior Unsecured Notes | | 350.0 |
| | 3.15 | | 2049 |
APCo | | Pollution Control Bonds | | 86.0 |
| | 2.55 | | 2024 |
APCo | | Senior Unsecured Notes | | 400.0 |
| | 4.50 | | 2049 |
I&M | | Notes Payable | | 62.8 |
| | Variable | | 2023 |
OPCo | | Senior Unsecured Notes | | 450.0 |
| | 4.00 | | 2049 |
PSO | | Senior Unsecured Notes | | 100.0 |
| | 3.91 | | 2029 |
PSO | | Senior Unsecured Notes | | 150.0 |
| | 4.11 | | 2034 |
PSO | | Senior Unsecured Notes | | 100.0 |
| | 4.50 | | 2049 |
| | | | | | | | |
Non-Registrant: | | | | | | | | |
AEGCo | | Pollution Control Bonds | | 45.0 |
| | 1.35 | | 2022 |
Transource Energy | | Other Long-term Debt | | 14.4 |
| | Variable | | 2020 |
Total Issuances | | | | $ | 3,549.0 |
| |
| |
|
| |
(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. |
| |
(b) | See “Equity Units” section below for additional information. |
|
| | | | | | | | | | |
| | | | Principal | | Interest | | |
Company | | Type of Debt | | Amount Paid | | Rate | | Due Date |
Retirements and Principal Payments: | | | | (in millions) | | (%) | | |
AEP Texas | | Senior Unsecured Notes | | $ | 50.0 |
| | 2.61 | | 2019 |
AEP Texas | | Securitization Bonds | | 28.2 |
| | 1.98 | | 2020 |
AEP Texas | | Securitization Bonds | | 188.0 |
| | 5.31 | | 2020 |
AEP Texas | | Pollution Control Bonds | | 100.6 |
| | 6.30 | | 2029 |
APCo | | Pollution Control Bonds | | 86.0 |
| | 1.90 | | 2019 |
APCo | | Pollution Control Bonds | | 70.0 |
| | 3.25 | | 2019 |
APCo | | Securitization Bonds | | 24.4 |
| | 2.01 | | 2023 |
I&M | | Notes Payable | | 2.7 |
| | Variable | | 2019 |
I&M | | Notes Payable | | 4.3 |
| | Variable | | 2019 |
I&M | | Notes Payable | | 13.7 |
| | Variable | | 2020 |
I&M | | Notes Payable | | 17.9 |
| | Variable | | 2021 |
I&M | | Notes Payable | | 11.3 |
| | Variable | | 2022 |
I&M | | Notes Payable | | 16.0 |
| | Variable | | 2022 |
I&M | | Notes Payable | | 6.4 |
| | Variable | | 2023 |
I&M | | Other Long-term Debt | | 1.3 |
| | 6.00 | | 2025 |
OPCo | | Securitization Bonds | | 47.9 |
| | 2.05 | | 2019 |
OPCo | | Other Long-term Debt | | 0.1 |
| | 1.15 | | 2028 |
PSO | | Senior Unsecured Notes | | 250.0 |
| | 5.15 | | 2019 |
PSO | | Other Long-term Debt | | 0.4 |
| | 3.00 | | 2027 |
SWEPCo | | Pollution Control Bonds | | 53.5 |
| | 1.60 | | 2019 |
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 |
| | Variable | | 2019 |
AEP Energy | | Notes Payable | | 0.1 |
| | 5.75 | | 2019 |
Transource Energy | | Other Long-term Debt | | 1.0 |
| | Variable | | 2020 |
Total Retirements and Principal Payments | | | | $ | 1,023.5 |
| | | | |
(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.
As of September 30, 2019, trustees held, on behalf of AEP, $574 million of their reacquired Pollution Control Bonds. Of this total, $345 million relates to OPCo.(b)See “Equity Units” section below for additional information.
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Principal | | Interest | | |
Company | | Type of Debt | | Amount Paid | | Rate | | Due Date |
Retirements and Principal Payments: | | | | (in millions) | | (%) | | |
AEP Texas | | Pollution Control Bonds | | $ | 50.6 | | | 4.45 | | 2020 |
AEP Texas | | Securitization Bonds | | 28.7 | | | 1.98 | | 2020 |
AEP Texas | | Securitization Bonds | | 202.6 | | | 5.31 | | 2020 |
AEP Texas | | Pollution Control Bonds | | 60.0 | | | 1.75 | | 2020 |
AEP Texas | | Securitization Bonds | | 0.2 | | | 2.85 | | 2024 |
AEP Texas | | Securitization Bonds | | 14.4 | | | 2.06 | | 2025 |
| | | | | | | | |
| | | | | | | | |
APCo | | Pollution Control Bonds | | 65.4 | | | 1.70 | | 2020 |
APCo | | Securitization Bonds | | 24.9 | | | 2.01 | | 2023 |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
I&M | | Notes Payable | | 2.0 | | | Variable | | 2020 |
I&M | | Notes Payable | | 4.6 | | | Variable | | 2021 |
I&M | | Notes Payable | | 14.9 | | | Variable | | 2022 |
I&M | | Notes Payable | | 11.4 | | | Variable | | 2022 |
I&M | | Notes Payable | | 18.7 | | | Variable | | 2023 |
I&M | | Notes Payable | | 18.2 | | | Variable | | 2024 |
I&M | | Other Long-term Debt | | 1.3 | | | 6.00 | | 2025 |
| | | | | | | | |
OPCo | | Other Long-term Debt | | 0.1 | | | 1.15 | | 2028 |
PSO | | Pollution Control Bonds | | 12.7 | | | 4.45 | | 2020 |
PSO | | Other Long-term Debt | | 0.3 | | | 3.00 | | 2027 |
| | | | | | | | |
| | | | | | | | |
SWEPCo | | Other Long-term Debt | | 15.0 | | | Variable | | 2020 |
SWEPCo | | Other Long-term Debt | | 1.5 | | | 4.68 | | 2028 |
SWEPCo | | Notes Payable | | 3.2 | | | 4.58 | | 2032 |
| | | | | | | | |
Non-Registrant: | | | | | | | | |
| | | | | | | | |
Transource Energy | | Other Long-term Debt | | 148.6 | | | Variable | | 2023 |
Transource Energy | | Senior Unsecured Notes | | 1.2 | | | 2.75 | | 2050 |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Total Retirements and Principal Payments | | | | $ | 700.5 | | | | | |
Long-term Debt Subsequent Events
In October 2019, AEP remarketed $240 million of Pollution Control Bonds that were held in trust.
In October 2019,2020, I&M retired $4issued $70 million of Notes Payable related to DCC Fuel.
In October 2019,2020, I&M retired $25$5 million of variable rate Pollution Control Bonds.Notes Payable related to DCC Fuel.
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 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 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 recent 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 settles after three years in 2022. The notes are expected to be remarketed in 2022, 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 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 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 $99.58: 0.5021 shares per contract.
•If the 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, the $805 million of notes were recorded within Long-term Debt on the balance sheets. The present value of the purchase contract payments of $62 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 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 the treasury stock method. The maximum amount of shares AEP will be required to issue to settle the purchase contract is 9,701,860 shares (subject to an anti-dilution adjustment).
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%0.9% of consolidated tangible net assets as of September 30, 2019.2020. 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 restriction that prohibits the payment of dividends out of capital accounts without regulatory approval; payment of dividends is allowed out of retained earnings only. However, theThe 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 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, 20192020 and December 31, 20182019 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, 20192020 are described in the following table:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Maximum | | | | Average | | | | Net Loans to | | | |
| | Borrowings | | Maximum | | Borrowings | | Average | | (Borrowings) from | | Authorized | |
| | from the | | Loans to the | | from the | | Loans to the | | the Utility Money | | Short-term | |
| | Utility | | Utility | | Utility | | Utility | | Pool as of | | Borrowing | |
Company | | Money Pool | | Money Pool | | Money Pool | | Money Pool | | September 30, 2020 | | Limit | |
| | (in millions) | | | | | | | | | | | |
AEP Texas | | $ | 320.4 | | | $ | 313.4 | | | $ | 154.7 | | | $ | 167.4 | | | $ | 141.3 | | | $ | 500.0 | | |
AEPTCo | | 358.4 | | | 259.7 | | | 112.7 | | | 59.1 | | | (84.3) | | | 820.0 | | (a) |
APCo | | 434.3�� | | | 189.0 | | | 274.8 | | | 74.6 | | | 155.2 | | | 500.0 | | |
I&M | | 218.6 | | | 13.4 | | | 115.3 | | | 13.3 | | | (145.8) | | | 500.0 | | |
OPCo | | 353.9 | | | 32.8 | | | 158.3 | | | 25.2 | | | (215.9) | | | 500.0 | | |
PSO | | 125.4 | | | 57.1 | | | 64.6 | | | 28.4 | | | (77.8) | | | 300.0 | | |
SWEPCo | | 178.9 | | | 0 | | | 113.6 | | | 0 | | | (71.8) | | | 350.0 | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | Maximum | | | | Average | | | | Net Loans to | | | |
| | Borrowings | | Maximum | | Borrowings | | Average | | (Borrowings from) | | Authorized | |
| | from the | | Loans to the | | from the | | Loans to the | | the Utility Money | | Short-term | |
| | Utility | | Utility | | Utility | | Utility | | Pool as of | | Borrowing | |
Company | | Money Pool | | Money Pool | | Money Pool | | Money Pool | | September 30, 2019 | | Limit | |
| | (in millions) |
AEP Texas | | $ | 390.7 |
| | $ | — |
| | $ | 261.8 |
| | $ | — |
| | $ | (74.8 | ) | | $ | 500.0 |
| |
AEPTCo | | 374.9 |
| | 244.4 |
| | 179.8 |
| | 40.2 |
| | 236.6 |
| | 795.0 |
| (a) |
APCo | | 225.4 |
| | 232.2 |
| | 90.4 |
| | 61.8 |
| | (17.7 | ) | | 600.0 |
| |
I&M | | 120.4 |
| | 66.0 |
| | 53.1 |
| | 17.2 |
| | (89.2 | ) | | 500.0 |
| |
OPCo | | 291.2 |
| | 178.6 |
| | 163.5 |
| | 50.1 |
| | (17.6 | ) | | 500.0 |
| |
PSO | | 140.5 |
| | 215.6 |
| | 63.9 |
| | 84.1 |
| | 95.1 |
| | 300.0 |
| |
SWEPCo | | 105.1 |
| | 81.4 |
| | 57.8 |
| | 11.2 |
| | 6.4 |
| | 350.0 |
| |
(a) Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions.
| |
(a) | 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, 20192020 and December 31, 20182019 are included in Advances to Affiliates on the subsidiaries’ balance sheets. The Nonutility Money Pool participants’ activity for the nine months ended September 30, 20192020 is described in the following table:
| | | | | | | | | | | | | | | | | | | | |
| | Maximum Loans | | Average Loans | | Loans to the Nonutility |
| | to the Nonutility | | to the Nonutility | | Money Pool as of |
Company | | Money Pool | | Money Pool | | September 30, 2020 |
| (in millions) | | | | | |
AEP Texas | | $ | 7.5 | | | $ | 7.1 | | | $ | 7.1 | |
SWEPCo | | 2.1 | | | 2.1 | | | 2.1 | |
|
| | | | | | | | | | | | |
| | Maximum Loans | | Average Loans | | Loans to the Nonutility |
| | to the Nonutility | | to the Nonutility | | Money Pool as of |
Company | | Money Pool | | Money Pool | | September 30, 2019 |
| (in millions) |
AEP Texas | | $ | 8.0 |
| | $ | 7.7 |
| | $ | 7.7 |
|
SWEPCo | | 2.1 |
| | 2.0 |
| | 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, 20192020 and December 31, 20182019 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, 20192020 are described in the following table:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Maximum | | Maximum | | Average | | Average | | Borrowings from | | Loans to | | Authorized | |
Borrowings | | Loans | | Borrowings | | Loans | | AEP as of | | AEP as of | | Short-term | |
from AEP | | to AEP | | from AEP | | to AEP | | September 30, 2020 | | September 30, 2020 | | Borrowing Limit | |
(in millions) | | | | | | | | | | | | | |
$ | 1.4 | | | $ | 195.8 | | | $ | 1.3 | | | $ | 128.7 | | | $ | 1.2 | | | $ | 105.4 | | | $ | 50.0 | | (a) |
(a) Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
Maximum | | Maximum | | Average | | Average | | Borrowings from | | Loans to | | Authorized | |
Borrowings | | Loans | | Borrowings | | Loans | | AEP as of | | AEP as of | | Short-term | |
from AEP | | to AEP | | from AEP | | to AEP | | September 30, 2019 | | September 30, 2019 | | Borrowing Limit | |
(in millions) |
$ | 1.3 |
| | $ | 117.6 |
| | $ | 1.3 |
| | $ | 63.4 |
| | $ | 1.3 |
| | $ | 30.8 |
| | $ | 75.0 |
| (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, | | |
| | 2020 | | 2019 |
Maximum Interest Rate | | 2.70 | % | | 3.43 | % |
Minimum Interest Rate | | 0.33 | % | | 1.83 | % |
|
| | | | | | |
| | Nine Months Ended September 30, |
| | 2019 | | 2018 |
Maximum Interest Rate | | 3.43 | % | | 2.52 | % |
Minimum Interest Rate | | 1.83 | % | | 1.81 | % |
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 | | |
| | Borrowed from the Utility Money Pool | | | | Loaned to the Utility Money Pool | | |
| | for Nine Months Ended September 30, | | | | for Nine Months Ended September 30, | | |
Company | | 2020 | | 2019 | | 2020 | | 2019 |
AEP Texas | | 1.55 | % | | 2.71 | % | | 0.87 | % | | 0 | % |
AEPTCo | | 1.63 | % | | 2.72 | % | | 2.00 | % | | 2.57 | % |
APCo | | 2.14 | % | | 2.82 | % | | 0.99 | % | | 2.73 | % |
I&M | | 1.30 | % | | 2.56 | % | | 1.44 | % | | 2.73 | % |
OPCo | | 1.32 | % | | 2.80 | % | | 2.06 | % | | 2.68 | % |
PSO | | 1.24 | % | | 2.85 | % | | 1.95 | % | | 2.48 | % |
SWEPCo | | 1.55 | % | | 2.74 | % | | 0 | % | | 2.47 | % |
|
| | | | | | | | | | | | |
| | Average Interest Rate for Funds | | Average Interest Rate for Funds |
| | Borrowed from the Utility Money Pool | | Loaned to the Utility Money Pool |
| | for Nine Months Ended September 30, | | for Nine Months Ended September 30, |
Company | | 2019 | | 2018 | | 2019 | | 2018 |
AEP Texas | | 2.71 | % | | 2.25 | % | | — | % | | 2.29 | % |
AEPTCo | | 2.72 | % | | 2.26 | % | | 2.57 | % | | 2.04 | % |
APCo | | 2.82 | % | | 2.22 | % | | 2.73 | % | | 2.19 | % |
I&M | | 2.56 | % | | 2.16 | % | | 2.73 | % | | 2.06 | % |
OPCo | | 2.80 | % | | 2.18 | % | | 2.68 | % | | 2.47 | % |
PSO | | 2.85 | % | | 2.25 | % | | 2.48 | % | | 1.86 | % |
SWEPCo | | 2.74 | % | | 2.31 | % | | 2.47 | % | | 1.87 | % |
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, 2020 | | | | | | Nine Months Ended September 30, 2019 | | | | |
| | Maximum | | Minimum | | Average | | Maximum | | Minimum | | Average |
| | Interest Rate | | Interest Rate | | Interest Rate | | Interest Rate | | Interest Rate | | Interest Rate |
| | for Funds | | for Funds | | for Funds | | for Funds | | for Funds | | for Funds |
| | Loaned to | | Loaned to | | Loaned to | | Loaned to | | Loaned to | | Loaned to |
| | the Nonutility | | the Nonutility | | the Nonutility | | the Nonutility | | the Nonutility | | the Nonutility |
Company | | Money Pool | | Money Pool | | Money Pool | | Money Pool | | Money Pool | | Money Pool |
AEP Texas | | 2.70 | % | | 0.33 | % | | 1.44 | % | | 3.02 | % | | 2.36 | % | | 2.70 | % |
SWEPCo | | 2.70 | % | | 0.33 | % | | 1.44 | % | | 3.02 | % | | 2.36 | % | | 2.70 | % |
|
| | | | | | | | | | | | | | | | | | |
| | Nine Months Ended September 30, 2019 | | Nine Months Ended September 30, 2018 |
| | Maximum | | Minimum | | Average | | Maximum | | Minimum | | Average |
| | Interest Rate | | Interest Rate | | Interest Rate | | Interest Rate | | Interest Rate | | Interest Rate |
| | for Funds | | for Funds | | for Funds | | for Funds | | for Funds | | for Funds |
| | Loaned to | | Loaned to | | Loaned to | | Loaned to | | Loaned to | | Loaned to |
| | the Nonutility | | the Nonutility | | the Nonutility | | the Nonutility | | the Nonutility | | the Nonutility |
Company | | Money Pool | | Money Pool | | Money Pool | | Money Pool | | Money Pool | | Money Pool |
AEP Texas | | 3.02 | % | | 2.36 | % | | 2.70 | % | | 2.52 | % | | 1.83 | % | | 2.26 | % |
SWEPCo | | 3.02 | % | | 2.36 | % | | 2.70 | % | | 2.52 | % | | 1.83 | % | | 2.26 | % |
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 |
2020 | | 2.70 | % | | 0.50 | % | | 2.70 | % | | 0.50 | % | | 1.45 | % | | 1.40 | % |
2019 | | 3.02 | % | | 2.36 | % | | 3.02 | % | | 2.36 | % | | 2.70 | % | | 2.70 | % |
|
| | | | | | | | | | | | | | | | | | |
| | 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 |
2019 | | 3.02 | % | | 2.36 | % | | 3.02 | % | | 2.36 | % | | 2.70 | % | | 2.70 | % |
2018 | | 2.52 | % | | 1.76 | % | | 2.52 | % | | 1.76 | % | | 2.26 | % | | 2.27 | % |
Short-term Debt (Applies to AEP)AEP, AEP Texas and SWEPCo)
Outstanding short-term debt was as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | September 30, 2020 | | | | December 31, 2019 | | |
| | | | Outstanding | | Interest | | Outstanding | | Interest |
Company | | Type of Debt | | Amount | | Rate (a) | | Amount | | Rate (a) |
| | | | (dollars in millions) | | | | | | |
AEP | | Securitized Debt for Receivables (b) | | $ | 703.0 | | | 1.05 | % | | $ | 710.0 | | | 2.42 | % |
AEP | | Commercial Paper | | 650.0 | | | 0.21 | % | | 2,110.0 | | | 2.10 | % |
AEP | | 364-Day Term Loan | | 1,000.0 | | | 0.75 | % | | 0 | | | 0 | % |
AEP Texas | | COVID-19 Electricity Relief Program Loan (c) | | 2.0 | | | 0 | % | | 0 | | | 0 | % |
SWEPCo | | Notes Payable | | 42.0 | | | 2.46 | % | | 18.3 | | | 3.29 | % |
| | Total Short-term Debt | | $ | 2,397.0 | | | | | $ | 2,838.3 | | | |
|
| | | | | | | | | | | | | | |
| | September 30, 2019 | | December 31, 2018 |
| | Outstanding | | Interest | | Outstanding | | Interest |
Type of Debt | | Amount | | Rate (a) | | Amount | | Rate (a) |
| | (dollars in millions) |
Securitized Debt for Receivables (b) | | $ | 750.0 |
| | 2.56 | % | | $ | 750.0 |
| | 2.16 | % |
Commercial Paper | | 1,760.0 |
| | 2.36 | % | | 1,160.0 |
| | 2.96 | % |
Total Short-term Debt | | $ | 2,510.0 |
| | |
| | $ | 1,910.0 |
| | |
|
(a)Weighted-average rate.
(b)Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance.
(c)Principal amount of loan shall not bear interest if paid in full by the maturity date. Unpaid principal after the maturity date will accrue interest of 2% per annum beginning the first day after the maturity date until all outstanding principal is paid.
| |
(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 that provides a commitment of $750 million from bank conduits to purchase receivables and expires in July 2021.September 2022. 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.
In May 2020, AEP Credit amended its receivables securitization agreement to increase the eligibility criteria related to aged receivable requirements for the participating affiliated utility subsidiaries in response to the COVID-19 pandemic. As of September 30, 2020, the affiliated utility subsidiaries are in compliance with all requirements under the agreement. To the extent that an affiliated utility subsidiary is deemed ineligible under the agreement, receivables would no longer be purchased by the bank conduits and the Registrants would need to rely on additional sources of funding for operation and working capital, which may adversely impact liquidity.
Accounts receivable information for AEP Credit was as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | | | Nine Months Ended September 30, | | |
| | 2020 | | 2019 | | 2020 | | 2019 |
| | (dollars in millions) | | | | | | |
Effective Interest Rates on Securitization of Accounts Receivable | | 0.36 | % | | 2.37 | % | | 1.05 | % | | 2.56 | % |
Net Uncollectible Accounts Receivable Written-Off | | $ | 2.9 | | | $ | 8.8 | | | $ | 10.5 | | | $ | 19.8 | |
|
| | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | 2019 | | 2018 | | 2019 | | 2018 |
| | (dollars in millions) |
Effective Interest Rates on Securitization of Accounts Receivable | | 2.37 | % | | 2.27 | % | | 2.56 | % | | 2.06 | % |
Net Uncollectible Accounts Receivable Written-Off | | $ | 8.8 |
| | $ | 9.6 |
| | $ | 19.8 |
| | $ | 19.0 |
|
| | | | | | | | | | | | | | |
| | September 30, 2020 | | December 31, 2019 |
| | (in millions) | | |
Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts | | $ | 1,002.4 | | | $ | 841.8 | |
Short-term – Securitized Debt of Receivables | | 703.0 | | | 710.0 | |
Delinquent Securitized Accounts Receivable | | 103.8 | | | 39.6 | |
Bad Debt Reserves Related to Securitization | | 52.7 | | | 32.1 | |
Unbilled Receivables Related to Securitization | | 227.4 | | | 266.8 | |
|
| | | | | | | | |
| | September 30, 2019 | | December 31, 2018 |
| | (in millions) |
Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts | | $ | 923.3 |
| | $ | 972.5 |
|
Short-term – Securitized Debt of Receivables | | 750.0 |
| | 750.0 |
|
Delinquent Securitized Accounts Receivable | | 43.9 |
| | 50.3 |
|
Bad Debt Reserves Related to Securitization | | 32.3 |
| | 27.5 |
|
Unbilled Receivables Related to Securitization | | 216.2 |
| | 281.4 |
|
AEP Credit’s delinquent customer accounts receivable represent accounts greater than 30 days past due.
Securitized Accounts Receivables – AEP Credit (Applies to 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. 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 | | September 30, 2020 | | December 31, 2019 |
| | (in millions) | | |
APCo | | $ | 117.3 | | | $ | 120.9 | |
I&M | | 184.3 | | | 141.8 | |
OPCo | | 394.3 | | | 330.3 | |
PSO | | 122.0 | | | 101.1 | |
SWEPCo | | 177.6 | | | 125.2 | |
|
| | | | | | | | |
Company | | September 30, 2019 | | December 31, 2018 |
| | (in millions) |
APCo | | $ | 95.4 |
| | $ | 133.3 |
|
I&M | | 156.2 |
| | 152.9 |
|
OPCo | | 337.5 |
| | 395.2 |
|
PSO | | 149.4 |
| | 109.7 |
|
SWEPCo | | 168.6 |
| | 150.3 |
|
The fees paid to AEP Credit for customer accounts receivable sold were:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | | | Nine Months Ended September 30, | | |
Company | | 2020 | | 2019 | | 2020 | | 2019 |
| | (in millions) | | | | | | |
APCo | | $ | 2.0 | | | $ | 1.2 | | | $ | 5.0 | | | $ | 5.8 | |
I&M | | 3.9 | | | 2.4 | | | 9.3 | | | 8.4 | |
OPCo | | 9.8 | | | 6.4 | | | 19.6 | | | 22.1 | |
PSO | | 1.5 | | | 2.0 | | | 3.8 | | | 6.2 | |
SWEPCo | | 2.8 | | | 1.9 | | | 6.8 | | | 7.9 | |
|
| | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
Company | | 2019 | | 2018 | | 2019 | | 2018 |
| | (in millions) |
APCo | | $ | 1.2 |
| | $ | 1.8 |
| | $ | 5.8 |
| | $ | 5.1 |
|
I&M | | 2.4 |
| | 2.5 |
| | 8.4 |
| | 6.8 |
|
OPCo | | 6.4 |
| | 7.2 |
| | 22.1 |
| | 18.8 |
|
PSO | | 2.0 |
| | 2.3 |
| | 6.2 |
| | 6.0 |
|
SWEPCo | | 1.9 |
| | 2.6 |
| | 7.9 |
| | 6.6 |
|
The proceeds on the sale of receivables to AEP Credit were:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | | | Nine Months Ended September 30, | | |
Company | | 2020 | | 2019 | | 2020 | | 2019 |
| | (in millions) | | | | | | |
APCo | | $ | 323.5 | | | $ | 303.3 | | | $ | 961.8 | | | $ | 978.5 | |
I&M | | 532.3 | | | 485.3 | | | 1,443.6 | | | 1,378.9 | |
OPCo | | 666.0 | | | 602.6 | | | 1,793.0 | | | 1,746.1 | |
PSO | | 369.2 | | | 451.5 | | | 961.4 | | | 1,118.7 | |
SWEPCo | | 478.3 | | | 480.7 | | | 1,225.3 | | | 1,247.0 | |
|
| | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
Company | | 2019 | | 2018 | | 2019 | | 2018 |
| | (in millions) |
APCo | | $ | 303.3 |
| | $ | 334.1 |
| | $ | 978.5 |
| | $ | 1,079.2 |
|
I&M | | 485.3 |
| | 498.4 |
| | 1,378.9 |
| | 1,401.7 |
|
OPCo | | 602.6 |
| | 695.2 |
| | 1,746.1 |
| | 2,046.9 |
|
PSO | | 451.5 |
| | 454.9 |
| | 1,118.7 |
| | 1,171.2 |
|
SWEPCo | | 480.7 |
| | 512.6 |
| | 1,247.0 |
| | 1,364.6 |
|
13. VARIABLE INTEREST ENTITIESPROPERTY, PLANT AND EQUITY METHOD INVESTMENTSEQUIPMENT
The disclosuresdisclosure in this note applyapplies to AEP, only unless indicated otherwise.AEP Texas, APCo, PSO and SWEPCo.
Asset Retirement Obligations
The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a variable interestRegistrants record ARO in a VIE. A VIE is a legal entity that possesses any of the following conditions: the entity’s equity at risk is not sufficient to permit the legal entity to finance its activities without additional subordinated financial support, equity owners are unable to direct the activities that most significantly impact the legal entity’s economic performance (or they possess disproportionate voting rights in relation to the economic interest in the legal entity), or the equity owners lack the obligation to absorb the legal entity’s expected losses or the right to receive the legal entity’s expected residual returns. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined byaccordance with the accounting guidance for “Variable Interest Entities.” In determining whether AEP is the primary beneficiary of a VIE, management considers whether AEP has the power to direct the most significant activities of the VIE“Asset Retirement and is obligated to absorb losses or receive the expected residual returns that are significant to the VIE. Management believes that significant assumptionsEnvironmental Obligations” for legal obligations for asbestos removal and judgments were applied consistently.
AEP holds ownership interests in businesses with varying ownership structures. Partnership interests and other variable interests are evaluated to determine if each entity is a VIE, and if so, whether or not the VIE should be consolidated into AEP’s financial statements. If an entity is determined not to be a VIE, or if the entity is determined to be a VIE and AEP is not deemed to be the primary beneficiary, the entity is accounted for under the equity method of accounting. The Variable Interest Entities note within the 2018 Annual Report should be read in conjunction with this report as this note only includes significant changes to AEP’s VIEs and equity method investments during 2019.
Consolidated Variable Interests Entities
Restoration Funding (Applies to AEP and AEP Texas)
Restoration Funding was formed for the sole purposeretirement of issuingcertain ash disposal facilities, wind farms, solar farms and servicing securitization bonds relatedcertain coal mining facilities. The Registrants recorded the following revisions to storm restorationARO estimates during the first nine months of AEP Texas’ distribution system2020:
•In March 2020, SWEPCo recorded a revision to increase estimated ARO liabilities by $21 million primarily due to damage caused by Hurricane Harvey.the revision in the useful life of DHLC. See “Texas Storm Cost Securitization” section of Note 4 - Rate Matters for additional information. Management has concluded thatdetails. In September 2020, SWEPCo recorded an $18 million revision due to a reduction in estimated ash pond closure costs.
•In June 2020, AEP Texas and PSO recorded a revision to decrease estimated ARO liabilities by $17 million and $5 million, respectively, due to the retirement of the Oklaunion Power Station in September 2020. See Note 4 - Rate Matters for additional details.
•In June 2020, AGR derecognized $106 million of Conesville Plant related ARO liabilities as a result of the Environmental Liability and Property Transfer and Asset Purchase Agreement executed with a non-affiliated third-party. See Note 6 - Acquisitions and Dispositions for additional details.
•In June 2020, APCo recorded a revision to increase estimated Glen Lyn Station ash disposal ARO liabilities by $199 million due to the enactment of House Bill 443. This bill requires APCo to close the ash disposal units at the retired Glen Lyn Station by removal of all coal combustion material. The legislation provides for regulatory recovery of these costs. See Note 5 - Commitments, Guarantees and Contingencies for additional details.
The following is a reconciliation of the primary beneficiaryaggregate carrying amounts of Restoration Funding becauseARO for AEP, AEP Texas, hasAPCo, PSO and SWEPCo:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Company | | ARO as of December 31, 2019 | | Accretion Expense | | Liabilities Incurred | | Liabilities Settled | | Revisions in Cash Flow Estimates | | ARO as of September 30, 2020 |
| | (in millions) | | | | | | | | | | |
AEP (a)(b)(c)(d) | | $ | 2,418.9 | | | $ | 76.8 | | | $ | 0.2 | | | $ | (155.4) | | | $ | 170.5 | | | $ | 2,511.0 | |
AEP Texas (a)(d) | | 29.1 | | | 0.7 | | | 0 | | | 0 | | | (16.8) | | | 13.0 | |
APCo (a)(d) | | 111.1 | | | 5.9 | | | 0 | | | (5.3) | | | 195.4 | | | 307.1 | |
PSO (a)(d) | | 52.2 | | | 2.3 | | | 0 | | | (0.5) | | | (4.8) | | | 49.2 | |
SWEPCo (a)(c)(d) | | 212.2 | | | 8.2 | | | 0 | | | (5.6) | | | 6.2 | | | 221.0 | |
(a)Includes ARO related to ash disposal facilities.
(b)Includes ARO related to nuclear decommissioning costs for the power to direct the most significant activitiesCook Plant of the VIE$1.78 billion and AEP Texas’ equity interest could potentially be significant. Therefore, AEP Texas is required to consolidate Restoration Funding. The securitized bonds totaled $235 million$1.73 billion as of September 30, 2019 and are included in Long-term Debt Due Within One Year - Nonaffiliated and Long-term Debt - Nonaffiliated on the balance sheets. Restoration Funding has securitized assets of $235 million as of September 30, 2019 which are presented separately on the face of the balance sheets. The securitized restoration assets represent the right to impose and collect Texas storm restoration costs from customers receiving electric transmission or distribution service from AEP Texas under recovery mechanisms approved by the PUCT. The securitization bonds are payable only from and secured by the securitized assets. The bondholders have no recourse to AEP Texas or any other AEP entity. AEP Texas acts as the servicer for Restoration Fundings’ securitized assets and remits all related amounts collected from customers to Restoration Funding for interest and principal payments on the securitization bonds and related costs. See the table below for the classification of Restoration Fundings’ assets and liabilities on the balance sheets.
Apple Blossom Wind Holdings LLC and Black Oak Getty Wind Holdings LLC
In April 2019, AEP acquired an equity interest in Apple Blossom Wind Holdings LLC (Apple Blossom) and Black Oak Getty Wind Holdings LLC (Black Oak) (the Project Entities) as part of the purchase of Sempra Renewables LLC. Both of the Project Entities have long-term PPAs for 100% of their energy production. The Project Entities are tax equity partnerships with nonaffiliated noncontrolling interests to which a percentage of earnings, tax attributes and cash flows are allocated in accordance with the respective limited liability company agreements. Management has concluded that the Project Entities are VIEs and that AEP is the primary beneficiary based on its power as managing member to direct the activities that most significantly impact the Project Entities’ economic performance. In addition, AEP has not provided material financial or other support to the Project Entities that was not previously contractually required. As the primary beneficiary of the Project Entities, AEP consolidates the Project Entities into its financial statements. See the table below for the classification of Project Entities’ assets and liabilities on the balance sheets.
The nonaffiliated interests in the Project Entities is presented in Noncontrolling Interests on the balance sheets. As of September 30, 2019, AEP recorded $129 million of Noncontrolling Interests related to the Project Entities in Equity on the balance sheets.
The Project Entities’ tax equity partnerships represent substantive profit-sharing arrangements. The method for attributing income and loss to the noncontrolling interests is a balance sheet approach referred to as the hypothetical liquidation at book value (HLBV) method. Under the HLBV method, the income and loss attributable to the noncontrolling interests reflect changes in the amounts the members would hypothetically receive at each balance sheet date under the liquidation provisions of the respective limited liability company agreements, assuming the net assets of these entities were liquidated at recorded amounts, after taking into account any capital transactions, such as contributions or distributions, between the entities and the members. For the three and nine months ended September 30, 2019, the HLBV method resulted in $0 and a loss of $4 million, respectively, allocated to Noncontrolling Interests.
Santa Rita East
In July 2019, AEP acquired a 75% interest in Santa Rita East Wind Energy Holdings, LLC and its wholly-owned subsidiary, Santa Rita East Wind Energy, LLC (collectively, Santa Rita East). Santa Rita East is a partnership whose sole purpose is to own and operate a new 302.4 MW wind generation facility in west Texas. Santa Rita East delivers energy and provides renewable energy credits through three long-term PPAs totaling 260 MWs. The remaining 42.4 MWs of energy are sold at wholesale into ERCOT. Management has concluded that Santa Rita East is a VIE and that AEP is the primary beneficiary based on its power as managing member of the partnership to direct the activities that most significantly impact Santa Rita East’s economic performance. As the primary beneficiary of Santa Rita East, AEP consolidates Santa Rita East into its financial statements. See the table below for the classification of Santa Rita’s assets and liabilities on the balance sheets.
AEP recognized $8 million of PTC attributable to Santa Rita East for the three and nine months ended September 30, 2019 which was recorded in Income Tax Expense (Benefit) on the statements of income. The nonaffiliated interest in Santa Rita East is presented in Noncontrolling Interests on the balance sheets. As of September 30, 2019, AEP recorded $118 million of Noncontrolling Interests related to Santa Rita East in Equity on the balance sheets.
|
| | | | | | | | | | | |
American Electric Power Company, Inc. and Subsidiary Companies |
Variable Interest Entities |
September 30, 2019 |
| | | | | |
| Registrant Subsidiary | | Other Consolidated VIEs |
| AEP Texas Restoration Funding | | Apple Blossom and Black Oak | | Santa Rita East |
| (in millions) |
ASSETS | | | | | |
Current Assets | $ | 1.2 |
| | $ | 5.7 |
| | $ | 17.0 |
|
Net Property, Plant and Equipment | — |
| | 233.3 |
| | 466.6 |
|
Other Noncurrent Assets | 235.3 |
| | 12.5 |
| | 0.8 |
|
Total Assets | $ | 236.5 |
| | $ | 251.5 |
| | $ | 484.4 |
|
| | | | | |
LIABILITIES AND EQUITY | | | | | |
Current Liabilities | $ | 14.4 |
| | $ | 2.2 |
| | $ | 3.5 |
|
Noncurrent Liabilities | 220.9 |
| | 4.6 |
| | 7.5 |
|
Equity
| 1.2 |
| | 244.7 |
| | 473.4 |
|
Total Liabilities and Equity | $ | 236.5 |
| | $ | 251.5 |
| | $ | 484.4 |
|
Significant Equity Method Investments in Unconsolidated Entities
The equity method of accounting is used for equity investments where AEP exercises significant influence but does not hold a controlling financial interest. Such investments are initially recorded at cost in Deferred Charges and Other Noncurrent Assets on the balance sheets. The proportionate share of the investee’s equity earnings or losses is included in Equity Earnings of Unconsolidated Subsidiaries on the statements of income. AEP regularly monitors and evaluates equity method investments to determine whether they are impaired. An impairment is recorded when the investment has experienced a decline in value that is other-than-temporary in nature.
Sempra Renewables LLC
In April 2019, AEP acquired a 50% interest in five wind farms in multiple states as part of the purchase of Sempra Renewables LLC. The wind farms are joint ventures with BP Wind Energy who holds the other 50% interest. All five wind farms have long-term PPAs for 100% of their energy production. One of the jointly-owned wind farms has PPAs with I&M and OPCo for a portion of its energy production. Another jointly-owned wind farm has a PPA with SWEPCo for a portion of its energy production. The joint venture wind farms are not considered VIEs and AEP is not required to consolidate them as AEP does not have a controlling financial interest. However, AEP is able to exercise significant influence over the wind farms and therefore applies the equity method of accounting. As of September 30, 2019, AEP’s investment in the five joint venture wind farms was $389 million. The investment includes amounts recognized in AOCI related to interest rate cash flow hedges. The investment is comprised of a historical investment of $417 million plus a basis difference of $(19) million. AEP’s equity earnings associated with the five joint venture wind farms were losses of $3 million and $6 million for the three and nine months ended September 30, 2019, respectively. AEP recognized $7 million and $21 million of PTC attributable to the joint venture wind farms for the three and nine months ended September 30, 2019, respectively, which was recorded in Income Tax Expense (Benefit) on the statements of income.
ETT
ETT designs, acquires, constructs, owns and operates certain transmission facilities in ERCOT. Berkshire Hathaway Energy, a nonaffiliated entity, holds a 50% membership interest in ETT, AEP Transmission Holdco holds a 49.5% interest in ETT and AEP Transmission Partner held the remaining 0.5% membership interest in ETT. In July 2019, AEP Transmission Partner was merged into AEP Transmission Holdco, increasing AEP Transmission Holdco’s interest in ETT to 50%. As a result, AEP, through its wholly-owned subsidiary, holds a 50% membership interest in ETT. As of September 30, 20192020 and December 31, 2018, AEP’s investment in ETT was $693 million2019, respectively.
(c)Includes ARO related to Sabine and $666 million, respectively. AEP’s equity earnings associated with ETT were $16 million and $15 million for the three months ended September 30, 2019 and 2018, respectively. AEP’s equity earnings associated with ETT were $49 million and $46 million for the nine months ended September 30, 2019 and 2018, respectively.DHLC.
(d)Includes ARO related to asbestos removal.
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, 2020 | | | | | | | | | | | | |
| | 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 | | $ | 1,053.3 | | | $ | 594.8 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 1,648.1 | |
Commercial Revenues | | 559.7 | | | 259.2 | | | 0 | | | 0 | | | 0 | | | 0 | | | 818.9 | |
Industrial Revenues | | 504.5 | | | 93.9 | | | 0 | | | 0 | | | 0 | | | (0.1) | | | 598.3 | |
Other Retail Revenues | | 41.4 | | | 10.0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 51.4 | |
Total Retail Revenues | | 2,158.9 | | | 957.9 | | | 0 | | | 0 | | | 0 | | | (0.1) | | | 3,116.7 | |
| | | | | | | | | | | | | | |
Wholesale and Competitive Retail Revenues: | | | | | | | | | | | | | | |
Generation Revenues | | 158.4 | | | 0 | | | 0 | | | 30.5 | | | 0 | | | 0 | | | 188.9 | |
| | | | | | | | | | | | | | |
Transmission Revenues (a) | | 84.4 | | | 119.1 | | | 317.7 | | | 0 | | | 0 | | | (276.9) | | | 244.3 | |
Renewable Generation Revenues (b) | | 0 | | | 0 | | | 0 | | | 15.8 | | | 0 | | | (0.3) | | | 15.5 | |
Retail, Trading and Marketing Revenues (c) | | 0 | | | 0 | | | 0 | | | 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 | |
| | | | | | | | | | | | | | |
Other Revenues from Contracts with Customers (b) | | 34.1 | | | 42.8 | | | 2.4 | | | 0.7 | | | 33.9 | | | (43.7) | | | 70.2 | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
Total Revenues from Contracts with Customers | | 2,435.8 | | | 1,119.8 | | | 320.1 | | | 494.5 | | | 34.8 | | | (345.8) | | | 4,059.2 | |
| | | | | | | | | | | | | | |
Other Revenues: | | | | | | | | | | | | | | |
Alternative Revenues (b) | | (1.0) | | | 9.3 | | | (2.2) | | | 0 | | | 0 | | | 6.6 | | | 12.7 | |
Other Revenues (b) | | 0 | | | 36.2 | | | 0 | | | (4.5) | | | (2.2) | | | (35.0) | | | (5.5) | |
| | | | | | | | | | | | | | |
Total Other Revenues | | (1.0) | | | 45.5 | | | (2.2) | | | (4.5) | | | (2.2) | | | (28.4) | | | 7.2 | |
| | | | | | | | | | | | | | |
Total Revenues | | $ | 2,434.8 | | | $ | 1,165.3 | | | $ | 317.9 | | | $ | 490.0 | | | $ | 32.6 | | | $ | (374.2) | | | $ | 4,066.4 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, 2019 |
| | 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 | | $ | 1,060.2 |
| | $ | 588.0 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 1,648.2 |
|
Commercial Revenues | | 612.5 |
| | 290.9 |
| | — |
| | — |
| | — |
| | — |
| | 903.4 |
|
Industrial Revenues | | 566.0 |
| | 99.3 |
| | — |
| | — |
| | — |
| | 1.5 |
| | 666.8 |
|
Other Retail Revenues | | 49.2 |
| | 10.6 |
| | — |
| | — |
| | — |
| | — |
| | 59.8 |
|
Total Retail Revenues | | 2,287.9 |
| | 988.8 |
| | — |
| | — |
| | — |
| | 1.5 |
| | 3,278.2 |
|
| | | | | | | | | | | | | | |
Wholesale and Competitive Retail Revenues: | | | | | | | | | | | | | | |
Generation Revenues (a) | | 231.3 |
| | — |
| | — |
| | 77.1 |
| | — |
| | (34.2 | ) | | 274.2 |
|
Transmission Revenues (b) | | 77.8 |
| | 110.9 |
| | 269.4 |
| | — |
| | — |
| | (217.2 | ) | | 240.9 |
|
Marketing, Competitive Retail and Renewable Revenues | | — |
| | — |
| | — |
| | 415.4 |
| | — |
| | 0.5 |
| | 415.9 |
|
Total Wholesale and Competitive Retail Revenues | | 309.1 |
| | 110.9 |
| | 269.4 |
| | 492.5 |
| | — |
| | (250.9 | ) | | 931.0 |
|
| | | | | | | | | | | | | | |
Other Revenues from Contracts with Customers (c) | | 47.3 |
| | 42.9 |
| | 4.5 |
| | 14.8 |
| | 35.6 |
| | (42.2 | ) | | 102.9 |
|
| | | | | | | | | | | | | | |
Total Revenues from Contracts with Customers | | 2,644.3 |
| | 1,142.6 |
| | 273.9 |
| | 507.3 |
| | 35.6 |
| | (291.6 | ) | | 4,312.1 |
|
| | | | | | | | | | | | | | |
Other Revenues: | | | | | | | | | | | | | | |
Alternative Revenues (c) | | 1.2 |
| | 5.1 |
| | (0.9 | ) | | — |
| | — |
| | (16.8 | ) | | (11.4 | ) |
Other Revenues (c) | | — |
| | 38.9 |
| | — |
| | 26.4 |
| | (11.2 | ) | | (39.8 | ) | | 14.3 |
|
Total Other Revenues | | 1.2 |
| | 44.0 |
| | (0.9 | ) | | 26.4 |
| | (11.2 | ) | | (56.6 | ) | | 2.9 |
|
| | | | | | | | | | | | | | |
Total Revenues | | $ | 2,645.5 |
| | $ | 1,186.6 |
| | $ | 273.0 |
| | $ | 533.7 |
| | $ | 24.4 |
| | $ | (348.2 | ) | | $ | 4,315.0 |
|
| |
(a) | Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $34 million. The remaining affiliated amounts were immaterial. |
| |
(b) | Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $197 million. The remaining affiliated amounts were immaterial. |
| |
(c) | Amounts include affiliated and nonaffiliated revenues. |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, 2018 |
| | 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 | | $ | 1,048.7 |
| | $ | 612.2 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 1,660.9 |
|
Commercial Revenues | | 612.8 |
| | 330.9 |
| | — |
| | — |
| | — |
| | — |
| | 943.7 |
|
Industrial Revenues | | 578.8 |
| | 128.8 |
| | — |
| | — |
| | — |
| | — |
| | 707.6 |
|
Other Retail Revenues | | 49.1 |
| | 10.7 |
| | — |
| | — |
| | — |
| | — |
| | 59.8 |
|
Total Retail Revenues (a) | | 2,289.4 |
| | 1,082.6 |
| | — |
| | — |
| | — |
| | — |
| | 3,372.0 |
|
| | | | | | | | | | | | | | |
Wholesale and Competitive Retail Revenues: | | | | | | | | | | | | | | |
Generation Revenues (b) | | 224.2 |
| | — |
| | — |
| | 115.1 |
| | — |
| | (98.5 | ) | | 240.8 |
|
Transmission Revenues (c) | | 72.8 |
| | 88.0 |
| | 201.4 |
| | — |
| | — |
| | (241.6 | ) | | 120.6 |
|
Marketing, Competitive Retail and Renewable Revenues | | — |
| | — |
| | — |
| | 399.1 |
| | — |
| | — |
| | 399.1 |
|
Total Wholesale and Competitive Retail Revenues | | 297.0 |
| | 88.0 |
| | 201.4 |
| | 514.2 |
| | — |
| | (340.1 | ) | | 760.5 |
|
| | | | | | | | | | | | | | |
Other Revenues from Contracts with Customers (e) | | 40.3 |
| | 69.9 |
| | 0.7 |
|
| 12.7 |
| | 21.5 |
| | 49.5 |
| | 194.6 |
|
| | | | | | | | | | | | | | |
Total Revenues from Contracts with Customers | | 2,626.7 |
| | 1,240.5 |
| | 202.1 |
| | 526.9 |
| | 21.5 |
| | (290.6 | ) | | 4,327.1 |
|
| | | | | | | | | | | | | | |
Other Revenues: | | | | | | | | | | | | | | |
Alternative Revenues (d) | | 0.2 |
| | (37.9 | ) | | (14.9 | ) | | — |
| | — |
| | — |
| | (52.6 | ) |
Other Revenues (e) | | 9.8 |
| | 8.9 |
| | — |
| | (5.3 | ) | | 2.2 |
| | 43.0 |
| | 58.6 |
|
Total Other Revenues | | 10.0 |
| | (29.0 | ) | | (14.9 | ) | | (5.3 | ) | | 2.2 |
| | 43.0 |
| | 6.0 |
|
| | | | | | | | | | | | | | |
Total Revenues | | $ | 2,636.7 |
| | $ | 1,211.5 |
| | $ | 187.2 |
| | $ | 521.6 |
| | $ | 23.7 |
| | $ | (247.6 | ) | | $ | 4,333.1 |
|
| |
(a) | 2018 amounts have been revised to reflect the reclassification of certain customer accounts between Retail classes. This reclassification did not impact previously reported Total Retail Revenues. Management concluded that these prior period disclosure only errors were immaterial individually and in the aggregate. |
| |
(b) | Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $35 million. The remaining affiliated amounts were immaterial. |
| |
(c) | Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $147 million. The remaining affiliated amounts were immaterial. |
| |
(d) | The alternative revenue for Transmission and Distribution Utilities was primarily the $48 million reduction in revenue relating to the Ohio Tax Reform settlement. |
| |
(e) | Amounts include affiliated and nonaffiliated revenues. |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, 2019 |
| | AEP Texas | | AEPTCo | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in millions) |
Retail Revenues: | | | | | | | | | | | | | | |
Residential Revenues | | $ | 192.0 |
| | $ | — |
| | $ | 315.7 |
| | $ | 198.2 |
| | $ | 395.6 |
| | $ | 231.9 |
| | $ | 222.9 |
|
Commercial Revenues | | 110.6 |
| | — |
| | 147.2 |
| | 138.3 |
| | 180.5 |
| | 122.2 |
| | 144.3 |
|
Industrial Revenues | | 32.2 |
| | — |
| | 152.2 |
| | 138.7 |
| | 67.1 |
| | 84.1 |
| | 92.3 |
|
Other Retail Revenues | | 7.5 |
| | — |
| | 18.5 |
| | 1.9 |
| | 3.1 |
| | 24.9 |
| | 2.3 |
|
Total Retail Revenues | | 342.3 |
| | — |
| | 633.6 |
| | 477.1 |
| | 646.3 |
| | 463.1 |
| | 461.8 |
|
| | | | | | | | | | | | | | |
Wholesale Revenues: | | | | | | | | | | | | | | |
Generation Revenues (a) | | — |
| | — |
| | 70.4 |
| | 102.1 |
| | — |
| | 21.1 |
| | 50.7 |
|
Transmission Revenues (b) | | 97.7 |
| | 256.4 |
| | 26.2 |
| | 6.4 |
| | 13.7 |
| | (3.4 | ) | | 30.0 |
|
Total Wholesale Revenues | | 97.7 |
| | 256.4 |
| | 96.6 |
| | 108.5 |
| | 13.7 |
| | 17.7 |
| | 80.7 |
|
| | | | | | | | | | | | | | |
Other Revenues from Contracts with Customers (c) | | 8.2 |
| | 4.5 |
| | 18.7 |
| | 26.6 |
| | 41.0 |
| | 5.1 |
| | 7.0 |
|
| | | | | | | | | | | | | | |
Total Revenues from Contracts with Customers | | 448.2 |
| | 260.9 |
| | 748.9 |
| | 612.2 |
| | 701.0 |
| | 485.9 |
| | 549.5 |
|
| | | | | | | | | | | | | | |
Other Revenues: | | | | | | | | | | | | | | |
Alternative Revenues (d) | | (0.7 | ) | | (1.2 | ) | | 6.6 |
| | (1.1 | ) | | 12.4 |
| | 7.1 |
| | (4.0 | ) |
Other Revenues (d) | | 41.8 |
| | — |
| | — |
| | — |
| | (2.8 | ) | | — |
| | — |
|
Total Other Revenues | | 41.1 |
| | (1.2 | ) | | 6.6 |
| | (1.1 | ) | | 9.6 |
| | 7.1 |
| | (4.0 | ) |
| | | | | | | | | | | | | | |
Total Revenues | | $ | 489.3 |
| | $ | 259.7 |
| | $ | 755.5 |
| | $ | 611.1 |
| | $ | 710.6 |
| | $ | 493.0 |
| | $ | 545.5 |
|
| |
(a) | Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $32 million primarily relating to the PPA with Kingsport. The remaining affiliated amounts were immaterial. |
| |
(b) | Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $194 million. The remaining affiliated amounts were immaterial. |
| |
(c) | Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $20 million primarily relating to the 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, 2018 |
| | AEP Texas | | AEPTCo | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in millions) |
Retail Revenues: | | | | | | | | | | | | | | |
Residential Revenues | | $ | 178.8 |
| | $ | — |
| | $ | 320.9 |
| | $ | 207.4 |
| | $ | 433.5 |
| | $ | 220.8 |
| | $ | 214.1 |
|
Commercial Revenues | | 107.9 |
| | — |
| | 155.1 |
| | 138.0 |
| | 222.9 |
| | 119.9 |
| | 140.4 |
|
Industrial Revenues | | 32.1 |
| | — |
| | 157.6 |
| | 150.2 |
| | 96.3 |
| | 82.4 |
| | 89.6 |
|
Other Retail Revenues | | 7.4 |
| | — |
| | 19.2 |
| | 1.7 |
| | 3.3 |
| | 24.5 |
| | 2.2 |
|
Total Retail Revenues (a) | | 326.2 |
| | — |
| | 652.8 |
| | 497.3 |
| | 756.0 |
| | 447.6 |
| | 446.3 |
|
| | | | | | | | | | | | | | |
Wholesale Revenues: | | | | | | | | | | | | | | |
Generation Revenues (b) | | — |
| | — |
| | 74.5 |
| | 93.6 |
| | — |
| | 12.5 |
| | 53.2 |
|
Transmission Revenues (c) | | 73.6 |
| | 206.6 |
| | 20.9 |
| | 6.2 |
| | 14.8 |
| | 13.5 |
| | 29.5 |
|
Total Wholesale Revenues | | 73.6 |
| | 206.6 |
| | 95.4 |
| | 99.8 |
| | 14.8 |
| | 26.0 |
| | 82.7 |
|
| | | | | | | | | | | | | | |
Other Revenues from Contracts with Customers (d) | | 7.5 |
| | 0.2 |
| | 15.9 |
| | 22.4 |
| | (29.9 | ) | | 5.5 |
| | 6.6 |
|
| | | | | | | | | | | | | | |
Total Revenues from Contracts with Customers | | 407.3 |
| | 206.8 |
| | 764.1 |
| | 619.5 |
| | 740.9 |
| | 479.1 |
| | 535.6 |
|
| | | | | | | | | | | | | | |
Other Revenues: | | | | | | | | | | | | | | |
Alternative Revenues (e) | | (1.0 | ) | | (12.4 | ) | | (1.2 | ) | | 1.5 |
| | (36.9 | ) | | 2.3 |
| | (0.3 | ) |
Other Revenues (f) | | 27.1 |
| | — |
| | (0.9 | ) | | 8.7 |
| | 74.3 |
| | — |
| | — |
|
Total Other Revenues | | 26.1 |
| | (12.4 | ) | | (2.1 | ) | | 10.2 |
| | 37.4 |
| | 2.3 |
| | (0.3 | ) |
| | | | | | | | | | | | | | |
Total Revenues | | $ | 433.4 |
| | $ | 194.4 |
| | $ | 762.0 |
| | $ | 629.7 |
| | $ | 778.3 |
| | $ | 481.4 |
| | $ | 535.3 |
|
| |
(a) | 2018 amounts have been revised to reflect the reclassification of certain customer accounts between Retail classes. This reclassification did not impact previously reported Total Retail Revenues. Management concluded that these prior period disclosure only errors were immaterial individually and in the aggregate. |
| |
(b) | Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $30 million primarily relating to the PPA with Kingsport. The remaining affiliated amounts were immaterial. |
| |
(c) | Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $146 million. The remaining affiliated amounts were immaterial. |
| |
(d) | Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $17 million primarily relating to the barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial. |
| |
(e) | The alternative revenue for OPCo was primarily the $48 million reduction in revenue relating to the Ohio Tax Reform settlement. |
| |
(f) | Amounts include affiliated and nonaffiliated revenues. |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Nine Months Ended September 30, 2019 |
| | 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 | | $ | 2,797.6 |
| | $ | 1,609.1 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 4,406.7 |
|
Commercial Revenues | | 1,641.2 |
| | 889.4 |
| | — |
| | — |
| | — |
| | — |
| | 2,530.6 |
|
Industrial Revenues | | 1,647.3 |
| | 332.6 |
| | — |
| | — |
| | — |
| | — |
| | 1,979.9 |
|
Other Retail Revenues | | 136.1 |
| | 32.8 |
| | — |
| | — |
| | — |
| | — |
| | 168.9 |
|
Total Retail Revenues | | 6,222.2 |
| | 2,863.9 |
| | — |
| | — |
| | — |
| | — |
| | 9,086.1 |
|
| | | | | | | | | | | | | | |
Wholesale and Competitive Retail Revenues: | | | | | | | | | | | | | | |
Generation Revenues (a) | | 661.9 |
| | — |
| | — |
| | 282.0 |
| | — |
| | (105.5 | ) | | 838.4 |
|
Transmission Revenues (b) | | 215.4 |
| | 324.0 |
| | 814.3 |
| | — |
| | — |
| | (603.6 | ) | | 750.1 |
|
Marketing, Competitive Retail and Renewable Revenues | | — |
| | — |
| | — |
| | 1,088.5 |
| | — |
| | 0.5 |
| | 1,089.0 |
|
Total Wholesale and Competitive Retail Revenues | | 877.3 |
| | 324.0 |
| | 814.3 |
| | 1,370.5 |
| | — |
| | (708.6 | ) | | 2,677.5 |
|
| | | | | | | | | | | | | | |
Other Revenues from Contracts with Customers (c) | | 128.8 |
| | 127.6 |
| | 12.6 |
| | 4.5 |
| | 80.4 |
| | (113.6 | ) | | 240.3 |
|
| | | | | | | | | | | | | | |
Total Revenues from Contracts with Customers | | 7,228.3 |
| | 3,315.5 |
| | 826.9 |
| | 1,375.0 |
| | 80.4 |
| | (822.2 | ) | | 12,003.9 |
|
| | | | | | | | | | | | | | |
Other Revenues: | | | | | | | | | | | | | | |
Alternative Revenues (c) | | (55.7 | ) | | 21.5 |
| | (18.6 | ) | | — |
| | — |
| | (60.3 | ) | | (113.1 | ) |
Other Revenues (c) | | — |
| | 117.3 |
| | — |
| | 53.2 |
| | (6.7 | ) | | (109.2 | ) | | 54.6 |
|
Total Other Revenues | | (55.7 | ) | | 138.8 |
| | (18.6 | ) | | 53.2 |
| | (6.7 | ) | | (169.5 | ) | | (58.5 | ) |
| | | | | | | | | | | | | | |
Total Revenues | | $ | 7,172.6 |
| | $ | 3,454.3 |
| | $ | 808.3 |
| | $ | 1,428.2 |
| | $ | 73.7 |
| | $ | (991.7 | ) | | $ | 11,945.4 |
|
| |
(a) | Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $105 million. The remaining affiliated amounts were immaterial. |
| |
(b) | Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $596 million. The remaining affiliated amounts were immaterial. |
| |
(c) | Amounts include affiliated and nonaffiliated revenues. |
(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $246 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 $19 million. The remaining affiliated amounts were immaterial. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Nine Months Ended September 30, 2018 |
| | 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 | | $ | 2,906.9 |
| | $ | 1,711.1 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 4,618.0 |
|
Commercial Revenues | | 1,672.7 |
| | 945.2 |
| | — |
| | — |
| | — |
| | — |
| | 2,617.9 |
|
Industrial Revenues | | 1,676.1 |
| | 381.5 |
| | — |
| | — |
| | — |
| | — |
| | 2,057.6 |
|
Other Retail Revenues | | 139.4 |
| | 31.8 |
| | — |
| | — |
| | — |
| | — |
| | 171.2 |
|
Total Retail Revenues (a) | | 6,395.1 |
| | 3,069.6 |
| | — |
| | — |
| | — |
| | — |
| | 9,464.7 |
|
| | | | | | | | | | | | | | |
Wholesale and Competitive Retail Revenues: | | | | | | | | | | | | | | |
Generation Revenues (b) | | 686.5 |
| | — |
| | — |
| | 413.4 |
| | — |
| | (155.2 | ) | | 944.7 |
|
Transmission Revenues (c) | | 208.4 |
| | 272.6 |
| | 633.9 |
| | — |
| | — |
| | (520.7 | ) | | 594.2 |
|
Marketing, Competitive Retail and Renewable Revenues | | — |
| | — |
| | — |
| | 1,040.2 |
| | — |
| | — |
| | 1,040.2 |
|
Total Wholesale and Competitive Retail Revenues | | 894.9 |
| | 272.6 |
| | 633.9 |
| | 1,453.6 |
| | — |
| | (675.9 | ) | | 2,579.1 |
|
| | | | | | | | | | | | | | |
Other Revenues from Contracts with Customers (e) | | 121.8 |
| | 165.1 |
| | 11.1 |
| | 15.0 |
| | 64.8 |
| | 1.8 |
| | 379.6 |
|
| | | | | | | | | | | | | | |
Total Revenues from Contracts with Customers | | 7,411.8 |
| | 3,507.3 |
| | 645.0 |
| | 1,468.6 |
| | 64.8 |
| | (674.1 | ) | | 12,423.4 |
|
| | | | | | | | | | | | | | |
Other Revenues: | | | | | | | | | | | | | | |
Alternative Revenues (d) | | (19.2 | ) | | (48.3 | ) | | (39.8 | ) | | — |
| | — |
| | — |
| | (107.3 | ) |
Other Revenues (e) | | 1.1 |
| | 51.9 |
| | — |
| | 18.8 |
| | 6.7 |
| | — |
| | 78.5 |
|
Total Other Revenues | | (18.1 | ) | | 3.6 |
| | (39.8 | ) | | 18.8 |
| | 6.7 |
| | — |
| | (28.8 | ) |
| | | | | | | | | | | | | | |
Total Revenues | | $ | 7,393.7 |
| | $ | 3,510.9 |
| | $ | 605.2 |
| | $ | 1,487.4 |
| | $ | 71.5 |
| | $ | (674.1 | ) | | $ | 12,394.6 |
|
| |
(a) | 2018 amounts have been revised to reflect the reclassification of certain customer accounts between Retail classes. This reclassification did not impact previously reported Total Retail Revenues. Management concluded that these prior period disclosure only errors were immaterial individually and in the aggregate. |
| |
(b) | Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $87 million. The remaining affiliated amounts were immaterial. |
| |
(c) | Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $444 million. The remaining affiliated amounts were immaterial. |
| |
(d) | The alternative revenue for Transmission and Distribution Utilities was primarily the $48 million reduction in revenue relating to the Ohio Tax Reform settlement. |
| |
(e) | Amounts include affiliated and nonaffiliated revenues. |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Nine Months Ended September 30, 2019 |
| | AEP Texas | | AEPTCo | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in millions) |
Retail Revenues: | | | | | | | | | | | | | | |
Residential Revenues | | $ | 454.9 |
| | $ | — |
| | $ | 944.7 |
| | $ | 558.8 |
| | $ | 1,155.5 |
| | $ | 519.6 |
| | $ | 503.7 |
|
Commercial Revenues | | 314.5 |
| | — |
| | 421.5 |
| | 371.4 |
| | 573.7 |
| | 304.3 |
| | 371.1 |
|
Industrial Revenues | | 98.8 |
| | — |
| | 444.3 |
| | 411.9 |
| | 233.9 |
| | 238.1 |
| | 257.2 |
|
Other Retail Revenues | | 22.7 |
| | — |
| | 56.5 |
| | 5.4 |
| | 9.8 |
| | 63.1 |
| | 6.7 |
|
Total Retail Revenues | | 890.9 |
| | — |
| | 1,867.0 |
| | 1,347.5 |
| | 1,972.9 |
| | 1,125.1 |
| | 1,138.7 |
|
| | | | | | | | | | | | | | |
Wholesale Revenues: | | | | | | | | | | | | | | |
Generation Revenues (a) | | — |
| | — |
| | 200.1 |
| | 327.4 |
| | — |
| | 35.5 |
| | 152.7 |
|
Transmission Revenues (b) | | 282.0 |
| | 775.3 |
| | 77.6 |
| | 18.8 |
| | 42.0 |
| | 21.9 |
| | 78.0 |
|
Total Wholesale Revenues | | 282.0 |
| | 775.3 |
| | 277.7 |
| | 346.2 |
| | 42.0 |
| | 57.4 |
| | 230.7 |
|
| | | | | | | | | | | | | | |
Other Revenues from Contracts with Customers (c) | | 22.9 |
| | 12.6 |
| | 48.2 |
| | 76.2 |
| | 113.3 |
| | 16.7 |
| | 20.1 |
|
| | | | | | | | | | | | | | |
Total Revenues from Contracts with Customers | | 1,195.8 |
| | 787.9 |
| | 2,192.9 |
| | 1,769.9 |
| | 2,128.2 |
| | 1,199.2 |
| | 1,389.5 |
|
| | | | | | | | | | | | | | |
Other Revenues: | | | | | | | | | | | | | | |
Alternative Revenues (d) | | (0.4 | ) | | (17.8 | ) | | 11.2 |
| | (1.4 | ) | | 22.0 |
| | (25.3 | ) | | (47.4 | ) |
Other Revenues (d) | | 122.6 |
| | — |
| | — |
| | — |
| | 3.8 |
| | — |
| | — |
|
Total Other Revenues | | 122.2 |
| | (17.8 | ) | | 11.2 |
| | (1.4 | ) | | 25.8 |
| | (25.3 | ) | | (47.4 | ) |
| | | | | | | | | | | | | | |
Total Revenues | | $ | 1,318.0 |
| | $ | 770.1 |
| | $ | 2,204.1 |
| | $ | 1,768.5 |
| | $ | 2,154.0 |
| | $ | 1,173.9 |
| | $ | 1,342.1 |
|
| |
(a) | Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $96 million primarily relating to the PPA with Kingsport. The remaining affiliated amounts were immaterial. |
| |
(b) | Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $587 million. The remaining affiliated amounts were immaterial. |
| |
(c) | Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $57 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, 2018 | | Three Months Ended September 30, 2019 | |
| | 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: | |
Residential Revenues | | $ | 453.6 |
| | $ | — |
| | $ | 1,017.3 |
| | $ | 559.4 |
| | $ | 1,258.4 |
| | $ | 531.4 |
| | $ | 512.4 |
| Residential Revenues | | $ | 1,060.2 | | | $ | 588.0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 1,648.2 | |
Commercial Revenues | | 310.8 |
| | — |
| | 442.3 |
| | 369.8 |
| | 633.2 |
| | 309.3 |
| | 372.6 |
| Commercial Revenues | | 612.5 | | | 290.9 | | | 0 | | | 0 | | | 0 | | | 0 | | | 903.4 | |
Industrial Revenues | | 94.8 |
| | — |
| | 457.3 |
| | 428.0 |
| | 287.4 |
| | 228.7 |
| | 254.0 |
| Industrial Revenues | | 566.0 | | | 99.3 | | | 0 | | | 0 | | | 0 | | | 1.5 | | | 666.8 | |
Other Retail Revenues | | 21.7 |
| | — |
| | 57.6 |
| | 5.4 |
| | 9.8 |
| | 65.2 |
| | 6.4 |
| Other Retail Revenues | | 49.2 | | | 10.6 | | | 0 | | | 0 | | | 0 | | | 0 | | | 59.8 | |
Total Retail Revenues (a) | | 880.9 |
| | — |
| | 1,974.5 |
| | 1,362.6 |
| | 2,188.8 |
| | 1,134.6 |
| | 1,145.4 |
| |
Total Retail Revenues | | Total Retail Revenues | | 2,287.9 | | | 988.8 | | | 0 | | | 0 | | | 0 | | | 1.5 | | | 3,278.2 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Wholesale Revenues: | | | | | | | | | | | | | | | |
Generation Revenues (b) | | — |
| | — |
| | 194.1 |
| | 349.7 |
| | — |
| | 26.7 |
| | 168.8 |
| |
Transmission Revenues (c) | | 229.6 |
| | 612.9 |
| | 60.2 |
| | 16.9 |
| | 42.8 |
| | 29.4 |
| | 77.3 |
| |
Total Wholesale Revenues | | 229.6 |
| | 612.9 |
| | 254.3 |
| | 366.6 |
| | 42.8 |
| | 56.1 |
| | 246.1 |
| |
Wholesale and Competitive Retail Revenues: | | Wholesale and Competitive Retail Revenues: | |
Generation Revenues (a) | | Generation Revenues (a) | | 231.3 | | | 0 | | | 0 | | | 77.1 | | | 0 | | | (34.2) | | | 274.2 | |
Transmission Revenues (b) | | Transmission Revenues (b) | | 77.8 | | | 110.9 | | | 269.4 | | | 0 | | | 0 | | | (217.2) | | | 240.9 | |
Renewable Generation Revenues (c) | | Renewable Generation Revenues (c) | | 0 | | | 0 | | | 0 | | | 20.1 | | | 0 | | | 0 | | | 20.1 | |
Retail, Trading and Marketing Revenues (c) | | Retail, Trading and Marketing Revenues (c) | | 0 | | | 0 | | | 0 | | | 395.3 | | | 0 | | | 0.5 | | | 395.8 | |
Total Wholesale and Competitive Retail Revenues | | Total Wholesale and Competitive Retail Revenues | | 309.1 | | | 110.9 | | | 269.4 | | | 492.5 | | | 0 | | | (250.9) | | | 931.0 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Other Revenues from Contracts with Customers (d) | | 21.8 |
| | 8.7 |
| | 42.2 |
| | 71.0 |
| | 51.3 |
| | 14.6 |
| | 18.0 |
| |
Other Revenues from Contracts with Customers (c) | | Other Revenues from Contracts with Customers (c) | | 47.3 | | | 42.9 | | | 4.5 | | | 14.8 | | | 35.6 | | | (42.2) | | | 102.9 | |
| | | | | | | | | | | | | | | |
Total Revenues from Contracts with Customers | | 1,132.3 |
| | 621.6 |
| | 2,271.0 |
| | 1,800.2 |
| | 2,282.9 |
| | 1,205.3 |
| | 1,409.5 |
| Total Revenues from Contracts with Customers | | 2,644.3 | | | 1,142.6 | | | 273.9 | | | 507.3 | | | 35.6 | | | (291.6) | | | 4,312.1 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Other Revenues: | | | | | | | | | | | | | | | Other Revenues: | |
Alternative Revenues (e) | | (1.1 | ) | | (35.4 | ) | | (20.7 | ) | | (4.0 | ) | | (47.2 | ) | | 11.2 |
| | 2.3 |
| |
Other Revenues (f) | | 62.1 |
| | — |
| | (0.9 | ) | | — |
| | 82.3 |
| | — |
| | — |
| |
Alternative Revenues (c) | | Alternative Revenues (c) | | 1.2 | | | 5.1 | | | (0.9) | | | 0 | | | 0 | | | (16.8) | | | (11.4) | |
Other Revenues (c) | | Other Revenues (c) | | 0 | | | 38.9 | | | 0 | | | 26.4 | | | (11.2) | | | (39.8) | | | 14.3 | |
Total Other Revenues | | 61.0 |
| | (35.4 | ) | | (21.6 | ) | | (4.0 | ) | | 35.1 |
| | 11.2 |
| | 2.3 |
| Total Other Revenues | | 1.2 | | | 44.0 | | | (0.9) | | | 26.4 | | | (11.2) | | | (56.6) | | | 2.9 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Total Revenues | | $ | 1,193.3 |
| | $ | 586.2 |
| | $ | 2,249.4 |
| | $ | 1,796.2 |
| | $ | 2,318.0 |
| | $ | 1,216.5 |
| | $ | 1,411.8 |
| Total Revenues | | $ | 2,645.5 | | | $ | 1,186.6 | | | $ | 273.0 | | | $ | 533.7 | | | $ | 24.4 | | | $ | (348.2) | | | $ | 4,315.0 | |
| |
(a) | 2018 amounts have been revised to reflect the reclassification of certain customer accounts between Retail classes. This reclassification did not impact previously reported Total Retail Revenues. Management concluded that these prior period disclosure only errors were immaterial individually and in the aggregate. |
| |
(b) | Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $100 million primarily relating to the PPA with Kingsport. The remaining affiliated amounts were immaterial. |
| |
(c) | Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $448 million. The remaining affiliated amounts were immaterial. |
| |
(d) | Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $57 million primarily relating to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial. |
| |
(e) | The alternative revenue for OPCo was primarily the $48 million reduction in revenue relating to the Ohio Tax Reform settlement. |
| |
(f) | Amounts include affiliated and nonaffiliated revenues. |
(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $34 million. The remaining affiliated amounts were immaterial.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $197 million. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, 2020 | | | | | | | | | | | | |
| | AEP Texas | | AEPTCo | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in millions) | | | | | | | | | | | | |
Retail Revenues: | | | | | | | | | | | | | | |
Residential Revenues | | $ | 165.3 | | | $ | 0 | | | $ | 324.2 | | | $ | 222.6 | | | $ | 429.4 | | | $ | 195.8 | | | $ | 219.4 | |
Commercial Revenues | | 78.0 | | | 0 | | | 138.4 | | | 135.8 | | | 181.2 | | | 94.4 | | | 135.0 | |
Industrial Revenues | | 24.9 | | | 0 | | | 139.4 | | | 139.7 | | | 69.1 | | | 55.0 | | | 83.8 | |
Other Retail Revenues | | 6.9 | | | 0 | | | 17.6 | | | 1.6 | | | 3.1 | | | 18.4 | | | 2.3 | |
Total Retail Revenues | | 275.1 | | | 0 | | | 619.6 | | | 499.7 | | | 682.8 | | | 363.6 | | | 440.5 | |
| | | | | | | | | | | | | | |
Wholesale Revenues: | | | | | | | | | | | | | | |
Generation Revenues (a) | | 0 | | | 0 | | | 70.3 | | | 61.5 | | | 0 | | | 5.8 | | | 42.3 | |
| | | | | | | | | | | | | | |
Transmission Revenues (b) | | 101.8 | | | 305.7 | | | 30.8 | | | 7.4 | | | 17.2 | | | 8.5 | | | 28.7 | |
| | | | | | | | | | | | | | |
Total Wholesale Revenues | | 101.8 | | | 305.7 | | | 101.1 | | | 68.9 | | | 17.2 | | | 14.3 | | | 71.0 | |
| | | | | | | | | | | | | | |
Other Revenues from Contracts with Customers (c) | | 15.2 | | | 3.0 | | | 16.1 | | | 17.7 | | | 27.6 | | | 4.8 | | | 5.6 | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
Total Revenues from Contracts with Customers | | 392.1 | | | 308.7 | | | 736.8 | | | 586.3 | | | 727.6 | | | 382.7 | | | 517.1 | |
| | | | | | | | | | | | | | |
Other Revenues: | | | | | | | | | | | | | | |
Alternative Revenues (d) | | (0.7) | | | (4.6) | | | (1.1) | | | 0.4 | | | 10.0 | | | (0.5) | | | 0.2 | |
Other Revenues (d) | | 40.6 | | | 0 | | | 0 | | | 0 | | | 3.4 | | | 0 | | | 0 | |
| | | | | | | | | | | | | | |
Total Other Revenues | | 39.9 | | | (4.6) | | | (1.1) | | | 0.4 | | | 13.4 | | | (0.5) | | | 0.2 | |
| | | | | | | | | | | | | | |
Total Revenues | | $ | 432.0 | | | $ | 304.1 | | | $ | 735.7 | | | $ | 586.7 | | | $ | 741.0 | | | $ | 382.2 | | | $ | 517.3 | |
(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $28 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 $243 million. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $15 million primarily relating 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, 2019 | | | | | | | | | | | | |
| | AEP Texas | | AEPTCo | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in millions) | | | | | | | | | | | | |
Retail Revenues: | | | | | | | | | | | | | | |
Residential Revenues | | $ | 192.0 | | | $ | 0 | | | $ | 315.7 | | | $ | 198.2 | | | $ | 395.6 | | | $ | 231.9 | | | $ | 222.9 | |
Commercial Revenues | | 110.6 | | | 0 | | | 147.2 | | | 138.3 | | | 180.5 | | | 122.2 | | | 144.3 | |
Industrial Revenues | | 32.2 | | | 0 | | | 152.2 | | | 138.7 | | | 67.1 | | | 84.1 | | | 92.3 | |
Other Retail Revenues | | 7.5 | | | 0 | | | 18.5 | | | 1.9 | | | 3.1 | | | 24.9 | | | 2.3 | |
Total Retail Revenues | | 342.3 | | | 0 | | | 633.6 | | | 477.1 | | | 646.3 | | | 463.1 | | | 461.8 | |
| | | | | | | | | | | | | | |
Wholesale Revenues: | | | | | | | | | | | | | | |
Generation Revenues (a) | | 0 | | | 0 | | | 70.4 | | | 102.1 | | | 0 | | | 21.1 | | | 50.7 | |
Transmission Revenues (b) | | 97.7 | | | 256.4 | | | 26.2 | | | 6.4 | | | 13.7 | | | (3.4) | | | 30.0 | |
Total Wholesale Revenues | | 97.7 | | | 256.4 | | | 96.6 | | | 108.5 | | | 13.7 | | | 17.7 | | | 80.7 | |
| | | | | | | | | | | | | | |
Other Revenues from Contracts with Customers (c) | | 8.2 | | | 4.5 | | | 18.7 | | | 26.6 | | | 41.0 | | | 5.1 | | | 7.0 | |
| | | | | | | | | | | | | | |
Total Revenues from Contracts with Customers | | 448.2 | | | 260.9 | | | 748.9 | | | 612.2 | | | 701.0 | | | 485.9 | | | 549.5 | |
| | | | | | | | | | | | | | |
Other Revenues: | | | | | | | | | | | | | | |
Alternative Revenues (d) | | (0.7) | | | (1.2) | | | 6.6 | | | (1.1) | | | 12.4 | | | 7.1 | | | (4.0) | |
Other Revenues (d) | | 41.8 | | | 0 | | | 0 | | | 0 | | | (2.8) | | | 0 | | | 0 | |
Total Other Revenues | | 41.1 | | | (1.2) | | | 6.6 | | | (1.1) | | | 9.6 | | | 7.1 | | | (4.0) | |
| | | | | | | | | | | | | | |
Total Revenues | | $ | 489.3 | | | $ | 259.7 | | | $ | 755.5 | | | $ | 611.1 | | | $ | 710.6 | | | $ | 493.0 | | | $ | 545.5 | |
(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $32 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 $194 million. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $20 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 | | | | | | | | | | | | |
| | 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 | | $ | 2,789.1 | | | $ | 1,610.6 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 4,399.7 | |
Commercial Revenues | | 1,523.6 | | | 792.4 | | | 0 | | | 0 | | | 0 | | | 0 | | | 2,316.0 | |
Industrial Revenues | | 1,508.7 | | | 290.4 | | | 0 | | | 0 | | | 0 | | | (0.5) | | | 1,798.6 | |
Other Retail Revenues | | 118.2 | | | 32.1 | | | 0 | | | 0 | | | 0 | | | 0 | | | 150.3 | |
Total Retail Revenues | | 5,939.6 | | | 2,725.5 | | | 0 | | | 0 | | | 0 | | | (0.5) | | | 8,664.6 | |
| | | | | | | | | | | | | | |
Wholesale and Competitive Retail Revenues: | | | | | | | | | | | | | | |
Generation Revenues | | 447.4 | | | 0 | | | 0 | | | 106.1 | | | 0 | | | 0 | | | 553.5 | |
| | | | | | | | | | | | | | |
Transmission Revenues (a) | | 248.4 | | | 341.6 | | | 937.7 | | | 0 | | | 0 | | | (741.7) | | | 786.0 | |
| | | | | | | | | | | | | | |
Renewable Generation Revenues (b) | | 0 | | | 0 | | | 0 | | | 50.7 | | | 0 | | | (1.2) | | | 49.5 | |
Retail, Trading and Marketing Revenues (c) | | 0 | | | 0 | | | 0 | | | 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 | |
| | | | | | | | | | | | | | |
Other Revenues from Contracts with Customers (b) | | 124.1 | | | 112.3 | | | 17.5 | | | 1.7 | | | 84.4 | | | (115.7) | | | 224.3 | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
Total Revenues from Contracts with Customers | | 6,759.5 | | | 3,179.4 | | | 955.2 | | | 1,292.3 | | | 78.7 | | | (939.8) | | | 11,325.3 | |
| | | | | | | | | | | | | | |
Other Revenues: | | | | | | | | | | | | | | |
Alternative Revenues (b) | | (6.0) | | | 49.2 | | | (77.4) | | | 0 | | | 0 | | | 3.5 | | | (30.7) | |
Other Revenues (b) | | 0 | | | 78.1 | | | 0 | | | 13.2 | | | (6.7) | | | (71.3) | | | 13.3 | |
| | | | | | | | | | | | | | |
Total Other Revenues | | (6.0) | | | 127.3 | | | (77.4) | | | 13.2 | | | (6.7) | | | (67.8) | | | (17.4) | |
| | | | | | | | | | | | | | |
Total Revenues | | $ | 6,753.5 | | | $ | 3,306.7 | | | $ | 877.8 | | | $ | 1,305.5 | | | $ | 72.0 | | | $ | (1,007.6) | | | $ | 11,307.9 | |
(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $725 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 $81 million. The remaining affiliated amounts were immaterial.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Nine Months Ended September 30, 2019 | | | | | | | | | | | | |
| | 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 | | $ | 2,797.6 | | | $ | 1,609.1 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 4,406.7 | |
Commercial Revenues | | 1,641.2 | | | 889.4 | | | 0 | | | 0 | | | 0 | | | 0 | | | 2,530.6 | |
Industrial Revenues | | 1,647.3 | | | 332.6 | | | 0 | | | 0 | | | 0 | | | 0 | | | 1,979.9 | |
Other Retail Revenues | | 136.1 | | | 32.8 | | | 0 | | | 0 | | | 0 | | | 0 | | | 168.9 | |
Total Retail Revenues | | 6,222.2 | | | 2,863.9 | | | 0 | | | 0 | | | 0 | | | 0 | | | 9,086.1 | |
| | | | | | | | | | | | | | |
Wholesale and Competitive Retail Revenues: | | | | | | | | | | | | | | |
Generation Revenues (a) | | 661.9 | | | 0 | | | 0 | | | 282.0 | | | 0 | | | (105.5) | | | 838.4 | |
Transmission Revenues (b) | | 215.4 | | | 324.0 | | | 814.3 | | | 0 | | | 0 | | | (603.6) | | | 750.1 | |
Renewable Generation Revenues (c) | | 0 | | | 0 | | | 0 | | | 39.0 | | | 0 | | | 0.5 | | | 39.5 | |
Retail, Trading and Marketing Revenues (c) | | 0 | | | 0 | | | 0 | | | 1,049.5 | | | 0 | | | 0 | | | 1,049.5 | |
Total Wholesale and Competitive Retail Revenues | | 877.3 | | | 324.0 | | | 814.3 | | | 1,370.5 | | | 0 | | | (708.6) | | | 2,677.5 | |
| | | | | | | | | | | | | | |
Other Revenues from Contracts with Customers (c) | | 128.8 | | | 127.6 | | | 12.6 | | | 4.5 | | | 80.4 | | | (113.6) | | | 240.3 | |
| | | | | | | | | | | | | | |
Total Revenues from Contracts with Customers | | 7,228.3 | | | 3,315.5 | | | 826.9 | | | 1,375.0 | | | 80.4 | | | (822.2) | | | 12,003.9 | |
| | | | | | | | | | | | | | |
Other Revenues: | | | | | | | | | | | | | | |
Alternative Revenues (c) | | (55.7) | | | 21.5 | | | (18.6) | | | 0 | | | 0 | | | (60.3) | | | (113.1) | |
Other Revenues (c) | | 0 | | | 117.3 | | | 0 | | | 53.2 | | | (6.7) | | | (109.2) | | | 54.6 | |
Total Other Revenues | | (55.7) | | | 138.8 | | | (18.6) | | | 53.2 | | | (6.7) | | | (169.5) | | | (58.5) | |
| | | | | | | | | | | | | | |
Total Revenues | | $ | 7,172.6 | | | $ | 3,454.3 | | | $ | 808.3 | | | $ | 1,428.2 | | | $ | 73.7 | | | $ | (991.7) | | | $ | 11,945.4 | |
(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $105 million. The remaining affiliated amounts were immaterial.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $596 million. The remaining affiliated amounts were immaterial.
(c)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 | | | $ | 0 | | | $ | 954.4 | | | $ | 610.8 | | | $ | 1,162.6 | | | $ | 463.5 | | | $ | 498.7 | |
Commercial Revenues | | 285.2 | | | 0 | | | 390.6 | | | 376.0 | | | 507.3 | | | 247.8 | | | 351.2 | |
Industrial Revenues | | 91.4 | | | 0 | | | 415.0 | | | 408.2 | | | 199.1 | | | 170.8 | | | 245.9 | |
Other Retail Revenues | | 22.3 | | | 0 | | | 50.9 | | | 5.0 | | | 9.8 | | | 51.2 | | | 6.6 | |
Total Retail Revenues | | 846.7 | | | 0 | | | 1,810.9 | | | 1,400.0 | | | 1,878.8 | | | 933.3 | | | 1,102.4 | |
| | | | | | | | | | | | | | |
Wholesale Revenues: | | | | | | | | | | | | | | |
Generation Revenues (a) | | 0 | | | 0 | | | 185.3 | | | 215.5 | | | 0 | | | 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 | | | 0 | | | 0 | | | 0 | | | 13.3 | | | 0 | | | 0 | |
| | | | | | | | | | | | | | |
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.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Nine Months Ended September 30, 2019 | | | | | | | | | | | | |
| | AEP Texas | | AEPTCo | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in millions) | | | | | | | | | | | | |
Retail Revenues: | | | | | | | | | | | | | | |
Residential Revenues | | $ | 454.9 | | | $ | 0 | | | $ | 944.7 | | | $ | 558.8 | | | $ | 1,155.5 | | | $ | 519.6 | | | $ | 503.7 | |
Commercial Revenues | | 314.5 | | | 0 | | | 421.5 | | | 371.4 | | | 573.7 | | | 304.3 | | | 371.1 | |
Industrial Revenues | | 98.8 | | | 0 | | | 444.3 | | | 411.9 | | | 233.9 | | | 238.1 | | | 257.2 | |
Other Retail Revenues | | 22.7 | | | 0 | | | 56.5 | | | 5.4 | | | 9.8 | | | 63.1 | | | 6.7 | |
Total Retail Revenues | | 890.9 | | | 0 | | | 1,867.0 | | | 1,347.5 | | | 1,972.9 | | | 1,125.1 | | | 1,138.7 | |
| | | | | | | | | | | | | | |
Wholesale Revenues: | | | | | | | | | | | | | | |
Generation Revenues (a) | | 0 | | | 0 | | | 200.1 | | | 327.4 | | | 0 | | | 35.5 | | | 152.7 | |
Transmission Revenues (b) | | 282.0 | | | 775.3 | | | 77.6 | | | 18.8 | | | 42.0 | | | 21.9 | | | 78.0 | |
Total Wholesale Revenues | | 282.0 | | | 775.3 | | | 277.7 | | | 346.2 | | | 42.0 | | | 57.4 | | | 230.7 | |
| | | | | | | | | | | | | | |
Other Revenues from Contracts with Customers (c) | | 22.9 | | | 12.6 | | | 48.2 | | | 76.2 | | | 113.3 | | | 16.7 | | | 20.1 | |
| | | | | | | | | | | | | | |
Total Revenues from Contracts with Customers | | 1,195.8 | | | 787.9 | | | 2,192.9 | | | 1,769.9 | | | 2,128.2 | | | 1,199.2 | | | 1,389.5 | |
| | | | | | | | | | | | | | |
Other Revenues: | | | | | | | | | | | | | | |
Alternative Revenues (d) | | (0.4) | | | (17.8) | | | 11.2 | | | (1.4) | | | 22.0 | | | (25.3) | | | (47.4) | |
Other Revenues (d) | | 122.6 | | | 0 | | | 0 | | | 0 | | | 3.8 | | | 0 | | | 0 | |
Total Other Revenues | | 122.2 | | | (17.8) | | | 11.2 | | | (1.4) | | | 25.8 | | | (25.3) | | | (47.4) | |
| | | | | | | | | | | | | | |
Total Revenues | | $ | 1,318.0 | | | $ | 770.1 | | | $ | 2,204.1 | | | $ | 1,768.5 | | | $ | 2,154.0 | | | $ | 1,173.9 | | | $ | 1,342.1 | |
(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $96 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 $587 million. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $57 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, 2019.2020. 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 | | 2020 | | 2021-2022 | | 2023-2024 | | After 2024 | | Total |
| | (in millions) | | | | | | | | |
AEP | | $ | 263.8 | | | $ | 188.3 | | | $ | 164.2 | | | $ | 223.4 | | | $ | 839.7 | |
AEP Texas | | 108.2 | | | 0 | | | 0 | | | 0 | | | 108.2 | |
AEPTCo | | 274.8 | | | 0 | | | 0 | | | 0 | | | 274.8 | |
APCo | | 40.1 | | | 33.1 | | | 26.6 | | | 11.6 | | | 111.4 | |
I&M | | 8.6 | | | 10.9 | | | 8.8 | | | 4.5 | | | 32.8 | |
OPCo | | 16.5 | | | 5.3 | | | 0 | | | 0 | | | 21.8 | |
PSO | | 3.8 | | | 0 | | | 0 | | | 0 | | | 3.8 | |
SWEPCo | | 10.3 | | | 0 | | | 0 | | | 0 | | | 10.3 | |
|
| | | | | | | | | | | | | | | | | | | | |
Company | | 2019 | | 2020-2021 | | 2022-2023 | | After 2023 | | Total |
| | (in millions) |
AEP | | $ | 252.7 |
| | $ | 209.7 |
| | $ | 160.9 |
| | $ | 285.5 |
| | $ | 908.8 |
|
AEP Texas | | 96.8 |
| | — |
| | — |
| | — |
| | 96.8 |
|
AEPTCo | | 225.8 |
| | — |
| | — |
| | — |
| | 225.8 |
|
APCo | | 36.4 |
| | 32.5 |
| | 25.5 |
| | 11.6 |
| | 106.0 |
|
I&M | | 7.2 |
| | 8.9 |
| | 8.8 |
| | 4.4 |
| | 29.3 |
|
OPCo | | 17.8 |
| | 7.5 |
| | — |
| | — |
| | 25.3 |
|
PSO | | 4.3 |
| | — |
| | — |
| | — |
| | 4.3 |
|
SWEPCo | | 9.8 |
| | — |
| | — |
| | — |
| | 9.8 |
|
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, 20192020 and December 31, 2018.2019.
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 sheet 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, 20192020 and December 31, 2018.2019.
Accounts Receivable from Contracts with Customers
Accounts receivable from contracts with customers are presented on the Registrants’Registrant Subsidiaries’ balance sheets within the Accounts Receivable - Customers line item. The Registrants’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, 20192020 and December 31, 2018.2019. See “Securitized Accounts Receivable - AEP Credit” section of Note 1312 for additional information related to AEP Credit’s securitized accounts receivable.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 | | September 30, 2020 | | December 31, 2019 |
| | (in millions) | | |
AEPTCo | | $ | 79.9 | | | $ | 65.9 | |
APCo | | 49.3 | | | 47.3 | |
I&M | | 30.5 | | | 37.1 | |
OPCo | | 36.5 | | | 33.9 | |
PSO | | 11.0 | | | 9.7 | |
SWEPCo | | 18.4 | | | 17.6 | |
|
| | | | | | | | |
Company | | September 30, 2019 | | December 31, 2018 |
| | (in millions) |
AEPTCo | | $ | 69.9 |
| | $ | 58.6 |
|
APCo | | 41.4 |
| | 52.5 |
|
I&M | | 28.0 |
| | 35.3 |
|
OPCo | | 29.2 |
| | 46.1 |
|
PSO | | 10.3 |
| | 12.4 |
|
SWEPCo | | 17.8 |
| | 16.3 |
|
CONTROLS AND PROCEDURES
During the third quarter of 2019,2020, 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, 2019,2020, 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.
The onlyThere 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 20192020 that materially affected, or is reasonably likely to materially affect, the Registrants’ internal control over financial reporting, relates to the Registrants’ conversion of work management, asset management, and source to settle (procurement, supply chain, and accounts payable) business processes to a newly implemented third-party software solution. In connection with this conversion, management will continue to evaluate and monitor the Registrants’ internal controls over financial reporting to ensure controls remain effective. There were no other changes in the Registrants’ internal control over financial reporting during the quarter ended September 30, 2019, that have materially affected, or are 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 AEP 2019 Annual Report on Form 10-K for the year ended December 31, 2018 includes a detailed discussion of risk factors. As of September 30, 2019, there have been no material changes to2020, the risk factors previously disclosedappearing in AEP’s 2019 Annual Report are supplemented and updated as follows:
AEP’s Financial Condition and Results of Operations could continue to be Adversely Affected by the Ongoing Coronavirus Pandemic
AEP is responding to the global 2019 novel coronavirus (COVID-19) pandemic by taking steps to mitigate the potential risks posed by its spread. 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 continue to disrupt economic activity in AEP’s service territory and could reduce future demand for energy, particularly from commercial and industrial customers. AEP provides a critical service to its customers which means that it must keep its employees who operate its businesses safe and minimize unnecessary risk of exposure to the virus. AEP has updated and implemented a company-wide pandemic plan to address specific aspects of the coronavirus pandemic. This plan guides AEP’s emergency response, business continuity, and the precautionary measures that AEP is taking on behalf its employees and the public. AEP has taken extra precautions for its employees who work in the 2018 Annual Reportfield and for employees who continue to work in its facilities, and AEP has implemented work from home policies where appropriate.
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. These conditions might also impact the Registrants’ access to and cost of capital. This is a rapidly evolving situation that could lead to extended disruption of economic activity in AEP’s markets.
AEP has instituted measures to ensure its supply chain remains open; however, there could be global shortages that will impact AEP’s maintenance and capital programs that AEP currently cannot anticipate. AEP will continue to monitor developments affecting both its workforce and its customers, and will take additional precautions that are determined to be necessary in order to mitigate the impacts.
AEP continues to implement strong physical and cyber security measures to ensure that its systems remain functional in order to both serve its operational needs with a remote workforce and keep them running to ensure uninterrupted service to customers.
In addition, the economic disruptions caused by COVID-19 could also adversely impact the impairment risks for certain long-lived assets, equity method investments and goodwill. Market volatility and reduction in collections coupled with longer collection periods due to the expansion of customer payment arrangements could reduce cash from operations and cause an adverse impact to liquidity.
AEP will continue to review and modify its plans as conditions change. Despite AEP’s efforts to manage these impacts, their ultimate impact also depends on Form 10-K.factors beyond AEP’s knowledge or control, including the duration and severity of this outbreak, its impact on economic and market conditions, as well as third-party actions taken to contain its spread and mitigate its public health effects. Therefore, AEP currently cannot estimate the potential impact to its financial position, results of operations and cash flows.
Ohio House Bill 6 (HB 6), which provides for beneficial cost recovery for OPCo and for plants owned by OVEC, has come under public scrutiny (Applies to AEP and OPCo)
In 2019, Ohio adopted and implemented HB 6. Among other provisions, HB 6 phased out current energy efficiency including lost shared savings revenues of $26 million annually and renewable mandates no later than 2020 and after 2026, respectively. HB 6 also provided for the recovery of existing renewable energy contracts on a bypassable basis through 2032, and included a provision for recovery of OVEC coal-fired unit costs through 2030. AEP and OPCo engaged in lobbying efforts and provided testimony during the legislative process in support of HB 6. 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. In light of the allegations in the indictment, proposed legislation has been introduced that would repeal HB 6. The outcome of the U.S. Attorney’s Office investigation and its impact on HB 6 is not known. If the provisions of HB 6 were to be eliminated, it is unclear whether and in what form the Ohio General Assembly would pass new legislation addressing similar issues. To the extent that OPCo is unable to recover the costs of renewable energy contracts on a bypassable basis by the end of 2032, recover costs of OVEC after 2030 or fully recover energy efficiency costs through 2020, it could reduce future net income and cash flows and impact financial condition. In addition, the impact of continued public scrutiny of HB 6 is not known, and may have an adverse impact on AEP and OPCo, including their relationship with regulatory and legislative authorities, customers and other stakeholders and their potential involvement with various current or future litigation arising out HB 6.
OVEC may require additional liquidity and other capital support (Applies to AEP, APCo, I&M and OPCo)
AEP and several nonaffiliated utility companies own OVEC. The Inter-Company Power Agreement (ICPA) defines the rights and obligations and sets the power participation ratio of the parties to it. Under the ICPA, parties are entitled to receive and are obligated to pay for all OVEC capacity (approximately 2,400 MWs) in proportion to their respective power participation ratios. The aggregate power participation ratio of APCo, I&M and OPCo is 43.47%. If a party fails to make payments owed by it under the ICPA, OVEC may not have sufficient funds to honor its payment obligations, including its ongoing operating expenses as well as its indebtedness. As of September 30, 2020, OVEC has outstanding indebtedness of approximately $1.3 billion, of which APCo, I&M, and OPCo are collectively responsible for $563 million through the ICPA. Although they are not an obligor or guarantor, APCo, I&M, and OPCo are responsible for their respective ratio of OVEC’s outstanding debt through the ICPA.
Energy Harbor (formerly FirstEnergy Solutions), a nonaffiliated party, whose aggregate power participation ratio is 4.85% under the ICPA, filed a petition seeking protection under the bankruptcy law. In May 2020, Energy Harbor entered into a bankruptcy settlement and resumed performance under the ICPA as of June 1, 2020. In July 2020, federal prosecutors arrested the Speaker of the Ohio House of Representatives and four other individuals alleging that they engaged in a bribery and money laundering scheme connected to the passage of HB 6. Subsequently, proposed legislation was introduced that would repeal HB 6. If HB 6 is repealed and not replaced, Energy Harbor’s financial ability to participate in the ICPA could be adversely impacted. Management is currently unable to predict the outcome of the proposed legislation and will continue to monitor the legislative process and any potential impact to OVEC’s cash flows or financial condition. If OVEC does not have sufficient funds to honor its payment obligations, there is risk that APCo, I&M and/or OPCo may need to make payments in addition to their power participation ratio payments. Further, if OVEC’s indebtedness is accelerated for any reason, there is risk that APCo, I&M and/or OPCo may be required to pay some or all of such accelerated indebtedness in amounts equal to their aggregate power participation ratio of 43.47%.
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, 2019.2020.
Item 5. Other Information
NoneOn October 21, 2020, the Company entered into a separation, release of all claims and noncompetition agreement with Ms. Hillebrand pursuant to which the Company will provide $1,106,875 in severance benefits due to the elimination of her position and separation from service, effective December 31, 2020. This amount is equivalent to 1× her annual base salary and target annual incentive award, which is the current severance benefit for all participants under AEP’s Executive Severance plan. Half of this amount will be paid 6 months after her termination date and the remainder will be paid over the following 13 biweekly pay periods. In addition, the Company agreed to provide $500,000 in unrestricted AEP shares under AEP’s Long-Term Incentive Plan upon her separation from AEP service. The number of unrestricted AEP shares provided to Ms. Hillebrand will be determined by dividing the $500,000 value by the closing price of AEP Common Stock as reported by NASDAQ on December 31, 2020 and will be granted under AEP’s Long-Term Incentive Plan. This agreement also contains among other provisions, a one-year non-competition agreement and affirms certain non-solicitation, confidentiality and cooperation stipulations.
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.
| | | | | | | | | | | | | | |
Exhibit | | Description | | Previously Filed as Exhibit to: |
| | | | |
AEP‡ File No. 1-3525 | | | | |
| | | | |
Exhibit4.1 | | Description | | Previously FiledPurchase Contract dated as Exhibit to: |
| | |
AEPTCo‡ File No. 333-217143 | | |
| | | | |
*4.3 | | Company Order and Officer’s Certificate,of August 14, 2020, between AEP Transmissionthe Company LLC and The Bank of New York Mellon Trust Company, N.A., as trustee,purchase contract agent, collateral agent, custodial agent and securities intermediary | | |
4.2 | | Junior Subordinated Indenture, dated March 1, 2008, between the termsCompany and The Bank of New York Mellon Trust Company, N.A., as Trustee for the Series L NotesJunior Subordinated Debentures | | Registration Statement No. 333-156387, Exhibits 4(c) and 4(d); Form 8-K, Exhibit 4(a)4.3, dated September 9,March 19, 2019 |
4.3 | | Supplemental Indenture No. 2, dated August 14, 2020, from the Company to The Bank of New York Mellon Trust Company, N.A., as trustee | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
SWEPCo‡ File No. 1-3146 | | | | |
| | | | |
4.4 | | Amendment to Certificate of Incorporation filed with Delaware Secretary of State effective August 31, 2020 to authorize a reverse stock split of the common stock, eliminate the authorized preferred stock and reduce the authorized number of shares of common stock | | |
The exhibits designated with an (X) in the table below are being filed on behalf of the Registrants.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Exhibit | | Description | | AEP | | AEP Texas
| | AEPTCo | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
10.1 | | AEP System Incentive Compensation DeferralStock Ownership Requirement Plan As Amended and Restated effective JuneEffective October 1, 20192020 | | | | | | | | | | | | | | | | |
10.2 | | AEP Aircraft TimesharingRetainer Deferral Plan For Non-Employee Directors As Amended and Restated Effective October 1, 2020 | | | | | | | | | | | | | | | | |
10.3 | | AEP Stock Unit Accumulation Plan For Non-Employee Directors As Amended Effective October 1, 2020 | | | | | | | | | | | | | | | | |
10.4 | | Severance, Stock Award, Release of All Claims and Noncompetition Agreement dated October 1, 201921, 2020 between American Electric Power Service CorporationAEPSC and Nicholas K. AkinsLana Hillebrand | | | | | | | | | | | | | | | | |
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.INSExhibit | | Description | | AEP | | AEP Texas | | AEPTCo | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
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 |
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 24, 2019
22, 2020