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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
| | |
| ☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the Quarterly Period Ended SeptemberJune 30, 20212022
or
| | |
| ☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
| | | | | | | | | | | | | | |
| Commission File Number | | Name of Registrant; State or Other Jurisdiction of Incorporation; Address of Principal Executive Offices; and Telephone Number | | IRS Employer Identification Number |
| | | | |
| 001-16169 | | EXELON CORPORATION | | 23-2990190 |
| | (a Pennsylvania corporation) 10 South Dearborn Street P.O. Box 805379 Chicago, Illinois 60680-5379 (800) 483-3220 | | |
| | | | |
333-85496 | | EXELON GENERATION COMPANY, LLC | | 23-3064219 |
| | (a Pennsylvania limited liability company)
300 Exelon Way
Kennett Square, Pennsylvania 19348-2473
(610) 765-5959
| | |
| | | | |
| 001-01839 | | COMMONWEALTH EDISON COMPANY | | 36-0938600 |
| | (an Illinois corporation) 10 South Dearborn Street 49th Floor
Chicago, Illinois 60603-2300 (312) 394-4321 | | |
| | | | |
| 000-16844 | | PECO ENERGY COMPANY | | 23-0970240 |
| | (a Pennsylvania corporation) P.O. Box 8699 2301 Market Street Philadelphia, Pennsylvania 19101-8699 (215) 841-4000 | | |
| | | | |
| 001-01910 | | BALTIMORE GAS AND ELECTRIC COMPANY | | 52-0280210 |
| | (a Maryland corporation) 2 Center Plaza 110 West Fayette Street Baltimore, Maryland 21201-3708 (410) 234-5000 | | |
| | | | |
| 001-31403 | | PEPCO HOLDINGS LLC | | 52-2297449 |
| | (a Delaware limited liability company) 701 Ninth Street, N.W. Washington, District of Columbia 20068-0001 (202) 872-2000 | | |
| | | | |
| 001-01072 | | POTOMAC ELECTRIC POWER COMPANY | | 53-0127880 |
| | (a District of Columbia and Virginia corporation) 701 Ninth Street, N.W. Washington, District of Columbia 20068-000120068-001 (202) 872-2000 | | |
| | | | |
| 001-01405 | | DELMARVA POWER & LIGHT COMPANY | | 51-0084283 |
| | (a Delaware and Virginia corporation) 500 North Wakefield Drive Newark, Delaware 19702-5440 (202) 872-2000 | | |
| | | | |
| 001-03559 | | ATLANTIC CITY ELECTRIC COMPANY | | 21-0398280 |
| | (a New Jersey corporation) 500 North Wakefield Drive Newark, Delaware 19702-5440 (202) 872-2000 | | |
Securities registered pursuant to Section 12(b) of the Act:
| | | | | | | | | | | | | | |
| Title of each class | | Trading Symbol(s) | | Name of each exchange on which registered |
| EXELON CORPORATION: | | | | |
| Common stock, without par value | | EXC | | The Nasdaq Stock Market LLC |
| | | | |
| PECO ENERGY COMPANY: | | | | |
| Trust Receipts of PECO Energy Capital Trust III, each representing a 7.38% Cumulative Preferred Security, Series D, $25 stated value, issued by PECO Energy Capital, L.P. and unconditionally guaranteed by PECO Energy Company | | EXC/28 | | New York Stock Exchange |
Indicate by check mark whether the registrant (1) has 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 registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o
Indicate by check mark whether the registrant has 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 registrant was required to submit and post such files). Yes x No o
Indicate by check mark whether the registrant 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.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Exelon Corporation | Large Accelerated Filer | x | Accelerated Filer | ☐ | Non-accelerated Filer | ☐ | Smaller Reporting Company | ☐ | Emerging Growth Company | ☐ |
Exelon Generation Company, LLC | Large Accelerated Filer | ☐ | Accelerated Filer | ☐ | Non-accelerated Filer | x | Smaller Reporting Company | ☐ | Emerging Growth Company | ☐ |
| Commonwealth Edison Company | Large Accelerated Filer | ☐ | Accelerated Filer | ☐ | Non-accelerated Filer | x | Smaller Reporting Company | ☐ | Emerging Growth Company | ☐ |
| PECO Energy Company | Large Accelerated Filer | ☐ | Accelerated Filer | ☐ | Non-accelerated Filer | x | Smaller Reporting Company | ☐ | Emerging Growth Company | ☐ |
| Baltimore Gas and Electric Company | Large Accelerated Filer | ☐ | Accelerated Filer | ☐ | Non-accelerated Filer | x | Smaller Reporting Company | ☐ | Emerging Growth Company | ☐ |
| Pepco Holdings LLC | Large Accelerated Filer | ☐ | Accelerated Filer | ☐ | Non-accelerated Filer | x | Smaller Reporting Company | ☐ | Emerging Growth Company | ☐ |
| Potomac Electric Power Company | Large Accelerated Filer | ☐ | Accelerated Filer | ☐ | Non-accelerated Filer | x | Smaller Reporting Company | ☐ | Emerging Growth Company | ☐ |
| Delmarva Power & Light Company | Large Accelerated Filer | ☐ | Accelerated Filer | ☐ | Non-accelerated Filer | x | Smaller Reporting Company | ☐ | Emerging Growth Company | ☐ |
| Atlantic City Electric 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 registrant has 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 registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No x
The number of shares outstanding of each registrant’s common stock as of SeptemberJune 30, 20212022 was:
| | | | | |
| Exelon Corporation Common Stock, without par value | 978,317,787 |
Exelon Generation Company, LLC | not applicable980,472,436 |
| Commonwealth Edison Company Common Stock, $12.50 par value | 127,021,383127,021,391 |
| PECO Energy Company Common Stock, without par value | 170,478,507 |
| Baltimore Gas and Electric Company Common Stock, without par value | 1,000 |
| Pepco Holdings LLC | not applicable |
| Potomac Electric Power Company Common Stock, $0.01 par value | 100 |
| Delmarva Power & Light Company Common Stock, $2.25 par value | 1,000 |
| Atlantic City Electric Company Common Stock, $3.00 par value | 8,546,017 |
TABLE OF CONTENTS
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| GLOSSARY OF TERMS AND ABBREVIATIONS |
| Exelon Corporation and Related Entities |
| Exelon | | Exelon Corporation |
Generation | | Exelon Generation Company, LLC |
| ComEd | | Commonwealth Edison Company |
| PECO | | PECO Energy Company |
| BGE | | Baltimore Gas and Electric Company |
| Pepco Holdings or PHI | | Pepco Holdings LLC |
| Pepco | | Potomac Electric Power Company |
| DPL | | Delmarva Power & Light Company |
| ACE | | Atlantic City Electric Company |
| Registrants | | Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE, collectively |
| Utility Registrants | | ComEd, PECO, BGE, Pepco, DPL, and ACE, collectively |
| ACE Funding or ATF | | Atlantic City Electric Transition Funding LLC |
Antelope Valley | | Antelope Valley Solar Ranch One |
| | |
| BSC | | Exelon Business Services Company, LLC |
CENG | | Constellation Energy Nuclear Group, LLC |
Constellation | | Constellation Energy Group, Inc. |
EGR IV | | ExGen Renewables IV, LLC |
EGRP | | ExGen Renewables Partners, LLC |
| Exelon Corporate | | Exelon in its corporate capacity as a holding company |
FitzPatrick | | James A. FitzPatrick nuclear generating station |
NER | | NewEnergy Receivables LLC |
| PCI | | Potomac Capital Investment Corporation and its subsidiaries |
| PECO Trust III | | PECO Energy Capital Trust III |
| PECO Trust IV | | PECO Energy Capital Trust IV |
Pepco Energy Services | | Pepco Energy Services, Inc. and its subsidiaries |
| PHI Corporate | | PHI in its corporate capacity as a holding company |
| PHISCO | | PHI Service Company |
RPGFormer Related Entities |
| Constellation | | Renewable Power GenerationConstellation Energy Corporation |
SolGenGeneration | | SolGen,Constellation Energy Generation, LLC |
TMI | | Three Mile Island nuclear facility (formerly Exelon Generation Company, LLC, a subsidiary of Exelon prior to separation on February 1, 2022) |
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| GLOSSARY OF TERMS AND ABBREVIATIONS |
| Other Terms and Abbreviations | | |
| 2021 Form 10-K | | The Registrants' Annual Report on Form 10-K for the year ended December 31, 2021 filed with the SEC on February 25, 2022 |
| 2021 Recast Form 10-K | | The Registrants' Current Report on Form 8-K filed with the SEC on June 30, 2022 to recast Exelon's consolidated financial statements and certain other financial information originally included in the 2021 Form 10-K |
Note - of the 20202021 Recast Form 10-K | | Reference to specific Combined Note to Consolidated Financial Statements within Exelon's 2020 Annual Report onin the 2021 Recast Form 10-K |
| AEC | | Alternative Energy Credit that is issued for each megawatt hour of generation from a qualified alternative energy source |
AESO | | Alberta Electric Systems Operator |
| AFUDC | | Allowance for Funds Used During Construction |
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| AMI | | Advanced Metering Infrastructure |
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| AOCI | | Accumulated Other Comprehensive Income (Loss) |
ARC | | Asset Retirement Cost |
| ARO | | Asset Retirement Obligation |
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| BGS | | Basic Generation Service |
CAISOCEJA (formerly Clean Energy Law in the Exelon 2021 Form 10-K) | | California Independent System Operator |
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CBA | | Collective Bargaining Agreement
Climate and Equitable Jobs Act; Illinois Public Act 102-0662 signed into law on September 15, 2021 |
| CERCLA | | Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended |
CESCIP | | Clean Energy Standard |
| | |
Clean Energy Law | | Illinois Public Act 102-0662 signed into law on September 15, 2021 |
Clean Water Act | | Federal Water Pollution Control Amendments of 1972, as amendedConservation Incentive Program |
| CMC | | Carbon Mitigation Credit |
| CODM | | Chief Operating Decision Maker(s) |
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| DC PLUG | | District of Columbia Power Line Undergrounding Initiative |
| DCPSC | | Public Service Commission of the District of Columbia |
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DOEDEPSC | | United States Department of EnergyDelaware Public Service Commission |
| DOEE | | District of Columbia Department of Energy & Environment |
DOJ | | United States Department of Justice |
| DPP | | Deferred Purchase Price |
DPSC | | Delaware Public Service Commission |
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EDF | | Electricite de France SA and its subsidiaries |
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| EIMA | | Energy Infrastructure Modernization Act (Illinois Senate Bill 1652 and Illinois House Bill 3036) |
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| EPA | | United States Environmental Protection Agency |
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| ERCOT | | Electric Reliability Council of Texas |
| ERISA | | Employee Retirement Income Security Act of 1974, as amended |
| ETAC | | |
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| | Energy Transition Assistance Charge |
| FEJA | | Illinois Public Act 99-0906 or Future Energy Jobs Act |
| FERC | | Federal Energy Regulatory Commission |
FRCC | | Florida Reliability Coordinating Council |
FRR | | Fixed Resource Requirement |
| GAAP | | Generally Accepted Accounting Principles in the United States |
| GCR | | Gas Cost Rate |
GHG | | Greenhouse Gas |
| GSA | | Generation Supply Adjustment |
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IBEWGWh | | International Brotherhood of Electrical Workers
Gigawatt hour |
| ICC | | Illinois Commerce Commission |
ICEIllinois Settlement Legislation | | Intercontinental ExchangeLegislation enacted in 2007 affecting electric utilities in Illinois |
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| IPA | | Illinois Power Agency |
| IRC | | Internal Revenue Code |
| IRS | | Internal Revenue Service |
| LIBOR | | London Interbank Offered Rate |
| MDPSC | | Maryland Public Service Commission |
| MGP | | Manufactured Gas Plant |
| mmcf | | Million Cubic Feet |
| | | | | | | | |
| GLOSSARY OF TERMS AND ABBREVIATIONS |
| Other Terms and Abbreviations | | |
ISO | | Independent System Operator |
ISO-NE | | Independent System Operator New England Inc. |
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LIBOR | | London Interbank Offered Rate |
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MDE | | Maryland Department of the Environment |
MDPSC | | Maryland Public Service Commission |
MGP | | Manufactured Gas Plant |
MISO | | Midcontinent Independent System Operator, Inc. |
mmcf | | Million Cubic Feet |
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MOPR | | Minimum Offer Price Rule |
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MPSC | | Missouri Public Service Commission |
| MW | | Megawatt |
| MWh | | Megawatt hour |
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NAV | | Net Asset Value |
| N/A | | Not applicable |
| NDT | | Nuclear Decommissioning Trust |
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NERC | | North American Electric Reliability Corporation |
NGX | | Natural Gas Exchange |
| NJBPU | | New Jersey Board of Public Utilities |
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Non-Regulatory Agreement Units | | Nuclear generating units or portions thereof whose decommissioning-related activities are not subject to contractual elimination under regulatory accounting |
NOSA | | Nuclear Operating Services Agreement |
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| NPNS | | Normal Purchase Normal Sale scope exception |
| NPS | | National Park Service |
NRC | | Nuclear Regulatory Commission |
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NYISO | | New York Independent System Operator Inc. |
NYMEX | | New York Mercantile Exchange |
NYPSC | | New York Public Service Commission |
| OCI | | Other Comprehensive Income |
OIESO | | Ontario Independent Electricity System Operator |
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| OPEB | | Other Postretirement Employee Benefits |
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| PAPUC | | Pennsylvania Public Utility Commission |
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| PGC | | Purchased Gas Cost Clause |
PG&E | | Pacific Gas and Electric Company |
| PJM | | PJM Interconnection, LLC |
| POLR | | Provider of Last Resort |
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| PPA | | Power Purchase Agreement |
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Price-Anderson ActPP&E | | Price-Anderson Nuclear Industries Indemnity Act of 1957Property, plant, and equipment |
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| PRP | | Potentially Responsible Parties |
PSDAR | | Post-Shutdown Decommissioning Activities Report |
PSEG | | Public Service Enterprise Group Incorporated |
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PUCT | | Public Utility Commission of Texas |
| REC | | Renewable Energy Credit which is issued for each megawatt hour of generation from a qualified renewable energy source |
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| Regulatory Agreement Units | | Nuclear generating units or portions thereof whose decommissioning-related activities are subject to contractual elimination under regulatory accounting |
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| RFP | | Request for Proposal |
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GLOSSARY OF TERMS AND ABBREVIATIONS |
Other Terms and Abbreviations | | |
| Rider | | Reconcilable Surcharge Recovery Mechanism |
RMC | | Risk Management Committee |
| ROE | | Return on Equityequity |
| ROU | | |
| | Right-of-use |
| RPS | | Renewable Energy Portfolio Standards |
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| RTO | | Regional Transmission Organization |
S&P | | Standard & Poor’s Ratings Services |
| SEC | | United States Securities and Exchange Commission |
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SERCSOFR | | SERC Reliability Corporation (formerly Southeast Electric Reliability Council) |
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SNF | | Spent Nuclear FuelSecured Overnight Financing Rate |
| SOS | | Standard Offer Service |
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| STRIDE | | Maryland Strategic Infrastructure Development and Enhancement Program |
| TCJA | | Tax Cuts and Jobs Act |
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| Transition Bonds | | Transition Bonds issued by ACE Funding |
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UGSOA | | United Government Security Officers of America |
U.S. Court of Appeals for the D.C. Circuit | | United States Court of Appeals for the District of Columbia Circuit |
VIE | | Variable Interest Entity |
WECC | | Western Electric Coordinating Council |
| ZEC | | Zero Emission Credit or Zero Emission Certificate |
ZES | | Zero Emission Standard |
FILING FORMAT
This combined Form 10-Q is being filed separately by Exelon Corporation, Exelon Generation Company, LLC, Commonwealth Edison Company, PECO Energy Company, Baltimore Gas and Electric Company, Pepco Holdings LLC, Potomac Electric Power Company, Delmarva Power & Light Company, and Atlantic City Electric Company (Registrants). Information contained herein relating to any individual Registrant is filed by such Registrant on its own behalf. No Registrant makes any representation as to information relating to any other Registrant.
CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION
This Report contains certain forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 that are subject to risks and uncertainties including, among others, those related to the timing, manner, tax-free nature, and expected benefits associated with the potential separation of Exelon’s competitive power generation and customer-facing energy business from its six regulated electric and gas utilities.uncertainties. Words such as “could,” “may,” “expects,” “anticipates,” “will,” “targets,” “goals,” “projects,” “intends,” “plans,” “believes,” “seeks,” “estimates,” “predicts,” and variations on such words, and similar expressions that reflect our current views with respect to future events and operational, economic, and financial performance, are intended to identify such forward-looking statements.
The factors that could cause actual results to differ materially from the forward-looking statements made by the Registrants include those factors discussed herein, as well as the items discussed in (1) the Registrants' combined 2020 Annual Report on2021 Form 10-K in (a) Part I, ITEM 1A. Risk Factors, (b)Factors; (2) the 2021 Recast Form 10-K in (a) Part II, ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c)(b) Part II, ITEM 8. Financial Statements and Supplementary Data: Note 19,17, Commitments and Contingencies; (2)(3) this Quarterly Report on Form 10-Q in (a) Part II, ITEM 1A. Risk Factors, (b) Part I, ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations, and (c) Part I, ITEM 1. Financial Statements: Note 15,12, Commitments and Contingencies; and (3)(4) other factors discussed in filings with the SEC by the Registrants.
Investors are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this Report. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this Report.
WHERE TO FIND MORE INFORMATION
The SEC maintains an Internet site at www.sec.gov that contains reports, proxy and information statements, and other information that the Registrants file electronically with the SEC. These documents are also available to the public from commercial document retrieval services and the Registrants' website at www.exeloncorp.com. Information contained on the Registrants' website shall not be deemed incorporated into, or to be a part of, this Report.
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
| | | Three Months Ended
September 30, | | Nine Months Ended
September 30, | | Three Months Ended
June 30, | | Six Months Ended
June 30, |
| (In millions, except per share data) | (In millions, except per share data) | 2021 | | 2020 | | 2021 | | 2020 | (In millions, except per share data) | 2022 | | 2021 | | 2022 | | 2021 |
| Operating revenues | Operating revenues | | | | | | | | Operating revenues | | | | | | | |
| Competitive businesses revenues | $ | 4,084 | | | $ | 4,331 | | | $ | 13,250 | | | $ | 12,348 | | |
| Rate-regulated utility revenues | 4,873 | | | 4,533 | | | 13,336 | | | 12,643 | | |
| Electric operating revenues | | Electric operating revenues | $ | 3,934 | | | $ | 3,739 | | | $ | 8,415 | | | $ | 7,609 | |
| Natural gas operating revenues | | Natural gas operating revenues | 307 | | | 234 | | | 1,124 | | | 867 | |
| Revenues from alternative revenue programs | Revenues from alternative revenue programs | (47) | | | (11) | | | 129 | | | (66) | | Revenues from alternative revenue programs | (2) | | | 47 | | | 27 | | | 176 | |
| Total operating revenues | Total operating revenues | 8,910 | | | 8,853 | | | 26,715 | | | 24,925 | | Total operating revenues | 4,239 | | | 4,020 | | | 9,566 | | | 8,652 | |
| Operating expenses | Operating expenses | | | | | | | | Operating expenses | | | | | | | |
| Competitive businesses purchased power and fuel | 1,541 | | | 2,311 | | | 8,103 | | | 6,967 | | |
| Rate-regulated utility purchased power and fuel | 1,492 | | | 1,303 | | | 3,914 | | | 3,439 | | |
| | Purchased power | | Purchased power | 1,167 | | | 1,006 | | | 2,748 | | | 2,146 | |
| Purchased fuel | | Purchased fuel | 107 | | | 58 | | | 445 | | | 276 | |
| Purchased power and fuel from affiliates | | Purchased power and fuel from affiliates | — | | | 257 | | | 159 | | | 550 | |
| Operating and maintenance | Operating and maintenance | 1,992 | | | 2,732 | | | 6,416 | | | 7,370 | | Operating and maintenance | 1,109 | | | 1,073 | | | 2,288 | | | 2,155 | |
| Depreciation and amortization | Depreciation and amortization | 1,624 | | | 1,289 | | | 4,988 | | | 3,312 | | Depreciation and amortization | 830 | | | 736 | | | 1,647 | | | 1,494 | |
| Taxes other than income taxes | Taxes other than income taxes | 468 | | | 452 | | | 1,337 | | | 1,299 | | Taxes other than income taxes | 330 | | | 314 | | | 684 | | | 631 | |
| Total operating expenses | Total operating expenses | 7,117 | | | 8,087 | | | 24,758 | | | 22,387 | | Total operating expenses | 3,543 | | | 3,444 | | | 7,971 | | | 7,252 | |
| | Gain on sales of assets and businesses | 65 | | | 3 | | | 147 | | | 16 | | |
| (Loss) gain on sales of assets and businesses | | (Loss) gain on sales of assets and businesses | (2) | | | 4 | | | (2) | | | 4 | |
| | Operating income | Operating income | 1,858 | | | 769 | | | 2,104 | | | 2,554 | | Operating income | 694 | | | 580 | | | 1,593 | | | 1,404 | |
| Other income and (deductions) | Other income and (deductions) | | | | | | | | Other income and (deductions) | | | | | | | |
| Interest expense, net | Interest expense, net | (391) | | | (398) | | | (1,161) | | | (1,222) | | Interest expense, net | (352) | | | (318) | | | (684) | | | (630) | |
| Interest expense to affiliates | Interest expense to affiliates | (6) | | | (6) | | | (19) | | | (19) | | Interest expense to affiliates | (6) | | | (6) | | | (13) | | | (13) | |
| Other, net | Other, net | (55) | | | 421 | | | 751 | | | 352 | | Other, net | 175 | | | 73 | | | 313 | | | 131 | |
| Total other income and (deductions) | Total other income and (deductions) | (452) | | | 17 | | | (429) | | | (889) | | Total other income and (deductions) | (183) | | | (251) | | | (384) | | | (512) | |
| Income before income taxes | 1,406 | | | 786 | | | 1,675 | | | 1,665 | | |
| Income from continuing operations before income taxes | | Income from continuing operations before income taxes | 511 | | | 329 | | | 1,209 | | | 892 | |
| Income taxes | Income taxes | 174 | | | 216 | | | 229 | | | 141 | | Income taxes | 46 | | | 3 | | | 263 | | | 42 | |
| Equity in losses of unconsolidated affiliates | (3) | | | (1) | | | (5) | | | (5) | | |
| Equity in earnings of unconsolidated affiliates | | Equity in earnings of unconsolidated affiliates | — | | | — | | | — | | | 1 | |
| Net income from continuing operations after income taxes | | Net income from continuing operations after income taxes | 465 | | | 326 | | | 946 | | | 851 | |
| Net income (loss) from discontinued operations after income taxes (Note 2) | | Net income (loss) from discontinued operations after income taxes (Note 2) | — | | | 150 | | | 117 | | | (640) | |
| Net income | Net income | 1,229 | | | 569 | | | 1,441 | | | 1,519 | | Net income | 465 | | | 476 | | | 1,063 | | | 211 | |
| Net income (loss) attributable to noncontrolling interests | 26 | | | 68 | | | 126 | | | (85) | | |
| Net income attributable to noncontrolling interests | | Net income attributable to noncontrolling interests | — | | | 75 | | | 1 | | | 99 | |
| Net income attributable to common shareholders | Net income attributable to common shareholders | $ | 1,203 | | | $ | 501 | | | $ | 1,315 | | | $ | 1,604 | | Net income attributable to common shareholders | $ | 465 | | | $ | 401 | | | $ | 1,062 | | | $ | 112 | |
| | Amounts attributable to common shareholders: | | Amounts attributable to common shareholders: | |
| Net income from continuing operations | | Net income from continuing operations | 465 | | | 326 | | | 946 | | | 851 | |
| Net income (loss) from discontinued operations | | Net income (loss) from discontinued operations | — | | | 75 | | | 116 | | | (739) | |
| Net income attributable to common shareholders | | Net income attributable to common shareholders | $ | 465 | | | $ | 401 | | | $ | 1,062 | | | $ | 112 | |
| | Comprehensive income, net of income taxes | Comprehensive income, net of income taxes | | | | | | | | Comprehensive income, net of income taxes | |
| Net income | Net income | $ | 1,229 | | | $ | 569 | | | $ | 1,441 | | | $ | 1,519 | | Net income | $ | 465 | | | $ | 476 | | | $ | 1,063 | | | $ | 211 | |
| Other comprehensive income (loss), net of income taxes | Other comprehensive income (loss), net of income taxes | | Other comprehensive income (loss), net of income taxes | |
| Pension and non-pension postretirement benefit plans: | Pension and non-pension postretirement benefit plans: | | Pension and non-pension postretirement benefit plans: | |
| Prior service benefit reclassified to periodic benefit cost | Prior service benefit reclassified to periodic benefit cost | (1) | | | (10) | | | (4) | | | (30) | | Prior service benefit reclassified to periodic benefit cost | 2 | | | (1) | | | 2 | | | (2) | |
| Actuarial loss reclassified to periodic benefit cost | Actuarial loss reclassified to periodic benefit cost | 56 | | | 49 | | | 167 | | | 142 | | Actuarial loss reclassified to periodic benefit cost | 10 | | | 56 | | | 24 | | | 112 | |
| Pension and non-pension postretirement benefit plan valuation adjustment | Pension and non-pension postretirement benefit plan valuation adjustment | 14 | | | (13) | | | 15 | | | (17) | | Pension and non-pension postretirement benefit plan valuation adjustment | — | | | — | | | — | | | (2) | |
| Unrealized loss on cash flow hedges | — | | | (1) | | | (1) | | | (2) | | |
| | Unrealized (loss) gain on foreign currency translation | (3) | | | 3 | | | — | | | (3) | | |
| | Unrealized gain on foreign currency translation | | Unrealized gain on foreign currency translation | — | | | 2 | | | — | | | 3 | |
| | Other comprehensive income | Other comprehensive income | 66 | | | 28 | | | 177 | | | 90 | | Other comprehensive income | 12 | | | 57 | | | 26 | | | 111 | |
| Comprehensive income | Comprehensive income | 1,295 | | | 597 | | | 1,618 | | | 1,609 | | Comprehensive income | 477 | | | 533 | | | 1,089 | | | 322 | |
| Comprehensive income (loss) attributable to noncontrolling interests | 26 | | | 68 | | | 126 | | | (85) | | |
| Comprehensive income attributable to noncontrolling interests | | Comprehensive income attributable to noncontrolling interests | — | | | 75 | | | 1 | | | 99 | |
| Comprehensive income attributable to common shareholders | Comprehensive income attributable to common shareholders | $ | 1,269 | | | $ | 529 | | | $ | 1,492 | | | $ | 1,694 | | Comprehensive income attributable to common shareholders | $ | 477 | | | $ | 458 | | | $ | 1,088 | | | $ | 223 | |
| | Average shares of common stock outstanding: | Average shares of common stock outstanding: | | Average shares of common stock outstanding: | |
| Basic | Basic | 979 | | | 976 | | | 978 | | | 976 | | Basic | 981 | | | 978 | | | 981 | | | 978 | |
| Assumed exercise and/or distributions of stock-based awards | Assumed exercise and/or distributions of stock-based awards | 1 | | | 1 | | | 1 | | | — | | Assumed exercise and/or distributions of stock-based awards | 1 | | | 1 | | | 1 | | | 1 | |
Diluted(a) | Diluted(a) | 980 | | | 977 | | | 979 | | | 976 | | Diluted(a) | 982 | | | 979 | | | 982 | | | 979 | |
| | Earnings per average common share | | |
| Earnings per average common share from continuing operations | | Earnings per average common share from continuing operations | |
| Basic | Basic | $ | 1.23 | | | $ | 0.51 | | | $ | 1.34 | | | $ | 1.64 | | Basic | $ | 0.47 | | | $ | 0.33 | | | $ | 0.96 | | | $ | 0.87 | |
| Diluted | Diluted | $ | 1.23 | | | $ | 0.51 | | | $ | 1.34 | | | $ | 1.64 | | Diluted | $ | 0.47 | | | $ | 0.33 | | | $ | 0.96 | | | $ | 0.87 | |
| | Earnings (losses) per average common share from discontinued operations | | Earnings (losses) per average common share from discontinued operations | |
| Basic | | Basic | $ | — | | | $ | 0.08 | | | $ | 0.12 | | | $ | (0.76) | |
| Diluted | | Diluted | $ | — | | | $ | 0.08 | | | $ | 0.12 | | | $ | (0.76) | |
__________
(a)The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was zerowere none for the three and ninesix months ended SeptemberJune 30, 2022 and 2021, and approximately 1 million forrespectively.
See the three and nine months ended September 30, 2020, respectively.Combined Notes to Consolidated Financial Statements
9
EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
| | | | | | | | | | | |
| Six Months Ended
June 30, |
| (In millions) | 2022 | | 2021 |
| Cash flows from operating activities | | | |
| Net income | $ | 1,063 | | | $ | 211 | |
| Adjustments to reconcile net income to net cash flows provided by operating activities: | | | |
| Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization | 1,854 | | | 4,180 | |
| Asset impairments | — | | | 500 | |
| | | |
| Gain on sales of assets and businesses | (8) | | | (83) | |
| | | |
| Deferred income taxes and amortization of investment tax credits | 143 | | | (163) | |
| Net fair value changes related to derivatives | (59) | | | (490) | |
| Net realized and unrealized losses (gains) on NDT funds | 205 | | | (376) | |
| Net unrealized losses (gains) on equity investments | 16 | | | (96) | |
| Other non-cash operating activities | 276 | | | (331) | |
| Changes in assets and liabilities: | | | |
| Accounts receivable | (795) | | | (16) | |
| Inventories | 12 | | | 1 | |
| Accounts payable and accrued expenses | 544 | | | (87) | |
| Option premiums (paid) received, net | (39) | | | 2 | |
| Collateral received, net | 1,689 | | | 957 | |
| Income taxes | 23 | | | 190 | |
| Regulatory assets and liabilities, net | (376) | | | (276) | |
| Pension and non-pension postretirement benefit contributions | (585) | | | (559) | |
| Other assets and liabilities | (723) | | | (2,426) | |
| Net cash flows provided by operating activities | 3,240 | | | 1,138 | |
| Cash flows from investing activities | | | |
| Capital expenditures | (3,507) | | | (4,040) | |
| Proceeds from NDT fund sales | 488 | | | 4,438 | |
| Investment in NDT funds | (516) | | | (4,538) | |
| Collection of DPP | 169 | | | 2,209 | |
| | | |
| | | |
| Proceeds from sales of assets and businesses | 16 | | | 724 | |
| | | |
| | | |
| Other investing activities | 4 | | | 17 | |
| Net cash flows used in investing activities | (3,346) | | | (1,190) | |
| Cash flows from financing activities | | | |
| Changes in short-term borrowings | (597) | | | (666) | |
| Proceeds from short-term borrowings with maturities greater than 90 days | 1,150 | | | 500 | |
| Repayments on short-term borrowings with maturities greater than 90 days | (350) | | | — | |
| Issuance of long-term debt | 5,151 | | | 2,455 | |
| Retirement of long-term debt | (1,707) | | | (630) | |
| | | |
| | | |
| | | |
| | | |
| | | |
| Dividends paid on common stock | (663) | | | (747) | |
| | | |
| Proceeds from employee stock plans | 17 | | | 47 | |
| Transfer of cash, restricted cash, and cash equivalents to Constellation | (2,594) | | | — | |
| Other financing activities | (84) | | | (64) | |
| Net cash flows provided by financing activities | 323 | | | 895 | |
| Increase in cash, restricted cash, and cash equivalents | 217 | | | 843 | |
| Cash, restricted cash, and cash equivalents at beginning of period | 1,619 | | | 1,166 | |
| Cash, restricted cash, and cash equivalents at end of period | $ | 1,836 | | | $ | 2,009 | |
| | | |
| Supplemental cash flow information | | | |
| Decrease in capital expenditures not paid | $ | (276) | | | $ | (313) | |
| Increase in DPP | 348 | | | 1,958 | |
| (Decrease) increase in PP&E related to ARO update | (335) | | | 2 | |
See the Combined Notes to Consolidated Financial Statements
10
EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWSBALANCE SHEETS
(Unaudited)
| | | | | | | | | | | |
| Nine Months Ended
September 30, |
| (In millions) | 2021 | | 2020 |
| Cash flows from operating activities | | | |
| Net income | $ | 1,441 | | | $ | 1,519 | |
| Adjustments to reconcile net income to net cash flows provided by operating activities: | | | |
| Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization | 6,204 | | | 4,419 | |
| Asset impairments | 541 | | | 567 | |
| | | |
| Gain on sales of assets and businesses | (147) | | | (16) | |
| | | |
| Deferred income taxes and amortization of investment tax credits | (45) | | | 164 | |
| Net fair value changes related to derivatives | (1,244) | | | (448) | |
| Net realized and unrealized gains on NDT funds | (383) | | | (59) | |
| Net unrealized losses on equity investments | 83 | | | — | |
| Other non-cash operating activities | (293) | | | 988 | |
| Changes in assets and liabilities: | | | |
| Accounts receivable | (254) | | | 1,195 | |
| Inventories | (101) | | | (67) | |
| Accounts payable and accrued expenses | 354 | | | (519) | |
| Option premiums paid, net | (186) | | | (131) | |
| Collateral received, net | 2,111 | | | 644 | |
| Income taxes | 250 | | | (31) | |
| Pension and non-pension postretirement benefit contributions | (602) | | | (580) | |
| Other assets and liabilities | (3,588) | | | (3,423) | |
| Net cash flows provided by operating activities | 4,141 | | | 4,222 | |
| Cash flows from investing activities | | | |
| Capital expenditures | (5,970) | | | (5,606) | |
| Proceeds from NDT fund sales | 5,766 | | | 3,370 | |
| Investment in NDT funds | (5,900) | | | (3,438) | |
| Collection of DPP | 3,052 | | | 2,518 | |
| | | |
| | | |
| Proceeds from sales of assets and businesses | 801 | | | 46 | |
| | | |
| | | |
| Other investing activities | 40 | | | (2) | |
| Net cash flows used in investing activities | (2,211) | | | (3,112) | |
| Cash flows from financing activities | | | |
| Changes in short-term borrowings | (744) | | | (689) | |
| Proceeds from short-term borrowings with maturities greater than 90 days | 1,380 | | | 500 | |
| | | |
| Issuance of long-term debt | 3,406 | | | 6,756 | |
| Retirement of long-term debt | (1,618) | | | (5,158) | |
| | | |
| | | |
| | | |
| | | |
| | | |
| Dividends paid on common stock | (1,121) | | | (1,119) | |
| Acquisition of CENG noncontrolling interest | (885) | | | — | |
| Proceeds from employee stock plans | 63 | | | 62 | |
| Other financing activities | (93) | | | (104) | |
| Net cash flows provided by financing activities | 388 | | | 248 | |
| Increase in cash, restricted cash, and cash equivalents | 2,318 | | | 1,358 | |
| Cash, restricted cash, and cash equivalents at beginning of period | 1,166 | | | 1,122 | |
| Cash, restricted cash, and cash equivalents at end of period | $ | 3,484 | | | $ | 2,480 | |
| | | |
| Supplemental cash flow information | | | |
| Decrease in capital expenditures not paid | $ | (334) | | | $ | (11) | |
| Increase in DPP | 2,933 | | | 3,275 | |
| Increase in PP&E related to ARO update | 574 | | | 775 | |
| | | | | | | | | | | |
| (In millions) | June 30, 2022 | | December 31, 2021 |
| ASSETS | | | |
| Current assets | | | |
| Cash and cash equivalents | $ | 816 | | | $ | 672 | |
| Restricted cash and cash equivalents | 961 | | | 321 | |
| | | |
| Accounts receivable | | | |
| Customer accounts receivable | 2,219 | | 2,189 |
| Customer allowance for credit losses | (354) | | (320) |
| Customer accounts receivable, net | 1,865 | | | 1,869 | |
| Other accounts receivable | 1,403 | | 1,068 |
| Other allowance for credit losses | (81) | | (72) |
| Other accounts receivable, net | 1,322 | | | 996 | |
| Inventories, net | | | |
| Fossil fuel | 133 | | | 105 | |
| Materials and supplies | 491 | | | 476 | |
| Regulatory assets | 1,239 | | | 1,296 | |
| Other | 515 | | | 387 | |
| Current assets of discontinued operations | — | | | 7,835 | |
| Total current assets | 7,342 | | | 13,957 | |
| Property, plant, and equipment (net of accumulated depreciation and amortization of $15,242 and $14,430 as of June 30, 2022 and December 31, 2021, respectively) | 66,456 | | | 64,558 | |
| Deferred debits and other assets | | | |
| Regulatory assets | 8,350 | | | 8,224 | |
| Goodwill | 6,630 | | | 6,630 | |
| Receivable related to Regulatory Agreement Units | 2,265 | | | — | |
| Investments | 235 | | | 250 | |
| Other | 1,017 | | | 885 | |
| Property, plant, and equipment, deferred debits, and other assets of discontinued operations | — | | | 38,509 | |
| Total deferred debits and other assets | 18,497 | | | 54,498 | |
| Total assets | $ | 92,295 | | | $ | 133,013 | |
See the Combined Notes to Consolidated Financial Statements
11
EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
| | | | | | | | | | | |
| (In millions) | September 30, 2021 | | December 31, 2020 |
| ASSETS | | | |
| Current assets | | | |
| Cash and cash equivalents | $ | 2,957 | | | $ | 663 | |
| Restricted cash and cash equivalents | 473 | | | 438 | |
| | | |
| Accounts receivable | | | |
| Customer accounts receivable | 3,530 | | 3,597 |
| Customer allowance for credit losses | (409) | | (366) |
| Customer accounts receivable, net | 3,121 | | | 3,231 | |
| Other accounts receivable | 1,616 | | 1,469 |
| Other allowance for credit losses | (77) | | (71) |
| Other accounts receivable, net | 1,539 | | | 1,398 | |
| Mark-to-market derivative assets | 1,507 | | | 644 | |
| Unamortized energy contract assets | 36 | | | 38 | |
| Inventories, net | | | |
| Fossil fuel and emission allowances | 343 | | | 297 | |
| Materials and supplies | 1,475 | | | 1,425 | |
| Regulatory assets | 1,258 | | | 1,228 | |
| Renewable energy credits | 492 | | | 633 | |
| Assets held for sale | 11 | | | 958 | |
| Other | 1,665 | | | 1,609 | |
| Total current assets | 14,877 | | | 12,562 | |
| Property, plant, and equipment (net of accumulated depreciation and amortization of $30,049 and $26,727 as of September 30, 2021 and December 31, 2020, respectively) | 82,852 | | | 82,584 | |
| Deferred debits and other assets | | | |
| Regulatory assets | 8,628 | | | 8,759 | |
| Nuclear decommissioning trust funds | 15,404 | | | 14,464 | |
| Investments | 435 | | | 440 | |
| Goodwill | 6,677 | | | 6,677 | |
| Mark-to-market derivative assets | 665 | | | 555 | |
| Unamortized energy contract assets | 265 | | | 294 | |
| | | |
| Other | 2,818 | | | 2,982 | |
| Total deferred debits and other assets | 34,892 | | | 34,171 | |
Total assets(a) | $ | 132,621 | | | $ | 129,317 | |
See the Combined Notes to Consolidated Financial Statements
12
EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
| | | | | | | | | | | |
| (In millions) | September 30, 2021 | | December 31, 2020 |
| LIABILITIES AND SHAREHOLDERS’ EQUITY | | | |
| Current liabilities | | | |
| Short-term borrowings | $ | 2,667 | | | $ | 2,031 | |
| Long-term debt due within one year | 3,375 | | | 1,819 | |
| Accounts payable | 3,694 | | | 3,562 | |
| Accrued expenses | 1,949 | | | 2,078 | |
| Payables to affiliates | 5 | | | 5 | |
| Regulatory liabilities | 460 | | | 581 | |
| Mark-to-market derivative liabilities | 1,717 | | | 295 | |
| Unamortized energy contract liabilities | 92 | | | 100 | |
| Renewable energy credit obligation | 684 | | | 661 | |
| Liabilities held for sale | 3 | | | 375 | |
| Other | 1,180 | | | 1,264 | |
| Total current liabilities | 15,826 | | | 12,771 | |
| Long-term debt | 35,269 | | | 35,093 | |
| Long-term debt to financing trusts | 390 | | | 390 | |
| Deferred credits and other liabilities | | | |
| Deferred income taxes and unamortized investment tax credits | 13,816 | | | 13,035 | |
| Asset retirement obligations | 12,907 | | | 12,300 | |
| Pension obligations | 3,777 | | | 4,503 | |
| Non-pension postretirement benefit obligations | 1,980 | | | 2,011 | |
| Spent nuclear fuel obligation | 1,209 | | | 1,208 | |
| Regulatory liabilities | 9,448 | | | 9,485 | |
| Mark-to-market derivative liabilities | 721 | | | 473 | |
| Unamortized energy contract liabilities | 169 | | | 238 | |
| | | |
| Other | 2,850 | | | 2,942 | |
| Total deferred credits and other liabilities | 46,877 | | | 46,195 | |
Total liabilities(a) | 98,362 | | | 94,449 | |
| Commitments and contingencies | 0 | | 0 |
| | | |
| Shareholders’ equity | | | |
| Common stock (No par value, 2,000 shares authorized, 978 shares and 976 shares outstanding at September 30, 2021 and December 31, 2020, respectively) | 20,271 | | | 19,373 | |
| Treasury stock, at cost (2 shares at September 30, 2021 and December 31, 2020) | (123) | | | (123) | |
| Retained earnings | 16,926 | | | 16,735 | |
| Accumulated other comprehensive loss, net | (3,223) | | | (3,400) | |
| Total shareholders’ equity | 33,851 | | | 32,585 | |
| Noncontrolling interests | 408 | | | 2,283 | |
| Total equity | 34,259 | | | 34,868 | |
| Total liabilities and shareholders’ equity | $ | 132,621 | | | $ | 129,317 | |
__________ | | | | | | | | | | | |
| (In millions) | June 30, 2022 | | December 31, 2021 |
| LIABILITIES AND SHAREHOLDERS’ EQUITY | | | |
| Current liabilities | | | |
| Short-term borrowings | $ | 2,003 | | | $ | 1,248 | |
| Long-term debt due within one year | 505 | | | 2,153 | |
| Accounts payable | 2,451 | | | 2,379 | |
| Accrued expenses | 1,057 | | | 1,137 | |
| Payables to affiliates | 5 | | | 5 | |
| Regulatory liabilities | 411 | | | 376 | |
| Mark-to-market derivative liabilities | — | | | 18 | |
| Unamortized energy contract liabilities | 11 | | | 89 | |
| Other | 1,588 | | | 766 | |
| Current liabilities of discontinued operations | — | | | 7,940 | |
| Total current liabilities | 8,031 | | | 16,111 | |
| Long-term debt | 35,789 | | | 30,749 | |
| Long-term debt to financing trusts | 390 | | | 390 | |
| Deferred credits and other liabilities | | | |
| Deferred income taxes and unamortized investment tax credits | 11,240 | | | 10,611 | |
| Regulatory liabilities | 8,513 | | | 9,628 | |
| Pension obligations | 1,406 | | | 2,051 | |
| Non-pension postretirement benefit obligations | 800 | | | 811 | |
| Asset retirement obligations | 275 | | | 271 | |
| Mark-to-market derivative liabilities | 103 | | | 201 | |
| Unamortized energy contract liabilities | 38 | | | 146 | |
| | | |
| Other | 2,054 | | | 1,573 | |
| Long-term debt, deferred credits, and other liabilities of discontinued operations | — | | | 25,676 | |
| Total deferred credits and other liabilities | 24,429 | | | 50,968 | |
| Total liabilities | 68,639 | | | 98,218 | |
| Commitments and contingencies | 0 | | 0 |
| | | |
| Shareholders’ equity | | | |
| Common stock (No par value, 2,000 shares authorized, 980 shares and 979 shares outstanding at June 30, 2022 and December 31, 2021, respectively) | 20,319 | | | 20,324 | |
| Treasury stock, at cost (2 shares at June 30, 2022 and December 31, 2021) | (123) | | | (123) | |
| Retained earnings | 4,161 | | | 16,942 | |
| Accumulated other comprehensive loss, net | (701) | | | (2,750) | |
| Total shareholders’ equity | 23,656 | | | 34,393 | |
| Noncontrolling interests | — | | | 402 | |
| Total equity | 23,656 | | | 34,795 | |
| Total liabilities and shareholders’ equity | $ | 92,295 | | | $ | 133,013 | |
(a)Exelon’s consolidated assets include $2,722 million and $10,200 million at September 30, 2021 and December 31, 2020, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $1,088 million and $3,598 million at September 30, 2021 and December 31, 2020, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 17 — Variable Interest Entities for additional information.
See the Combined Notes to Consolidated Financial Statements
1312
EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
(Unaudited)
| | | Nine Months Ended September 30, 2021 | | Six Months Ended June 30, 2022 |
(In millions, shares
in thousands) | (In millions, shares
in thousands) | Issued
Shares | | Common
Stock | | Treasury
Stock | | Retained
Earnings | | Accumulated
Other
Comprehensive
Loss, net | | Noncontrolling
Interests | | Total Shareholders'
Equity | (In millions, shares
in thousands) | Issued
Shares | | Common
Stock | | Treasury
Stock | | Retained
Earnings | | Accumulated
Other
Comprehensive
Loss, net | | Noncontrolling
Interests | | Total Shareholders'
Equity |
| Balance, December 31, 2020 | 977,466 | | | $ | 19,373 | | | $ | (123) | | | $ | 16,735 | | | $ | (3,400) | | | $ | 2,283 | | | $ | 34,868 | | |
| Net (loss) income | — | | | — | | | — | | | (289) | | | — | | | 25 | | | (264) | | |
| Balance, December 31, 2021 | | Balance, December 31, 2021 | 981,291 | | | $ | 20,324 | | | $ | (123) | | | $ | 16,942 | | | $ | (2,750) | | | $ | 402 | | | $ | 34,795 | |
| Net income | | Net income | — | | | — | | | — | | | 597 | | | — | | | 1 | | | 598 | |
| Long-term incentive plan activity | Long-term incentive plan activity | 640 | | | 5 | | | — | | | — | | | — | | | — | | | 5 | | Long-term incentive plan activity | 540 | | | (13) | | | — | | | — | | | — | | | — | | | (13) | |
| Employee stock purchase plan issuances | Employee stock purchase plan issuances | 902 | | | 34 | | | — | | | — | | | — | | | — | | | 34 | | Employee stock purchase plan issuances | 211 | | | 9 | | | — | | | — | | | — | | | — | | | 9 | |
| | Changes in equity of noncontrolling interests | Changes in equity of noncontrolling interests | — | | | — | | | — | | | — | | | — | | | (10) | | | (10) | | Changes in equity of noncontrolling interests | — | | | — | | | — | | | — | | | — | | | (7) | | | (7) | |
| Common stock dividends ($0.38/common share) | — | | | — | | | — | | | (374) | | | — | | | — | | | (374) | | |
| Distribution of Constellation (Note 2) | | Distribution of Constellation (Note 2) | — | | | (21) | | | — | | | (13,179) | | | 2,023 | | | (396) | | | (11,573) | |
Common stock dividends ($0.34/common share) | | Common stock dividends ($0.34/common share) | — | | | — | | | — | | | (332) | | | — | | | — | | | (332) | |
| Other comprehensive income, net of income taxes | Other comprehensive income, net of income taxes | — | | | — | | | — | | | — | | | 54 | | | — | | | 54 | | Other comprehensive income, net of income taxes | — | | | — | | | — | | | — | | | 14 | | | — | | | 14 | |
| | Balance, March 31, 2021 | 979,008 | | | $ | 19,412 | | | $ | (123) | | | $ | 16,072 | | | $ | (3,346) | | | $ | 2,298 | | | $ | 34,313 | | |
| Balance, March 31, 2022 | | Balance, March 31, 2022 | 982,042 | | | $ | 20,299 | | | $ | (123) | | | $ | 4,028 | | | $ | (713) | | | $ | — | | | $ | 23,491 | |
| Net income | Net income | — | | | — | | | — | | | 401 | | | — | | | 75 | | | 476 | | Net income | — | | | — | | | — | | | 465 | | | — | | | — | | | 465 | |
| Long-term incentive plan activity | Long-term incentive plan activity | 237 | | | 24 | | | — | | | — | | | — | | | — | | | 24 | | Long-term incentive plan activity | 21 | | | 10 | | | — | | | — | | | — | | | — | | | 10 | |
| Employee stock purchase plan issuances | Employee stock purchase plan issuances | 420 | | | 18 | | | — | | | — | | | — | | | — | | | 18 | | Employee stock purchase plan issuances | 242 | | | 10 | | | — | | | — | | | — | | | — | | | 10 | |
| | Changes in equity of noncontrolling interests | Changes in equity of noncontrolling interests | — | | | — | | | — | | | — | | | — | | | (13) | | | (13) | | Changes in equity of noncontrolling interests | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Common stock dividends ($0.38/common share) | — | | | — | | | — | | | (375) | | | — | | | — | | | (375) | | |
Common stock dividends ($0.34/common share) | | Common stock dividends ($0.34/common share) | — | | | — | | | — | | | (332) | | | — | | | — | | | (332) | |
| Other comprehensive income, net of income taxes | Other comprehensive income, net of income taxes | — | | | — | | | — | | | — | | | 57 | | | — | | | 57 | | Other comprehensive income, net of income taxes | — | | | — | | | — | | | — | | | 12 | | | — | | | 12 | |
| | Balance, June 30, 2021 | 979,665 | | | $ | 19,454 | | | $ | (123) | | | $ | 16,098 | | | $ | (3,289) | | | $ | 2,360 | | | $ | 34,500 | | |
| Net income | — | | | — | | | — | | | 1,203 | | | — | | | 26 | | | 1,229 | | |
| Long-term incentive plan activity | 94 | | | 9 | | | — | | | — | | | — | | | — | | | 9 | | |
| Employee stock purchase plan issuances | 391 | | | 18 | | | — | | | — | | | — | | | — | | | 18 | | |
| Changes in equity of noncontrolling interests | — | | | — | | | — | | | — | | | — | | | (13) | | | (13) | | |
| Acquisition of CENG noncontrolling interest | — | | | 1,080 | | | — | | | — | | | — | | | (1,965) | | | (885) | | |
| Deferred tax adjustment related to acquisition of CENG noncontrolling interest | — | | | (290) | | | — | | | — | | | — | | | — | | | (290) | | |
Common stock dividends ($0.38/common share) | — | | | — | | | — | | | (375) | | | — | | | — | | | (375) | | |
| Other comprehensive income net of income taxes | — | | | — | | | — | | | — | | | 66 | | | — | | | 66 | | |
| Balance, September 30, 2021 | 980,150 | | | $ | 20,271 | | | $ | (123) | | | $ | 16,926 | | | $ | (3,223) | | | $ | 408 | | | $ | 34,259 | | |
| Balance, June 30, 2022 | | Balance, June 30, 2022 | 982,305 | | | $ | 20,319 | | | $ | (123) | | | $ | 4,161 | | | $ | (701) | | | $ | — | | | $ | 23,656 | |
|
See the Combined Notes to Consolidated Financial Statements
14
EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2020 |
(In millions, shares
in thousands) | Issued
Shares | | Common
Stock | | Treasury
Stock | | Retained
Earnings | | Accumulated
Other
Comprehensive
Loss, net | | Noncontrolling
Interests | | Total Shareholders'
Equity |
| Balance, December 31, 2019 | 974,416 | | | $ | 19,274 | | | $ | (123) | | | $ | 16,267 | | | $ | (3,194) | | | $ | 2,349 | | | $ | 34,573 | |
| Net income (loss) | — | | | — | | | — | | | 582 | | | — | | | (206) | | | 376 | |
| Long-term incentive plan activity | 1,354 | | | (4) | | | — | | | — | | | — | | | — | | | (4) | |
| Employee stock purchase plan issuances | 470 | | | 31 | | | — | | | — | | | — | | | — | | | 31 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| Changes in equity of noncontrolling interests | — | | | — | | | — | | | — | | | — | | | (9) | | | (9) | |
| Sale of noncontrolling interests | — | | | 2 | | | — | | | — | | | — | | | — | | | 2 | |
Common stock dividends ($0.38/common share) | — | | | — | | | — | | | (374) | | | — | | | — | | | (374) | |
| Other comprehensive income, net of income taxes | — | | | — | | | — | | | — | | | 21 | | | — | | | 21 | |
| | | | | | | | | | | | | |
| Balance, March 31, 2020 | 976,240 | | | $ | 19,303 | | | $ | (123) | | | $ | 16,475 | | | $ | (3,173) | | | $ | 2,134 | | | $ | 34,616 | |
| Net income | — | | | — | | | — | | | 521 | | | — | | | 53 | | | 574 | |
| Long-term incentive plan activity | 148 | | | 17 | | | — | | | — | | | — | | | — | | | 17 | |
| Employee stock purchase plan issuances | (51) | | | 15 | | | — | | | — | | | — | | | — | | | 15 | |
| | | | | | | | | | | | | |
| Changes in equity of noncontrolling interests | — | | | — | | | — | | | — | | | — | | | (19) | | | (19) | |
| Sale of noncontrolling interests | — | | | 1 | | | — | | | — | | | — | | | — | | | 1 | |
Common stock dividends ($0.38/common share) | — | | | — | | | — | | | (374) | | | — | | | — | | | (374) | |
| Other comprehensive income, net of income taxes | — | | | — | | | — | | | — | | | 41 | | | — | | | 41 | |
| Balance, June 30, 2020 | 976,337 | | | $ | 19,336 | | | $ | (123) | | | $ | 16,622 | | | $ | (3,132) | | | $ | 2,168 | | | $ | 34,871 | |
| Net Income | — | | | — | | | — | | | 501 | | | — | | | 68 | | | 569 | |
| Long-term incentive plan activity | 68 | | | 10 | | | — | | | — | | | — | | | — | | | 10 | |
| Employee stock purchase plan issuances | 1,000 | | | 16 | | | — | | | — | | | — | | | — | | | 16 | |
| Changes in equity of noncontrolling interests | — | | | — | | | — | | | — | | | — | | | (17) | | | (17) | |
Common stock dividends ($0.38/common share) | — | | | — | | | — | | | (374) | | | — | | | — | | | (374) | |
| Other comprehensive income, net of income taxes | — | | | — | | | — | | | — | | | 28 | | | — | | | 28 | |
| Balance, September 30, 2020 | 977,405 | | | $ | 19,362 | | | $ | (123) | | | $ | 16,749 | | | $ | (3,104) | | | $ | 2,219 | | | $ | 35,103 | |
See the Combined Notes to Consolidated Financial Statements
15
EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended
September 30, | | Nine Months Ended
September 30, |
| (In millions) | 2021 | | 2020 | | 2021 | | 2020 |
| Operating revenues | | | | | | | |
| Operating revenues | $ | 4,082 | | | $ | 4,328 | | | $ | 13,245 | | | $ | 12,340 | |
| Operating revenues from affiliates | 324 | | | 331 | | | 872 | | | 932 | |
| Total operating revenues | 4,406 | | | 4,659 | | | 14,117 | | | 13,272 | |
| Operating expenses | | | | | | | |
| Purchased power and fuel | 1,542 | | | 2,311 | | | 8,103 | | | 6,967 | |
| Purchased power and fuel from affiliates | 4 | | | 3 | | | — | | | (6) | |
| Operating and maintenance | 761 | | | 1,605 | | | 2,955 | | | 3,779 | |
| Operating and maintenance from affiliates | 177 | | | 132 | | | 458 | | | 409 | |
| Depreciation and amortization | 866 | | | 558 | | | 2,735 | | | 1,161 | |
| Taxes other than income taxes | 115 | | | 118 | | | 354 | | | 364 | |
| Total operating expenses | 3,465 | | | 4,727 | | | 14,605 | | | 12,674 | |
| | | | | | | |
| Gain on sales of assets and businesses | 65 | | | — | | | 144 | | | 12 | |
| | | | | | | |
| | | | | | | |
| Operating income (loss) | 1,006 | | | (68) | | | (344) | | | 610 | |
| Other income and (deductions) | | | | | | | |
| Interest expense, net | (73) | | | (72) | | | (214) | | | (251) | |
| Interest expense to affiliates | (4) | | | (8) | | | (11) | | | (26) | |
| Other, net | (115) | | | 367 | | | 561 | | | 199 | |
| Total other income and (deductions) | (192) | | | 287 | | | 336 | | | (78) | |
| Income (loss) before income taxes | 814 | | | 219 | | | (8) | | | 532 | |
| Income taxes | 177 | | | 100 | | | 108 | | | 41 | |
| Equity in losses of unconsolidated affiliates | (4) | | | (2) | | | (6) | | | (6) | |
| Net income (loss) | 633 | | | 117 | | | (122) | | | 485 | |
| Net income (loss) attributable to noncontrolling interests | 26 | | | 68 | | | 125 | | | (85) | |
| Net income (loss) attributable to membership interest | $ | 607 | | | $ | 49 | | | $ | (247) | | | $ | 570 | |
| Comprehensive income (loss), net of income taxes | | | | | | | |
| Net income (loss) | $ | 633 | | | $ | 117 | | | $ | (122) | | | $ | 485 | |
| Other comprehensive (loss) income, net of income taxes | | | | | | | |
| Unrealized loss on cash flow hedges | — | | | — | | | (1) | | | (1) | |
| | | | | | | |
| Unrealized (loss) gain on foreign currency translation | (4) | | | 3 | | | — | | | (3) | |
| | | | | | | |
| | | | | | | |
| Other comprehensive (loss) income, net of income taxes | (4) | | | 3 | | | (1) | | | (4) | |
| Comprehensive income (loss) | 629 | | | 120 | | | (123) | | | 481 | |
| Comprehensive income (loss) attributable to noncontrolling interests | 26 | | | 68 | | | 125 | | | (85) | |
| Comprehensive income (loss) attributable to membership interest | $ | 603 | | | $ | 52 | | | $ | (248) | | | $ | 566 | |
See the Combined Notes to Consolidated Financial Statements
16
EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited) | | | | | | | | | | | |
| Nine Months Ended
September 30, |
| (In millions) | 2021 | | 2020 |
| Cash flows from operating activities | | | |
| Net (loss) income | $ | (122) | | | $ | 485 | |
| Adjustments to reconcile net (loss) income to net cash flows provided by operating activities: | | | |
| Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization | 3,951 | | | 2,266 | |
| Asset impairments | 537 | | | 552 | |
| | | |
| Gain on sales of assets and businesses | (144) | | | (12) | |
| | | |
| Deferred income taxes and amortization of investment tax credits | (204) | | | (51) | |
| Net fair value changes related to derivatives | (1,244) | | | (448) | |
| Net realized and unrealized gains on NDT funds | (383) | | | (59) | |
| Net unrealized losses on equity investments | 83 | | | — | |
| Other non-cash operating activities | (582) | | | 293 | |
| Changes in assets and liabilities: | | | |
| Accounts receivable | (207) | | | 1,463 | |
| Receivables from and payables to affiliates, net | 82 | | | 75 | |
| Inventories | (29) | | | (65) | |
| Accounts payable and accrued expenses | 357 | | | (619) | |
| Option premiums paid, net | (186) | | | (131) | |
| Collateral received, net | 1,974 | | | 640 | |
| Income taxes | 177 | | | 112 | |
| Pension and non-pension postretirement benefit contributions | (237) | | | (249) | |
| Other assets and liabilities | (2,849) | | | (2,889) | |
| Net cash flows provided by operating activities | 974 | | | 1,363 | |
| Cash flows from investing activities | | | |
| Capital expenditures | (1,086) | | | (1,212) | |
| | | |
| Proceeds from NDT fund sales | 5,766 | | | 3,370 | |
| Investment in NDT funds | (5,900) | | | (3,438) | |
| | | |
| Collection of DPP | 3,052 | | | 2,518 | |
| | | |
| Proceeds from sales of assets and businesses | 802 | | | 46 | |
| | | |
| | | |
| | | |
| Other investing activities | 5 | | | 5 | |
| Net cash flows provided by investing activities | 2,639 | | | 1,289 | |
| Cash flows from financing activities | | | |
| Changes in short-term borrowings | (340) | | | (280) | |
| Proceeds from short-term borrowings with maturities greater than 90 days | 880 | | | 500 | |
| | | |
| Issuance of long-term debt | 152 | | | 2,405 | |
| Retirement of long-term debt | (89) | | | (3,613) | |
| | | |
| Changes in Exelon intercompany money pool | (285) | | | — | |
| Acquisition of CENG noncontrolling interest | (885) | | | — | |
| Distributions to member | (1,373) | | | (1,406) | |
| | | |
| Contributions from member | 64 | | | 64 | |
| | | |
| | | |
| Other financing activities | (45) | | | (48) | |
| Net cash flows used in financing activities | (1,921) | | | (2,378) | |
| Increase in cash, restricted cash, and cash equivalents | 1,692 | | | 274 | |
| Cash, restricted cash, and cash equivalents at beginning of period | 327 | | | 449 | |
| Cash, restricted cash, and cash equivalents at end of period | $ | 2,019 | | | $ | 723 | |
| | | |
| Supplemental cash flow information | | | |
| Decrease in capital expenditures not paid | $ | (77) | | | $ | (77) | |
| Increase in DPP | 2,933 | | | 3,275 | |
| Increase in PP&E related to ARO update | 550 | | | 775 | |
| | | |
See the Combined Notes to Consolidated Financial Statements
17
EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
| | | | | | | | | | | |
| (In millions) | September 30, 2021 | | December 31, 2020 |
| ASSETS | | | |
| Current assets | | | |
| Cash and cash equivalents | $ | 1,957 | | | $ | 226 | |
| Restricted cash and cash equivalents | 62 | | | 89 | |
| Accounts receivable | | | |
| Customer accounts receivable | 1,412 | | 1,330 |
| Customer allowance for credit losses | (84) | | (32) |
| Customer accounts receivable, net | 1,328 | | | 1,298 | |
| Other accounts receivable | 465 | | 352 |
| Other allowance for credit losses | (4) | | — |
| Other accounts receivable, net | 461 | | | 352 | |
| Mark-to-market derivative assets | 1,505 | | | 644 | |
| Receivables from affiliates | 184 | | | 153 | |
| | | |
| Unamortized energy contract assets | 36 | | | 38 | |
| Inventories, net | | | |
| Fossil fuel and emission allowances | 240 | | | 233 | |
| Materials and supplies | 998 | | | 978 | |
| | | |
| Renewable energy credits | 486 | | | 621 | |
| Assets held for sale | 11 | | | 958 | |
| Other | 1,319 | | | 1,357 | |
| Total current assets | 8,587 | | | 6,947 | |
| Property, plant, and equipment (net of accumulated depreciation and amortization of $15,966 and $13,370 as of September 30, 2021 and December 31, 2020, respectively) | 19,574 | | | 22,214 | |
| Deferred debits and other assets | | | |
| Nuclear decommissioning trust funds | 15,404 | | | 14,464 | |
| Investments | 165 | | | 184 | |
| Goodwill | 47 | | | 47 | |
| Mark-to-market derivative assets | 664 | | | 555 | |
| | | |
| Prepaid pension asset | 1,702 | | | 1,558 | |
| | | |
| Unamortized energy contract assets | 265 | | | 293 | |
| Deferred income taxes | 13 | | | 6 | |
| Other | 1,589 | | | 1,826 | |
| Total deferred debits and other assets | 19,849 | | | 18,933 | |
Total assets(a) | $ | 48,010 | | | $ | 48,094 | |
See the Combined Notes to Consolidated Financial Statements
18
EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
| | | | | | | | | | | |
| (In millions) | September 30, 2021 | | December 31, 2020 |
| LIABILITIES AND EQUITY | | | |
| Current liabilities | | | |
| Short-term borrowings | $ | 1,380 | | | $ | 840 | |
| Long-term debt due within one year | 1,216 | | | 197 | |
| | | |
| Accounts payable | 1,612 | | | 1,253 | |
| Accrued expenses | 691 | | | 788 | |
| Payables to affiliates | 154 | | | 107 | |
| Borrowings from Exelon intercompany money pool | — | | | 285 | |
| | | |
| Mark-to-market derivative liabilities | 1,709 | | | 262 | |
| Unamortized energy contract liabilities | 2 | | | 7 | |
| Renewable energy credit obligation | 682 | | | 661 | |
| Liabilities held for sale | 3 | | | 375 | |
| Other | 347 | | | 444 | |
| Total current liabilities | 7,796 | | | 5,219 | |
| Long-term debt | 4,593 | | | 5,566 | |
| Long-term debt to affiliates | 321 | | | 324 | |
| | | |
| Deferred credits and other liabilities | | | |
| Deferred income taxes and unamortized investment tax credits | 3,685 | | | 3,656 | |
| Asset retirement obligations | 12,635 | | | 12,054 | |
| | | |
| Non-pension postretirement benefit obligations | 857 | | | 858 | |
| Spent nuclear fuel obligation | 1,209 | | | 1,208 | |
| Payables to affiliates | 3,143 | | | 3,017 | |
| Mark-to-market derivative liabilities | 511 | | | 205 | |
| Unamortized energy contract liabilities | 1 | | | 3 | |
| | | |
| Other | 1,224 | | | 1,308 | |
| Total deferred credits and other liabilities | 23,265 | | | 22,309 | |
Total liabilities(a) | 35,975 | | | 33,418 | |
| Commitments and contingencies | 0 | | 0 |
| | | |
| Equity | | | |
| Member’s equity | | | |
| Membership interest | 10,480 | | | 9,624 | |
| Undistributed earnings | 1,185 | | | 2,805 | |
| Accumulated other comprehensive loss, net | (31) | | | (30) | |
| Total member’s equity | 11,634 | | | 12,399 | |
| Noncontrolling interests | 401 | | | 2,277 | |
| Total equity | 12,035 | | | 14,676 | |
| Total liabilities and equity | $ | 48,010 | | | $ | 48,094 | |
__________
(a)Generation’s consolidated assets include $2,704 million and $10,182 million at September 30, 2021 and December 31, 2020, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Generation’s consolidated liabilities include $1,078 million and $3,572 million at September 30, 2021 and December 31, 2020, respectively, of certain VIEs for which the VIE creditors do not have recourse to Generation. See Note 17 — Variable Interest Entities for additional information.
See the Combined Notes to Consolidated Financial Statements
19
EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2021 |
| Member’s Equity | | | | |
| (In millions) | Membership
Interest | | Undistributed
Earnings | | Accumulated
Other
Comprehensive
Loss, net | | Noncontrolling
Interests | | Total Equity |
| Balance, December 31, 2020 | $ | 9,624 | | | $ | 2,805 | | | $ | (30) | | | $ | 2,277 | | | $ | 14,676 | |
| Net (loss) income | — | | | (793) | | | — | | | 24 | | | (769) | |
| Changes in equity of noncontrolling interests | — | | | — | | | — | | | (10) | | | (10) | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| Distributions to member | — | | | (458) | | | — | | | — | | | (458) | |
| Other comprehensive income, net of income taxes | — | | | — | | | 1 | | | — | | | 1 | |
| | | | | | | | | |
| Balance, March 31, 2021 | $ | 9,624 | | | $ | 1,554 | | | $ | (29) | | | $ | 2,291 | | | $ | 13,440 | |
| Net (loss) income | — | | | (61) | | | — | | | 74 | | | 13 | |
| Changes in equity of noncontrolling interests | — | | | — | | | — | | | (12) | | | (12) | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| Distributions to member | — | | | (458) | | | — | | | — | | | (458) | |
| Other comprehensive income, net of income taxes | — | | | — | | | 2 | | | — | | | 2 | |
| Balance, June 30, 2021 | $ | 9,624 | | | $ | 1,035 | | | $ | (27) | | | $ | 2,353 | | | $ | 12,985 | |
| Net income | — | | | 607 | | | — | | | 26 | | | 633 | |
| Changes in equity of noncontrolling interests | — | | | — | | | — | | | (13) | | | (13) | |
| | | | | | | | | |
| Acquisition of CENG noncontrolling interest | 1,080 | | | — | | | — | | | (1,965) | | | (885) | |
| | | | | | | | | |
| | | | | | | | | |
| Deferred tax adjustment related to acquisition of CENG noncontrolling interest | (288) | | | — | | | — | | | — | | | (288) | |
| Contribution from member | 64 | | | — | | | — | | | — | | | 64 | |
| Distributions to member | — | | | (457) | | | — | | | — | | | (457) | |
| Other comprehensive loss, net of income taxes | — | | | — | | | (4) | | | — | | | (4) | |
| Balance, September 30, 2021 | $ | 10,480 | | | $ | 1,185 | | | $ | (31) | | | $ | 401 | | | $ | 12,035 | |
See the Combined Notes to Consolidated Financial Statements
2013
EXELON GENERATION COMPANY, LLCCORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2020 |
| Member’s Equity | | | | |
| (In millions) | Membership
Interest | | Undistributed
Earnings | | Accumulated
Other
Comprehensive
Loss, net | | Noncontrolling
Interests | | Total Equity |
| Balance, December 31, 2019 | $ | 9,566 | | | $ | 3,950 | | | $ | (32) | | | $ | 2,346 | | | $ | 15,830 | |
| Net income (loss) | — | | | 45 | | | — | | | (206) | | | (161) | |
| Changes in equity of noncontrolling interests | — | | | — | | | — | | | (11) | | | (11) | |
| Sale of noncontrolling interests | 2 | | | — | | | — | | | — | | | 2 | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| Distributions to member | — | | | (468) | | | — | | | — | | | (468) | |
| Other comprehensive loss, net of income taxes | — | | | — | | | (9) | | | — | | | (9) | |
| | | | | | | | | |
| Balance, March 31, 2020 | $ | 9,568 | | | $ | 3,527 | | | $ | (41) | | | $ | 2,129 | | | $ | 15,183 | |
| Net income | — | | | 476 | | | — | | | 53 | | | 529 | |
| Changes in equity of noncontrolling interests | — | | | — | | | — | | | (19) | | | (19) | |
| Sale of noncontrolling interests | 1 | | | — | | | — | | | — | | | 1 | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| Distributions to member | — | | | (469) | | | — | | | — | | | (469) | |
| Other comprehensive income, net of income taxes | — | | | — | | | 2 | | | — | | | 2 | |
| Balance, June 30, 2020 | $ | 9,569 | | | $ | 3,534 | | | $ | (39) | | | $ | 2,163 | | | $ | 15,227 | |
| Net income | — | | | 49 | | | — | | | 68 | | | 117 | |
| Changes in equity of noncontrolling interests | — | | | — | | | — | | | (18) | | | (18) | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| Contribution from member | 64 | | | — | | | — | | | — | | | 64 | |
| Distributions to member | — | | | (469) | | | — | | | — | | | (469) | |
| Other comprehensive income, net of income taxes | — | | | — | | | 3 | | | — | | | 3 | |
| Balance, September 30, 2020 | $ | 9,633 | | | $ | 3,114 | | | $ | (36) | | | $ | 2,213 | | | $ | 14,924 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Six Months Ended June 30, 2021 |
(In millions, shares
in thousands) | Issued
Shares | | Common
Stock | | Treasury
Stock | | Retained
Earnings | | Accumulated
Other
Comprehensive
Loss, net | | Noncontrolling
Interests | | Total Shareholders'
Equity |
| Balance, December 31, 2020 | 977,466 | | | $ | 19,373 | | | $ | (123) | | | $ | 16,735 | | | $ | (3,400) | | | $ | 2,283 | | | $ | 34,868 | |
| Net (loss) income | — | | | — | | | — | | | (289) | | | — | | | 25 | | | (264) | |
| Long-term incentive plan activity | 640 | | | 5 | | | — | | | — | | | — | | | — | | | 5 | |
| Employee stock purchase plan issuances | 902 | | | 34 | | | — | | | — | | | — | | | — | | | 34 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| Changes in equity of noncontrolling interests | — | | | — | | | — | | | — | | | — | | | (10) | | | (10) | |
| | | | | | | | | | | | | |
Common stock dividends ($0.38/common share) | — | | | — | | | — | | | (374) | | | — | | | — | | | (374) | |
| Other comprehensive income, net of income taxes | — | | | — | | | — | | | — | | | 54 | | | — | | | 54 | |
| | | | | | | | | | | | | |
| Balance, March 31, 2021 | 979,008 | | | $ | 19,412 | | | $ | (123) | | | $ | 16,072 | | | $ | (3,346) | | | $ | 2,298 | | | $ | 34,313 | |
| Net income | — | | | — | | | — | | | 401 | | | — | | | 75 | | | 476 | |
| Long-term incentive plan activity | 237 | | | 24 | | | — | | | — | | | — | | | — | | | 24 | |
| Employee stock purchase plan issuances | 420 | | | 18 | | | — | | | — | | | — | | | — | | | 18 | |
| | | | | | | | | | | | | |
| Changes in equity of noncontrolling interests | — | | | — | | | — | | | — | | | — | | | (13) | | | (13) | |
| | | | | | | | | | | | | |
Common stock dividends ($0.38/common share) | — | | | — | | | — | | | (375) | | | — | | | — | | | (375) | |
| Other comprehensive income, net of income taxes | — | | | — | | | — | | | — | | | 57 | | | — | | | 57 | |
| Balance, June 30, 2021 | 979,665 | | | $ | 19,454 | | | $ | (123) | | | $ | 16,098 | | | $ | (3,289) | | | $ | 2,360 | | | $ | 34,500 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
See the Combined Notes to Consolidated Financial Statements
2114
COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
| | | Three Months Ended
September 30, | | Nine Months Ended
September 30, | | Three Months Ended
June 30, | | Six Months Ended
June 30, |
| (In millions) | (In millions) | 2021 | | 2020 | | 2021 | | 2020 | (In millions) | 2022 | | 2021 | | 2022 | | 2021 |
| Operating revenues | Operating revenues | | | | | | | | Operating revenues | | | | | | | |
| Electric operating revenues | Electric operating revenues | $ | 1,812 | | | $ | 1,666 | | | $ | 4,789 | | | $ | 4,519 | | Electric operating revenues | $ | 1,387 | | | $ | 1,503 | | | $ | 3,075 | | | $ | 2,977 | |
| Revenues from alternative revenue programs | Revenues from alternative revenue programs | (32) | | | (38) | | | 32 | | | (51) | | Revenues from alternative revenue programs | 35 | | | 9 | | | 75 | | | 64 | |
| Operating revenues from affiliates | Operating revenues from affiliates | 9 | | | 15 | | | 19 | | | 31 | | Operating revenues from affiliates | 3 | | | 5 | | | 8 | | | 11 | |
| Total operating revenues | Total operating revenues | 1,789 | | | 1,643 | | | 4,840 | | | 4,499 | | Total operating revenues | 1,425 | | | 1,517 | | | 3,158 | | | 3,052 | |
| Operating expenses | Operating expenses | | | | | | | | Operating expenses | | | | | | | |
| Purchased power | Purchased power | 610 | | | 535 | | | 1,472 | | | 1,305 | | Purchased power | 283 | | | 421 | | | 862 | | | 862 | |
| Purchased power from affiliate | Purchased power from affiliate | 93 | | | 71 | | | 256 | | | 252 | | Purchased power from affiliate | — | | | 79 | | | 59 | | | 163 | |
| Operating and maintenance | Operating and maintenance | 257 | | | 252 | | | 752 | | | 964 | | Operating and maintenance | 258 | | | 250 | | | 523 | | | 495 | |
| Operating and maintenance from affiliates | Operating and maintenance from affiliates | 73 | | | 69 | | | 217 | | | 209 | | Operating and maintenance from affiliates | 80 | | | 73 | | | 166 | | | 144 | |
| Depreciation and amortization | Depreciation and amortization | 304 | | | 294 | | | 893 | | | 841 | | Depreciation and amortization | 328 | | | 296 | | | 649 | | | 589 | |
| Taxes other than income taxes | Taxes other than income taxes | 91 | | | 81 | | | 243 | | | 227 | | Taxes other than income taxes | 90 | | | 77 | | | 185 | | | 153 | |
| Total operating expenses | Total operating expenses | 1,428 | | | 1,302 | | | 3,833 | | | 3,798 | | Total operating expenses | 1,039 | | | 1,196 | | | 2,444 | | | 2,406 | |
| | Loss on sales of assets | | Loss on sales of assets | (2) | | | — | | | (2) | | | — | |
| Operating income | Operating income | 361 | | | 341 | | | 1,007 | | | 701 | | Operating income | 384 | | | 321 | | | 712 | | | 646 | |
| Other income and (deductions) | Other income and (deductions) | | | | | | | | Other income and (deductions) | | | | | | | |
| Interest expense, net | Interest expense, net | (95) | | | (92) | | | (282) | | | (277) | | Interest expense, net | (101) | | | (95) | | | (197) | | | (187) | |
| Interest expense to affiliates | Interest expense to affiliates | (3) | | | (3) | | | (10) | | | (10) | | Interest expense to affiliates | (3) | | | (3) | | | (7) | | | (6) | |
| Other, net | Other, net | 13 | | | 10 | | | 35 | | | 32 | | Other, net | 13 | | | 15 | | | 26 | | | 22 | |
| Total other deductions | (85) | | | (85) | | | (257) | | | (255) | | |
| Total other income and (deductions) | | Total other income and (deductions) | (91) | | | (83) | | | (178) | | | (171) | |
| Income before income taxes | Income before income taxes | 276 | | | 256 | | | 750 | | | 446 | | Income before income taxes | 293 | | | 238 | | | 534 | | | 475 | |
| Income taxes | Income taxes | 56 | | | 60 | | | 141 | | | 142 | | Income taxes | 66 | | | 46 | | | 119 | | | 85 | |
| Net income | Net income | $ | 220 | | | $ | 196 | | | $ | 609 | | | $ | 304 | | Net income | $ | 227 | | | $ | 192 | | | $ | 415 | | | $ | 390 | |
| Comprehensive income | Comprehensive income | $ | 220 | | | $ | 196 | | | $ | 609 | | | $ | 304 | | Comprehensive income | $ | 227 | | | $ | 192 | | | $ | 415 | | | $ | 390 | |
22See the Combined Notes to Consolidated Financial Statements
15
COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
| | | Nine Months Ended
September 30, | | Six Months Ended
June 30, |
| (In millions) | (In millions) | 2021 | | 2020 | (In millions) | 2022 | | 2021 |
| Cash flows from operating activities | Cash flows from operating activities | | | | Cash flows from operating activities | | | |
| Net income | Net income | $ | 609 | | | $ | 304 | | Net income | $ | 415 | | | $ | 390 | |
| Adjustments to reconcile net income to net cash flows provided by operating activities: | Adjustments to reconcile net income to net cash flows provided by operating activities: | | Adjustments to reconcile net income to net cash flows provided by operating activities: | |
| Depreciation and amortization | Depreciation and amortization | 893 | | | 841 | | Depreciation and amortization | 649 | | | 589 | |
| Asset impairments | — | | | 15 | | |
| | Deferred income taxes and amortization of investment tax credits | Deferred income taxes and amortization of investment tax credits | 211 | | | 205 | | Deferred income taxes and amortization of investment tax credits | 122 | | | 143 | |
| | Other non-cash operating activities | Other non-cash operating activities | 95 | | | 354 | | Other non-cash operating activities | (18) | | | 23 | |
| Changes in assets and liabilities: | Changes in assets and liabilities: | | Changes in assets and liabilities: | |
| Accounts receivable | Accounts receivable | (72) | | | (104) | | Accounts receivable | (163) | | | (48) | |
| Receivables from and payables to affiliates, net | Receivables from and payables to affiliates, net | (16) | | | (13) | | Receivables from and payables to affiliates, net | (43) | | | 5 | |
| Inventories | Inventories | (6) | | | (2) | | Inventories | (2) | | | (2) | |
| Accounts payable and accrued expenses | Accounts payable and accrued expenses | (36) | | | 21 | | Accounts payable and accrued expenses | 123 | | | (45) | |
| Collateral received, net | Collateral received, net | 68 | | | 3 | | Collateral received, net | 60 | | | 2 | |
| Income taxes | Income taxes | (9) | | | (22) | | Income taxes | (19) | | | (34) | |
| Regulatory assets and liabilities, net | | Regulatory assets and liabilities, net | (267) | | | (181) | |
| Pension and non-pension postretirement benefit contributions | Pension and non-pension postretirement benefit contributions | (176) | | | (145) | | Pension and non-pension postretirement benefit contributions | (178) | | | (173) | |
| Other assets and liabilities | Other assets and liabilities | (376) | | | (380) | | Other assets and liabilities | (91) | | | (111) | |
| Net cash flows provided by operating activities | Net cash flows provided by operating activities | 1,185 | | | 1,077 | | Net cash flows provided by operating activities | 588 | | | 558 | |
| Cash flows from investing activities | Cash flows from investing activities | | | | Cash flows from investing activities | | | |
| Capital expenditures | Capital expenditures | (1,723) | | | (1,583) | | Capital expenditures | (1,208) | | | (1,162) | |
| | Other investing activities | Other investing activities | 20 | | | — | | Other investing activities | 15 | | | 12 | |
| Net cash flows used in investing activities | Net cash flows used in investing activities | (1,703) | | | (1,583) | | Net cash flows used in investing activities | (1,193) | | | (1,150) | |
| Cash flows from financing activities | Cash flows from financing activities | | | | Cash flows from financing activities | | | |
| Changes in short-term borrowings | Changes in short-term borrowings | (323) | | | 11 | | Changes in short-term borrowings | — | | | (290) | |
| Issuance of long-term debt | Issuance of long-term debt | 1,150 | | | 1,000 | | Issuance of long-term debt | 750 | | | 700 | |
| Retirement of long-term debt | (350) | | | (500) | | |
| | | Dividends paid on common stock | Dividends paid on common stock | (380) | | | (374) | | Dividends paid on common stock | (289) | | | (253) | |
| Contributions from parent | Contributions from parent | 593 | | | 488 | | Contributions from parent | 335 | | | 395 | |
| | Other financing activities | Other financing activities | (16) | | | (14) | | Other financing activities | (12) | | | (11) | |
| Net cash flows provided by financing activities | Net cash flows provided by financing activities | 674 | | | 611 | | Net cash flows provided by financing activities | 784 | | | 541 | |
| Increase in cash, restricted cash, and cash equivalents | 156 | | | 105 | | |
| Increase (decrease) in cash, restricted cash, and cash equivalents | | Increase (decrease) in cash, restricted cash, and cash equivalents | 179 | | | (51) | |
| Cash, restricted cash, and cash equivalents at beginning of period | Cash, restricted cash, and cash equivalents at beginning of period | 405 | | | 403 | | Cash, restricted cash, and cash equivalents at beginning of period | 384 | | | 405 | |
| Cash, restricted cash, and cash equivalents at end of period | Cash, restricted cash, and cash equivalents at end of period | $ | 561 | | | $ | 508 | | Cash, restricted cash, and cash equivalents at end of period | $ | 563 | | | $ | 354 | |
| | Supplemental cash flow information | Supplemental cash flow information | | Supplemental cash flow information | |
| (Decrease) increase in capital expenditures not paid | $ | (118) | | | $ | 49 | | |
| Decrease in capital expenditures not paid | | Decrease in capital expenditures not paid | $ | (44) | | | $ | (93) | |
|
See the Combined Notes to Consolidated Financial Statements
2316
COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
| | (In millions) | (In millions) | September 30, 2021 | | December 31, 2020 | (In millions) | June 30, 2022 | | December 31, 2021 |
| ASSETS | ASSETS | | | | ASSETS | | | |
| Current assets | Current assets | | Current assets | |
| Cash and cash equivalents | Cash and cash equivalents | $ | 241 | | | $ | 83 | | Cash and cash equivalents | $ | 120 | | | $ | 131 | |
| Restricted cash and cash equivalents | Restricted cash and cash equivalents | 276 | | | 279 | | Restricted cash and cash equivalents | 384 | | | 210 | |
| Accounts receivable | Accounts receivable | | Accounts receivable | |
| Customer accounts receivable | Customer accounts receivable | 685 | | 656 | Customer accounts receivable | 589 | | 647 |
| Customer allowance for credit losses | Customer allowance for credit losses | (88) | | (97) | Customer allowance for credit losses | (81) | | (73) |
| Customer accounts receivable, net | Customer accounts receivable, net | 597 | | | 559 | | Customer accounts receivable, net | 508 | | | 574 | |
| Other accounts receivable | Other accounts receivable | 252 | | 239 | Other accounts receivable | 448 | | 227 |
| Other allowance for credit losses | Other allowance for credit losses | (19) | | (21) | Other allowance for credit losses | (18) | | (17) |
| Other accounts receivable, net | Other accounts receivable, net | 233 | | | 218 | | Other accounts receivable, net | 430 | | | 210 | |
| | Receivables from affiliates | Receivables from affiliates | 41 | | | 22 | | Receivables from affiliates | 3 | | | 16 | |
| | Inventories, net | Inventories, net | 174 | | | 170 | | Inventories, net | 171 | | | 170 | |
| | Regulatory assets | Regulatory assets | 287 | | | 279 | | Regulatory assets | 325 | | | 335 | |
| | Other | Other | 77 | | | 49 | | Other | 143 | | | 76 | |
| Total current assets | Total current assets | 1,926 | | | 1,659 | | Total current assets | 2,084 | | | 1,722 | |
| Property, plant, and equipment (net of accumulated depreciation and amortization of $5,995 and $5,672 as of September 30, 2021 and December 31, 2020, respectively) | 25,496 | | | 24,557 | | |
| Property, plant, and equipment (net of accumulated depreciation and amortization of $6,400 and $6,099 as of June 30, 2022 and December 31, 2021, respectively) | | Property, plant, and equipment (net of accumulated depreciation and amortization of $6,400 and $6,099 as of June 30, 2022 and December 31, 2021, respectively) | 26,673 | | | 25,995 | |
| Deferred debits and other assets | Deferred debits and other assets | | Deferred debits and other assets | |
| Regulatory assets | Regulatory assets | 1,834 | | | 1,749 | | Regulatory assets | 2,134 | | | 1,870 | |
| Investments | 6 | | | 6 | | |
| | Goodwill | Goodwill | 2,625 | | | 2,625 | | Goodwill | 2,625 | | | 2,625 | |
| Receivables from affiliates | Receivables from affiliates | 2,597 | | | 2,541 | | Receivables from affiliates | — | | | 2,761 | |
| Receivable related to Regulatory Agreement Units | | Receivable related to Regulatory Agreement Units | 1,973 | | | — | |
| Investments | | Investments | 6 | | | 6 | |
| Prepaid pension asset | Prepaid pension asset | 1,111 | | | 1,022 | | Prepaid pension asset | 1,232 | | | 1,086 | |
| | Other | Other | 407 | | | 307 | | Other | 467 | | | 405 | |
| Total deferred debits and other assets | Total deferred debits and other assets | 8,580 | | | 8,250 | | Total deferred debits and other assets | 8,437 | | | 8,753 | |
| Total assets | Total assets | $ | 36,002 | | | $ | 34,466 | | Total assets | $ | 37,194 | | | $ | 36,470 | |
See the Combined Notes to Consolidated Financial Statements
2417
COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
| | (In millions) | (In millions) | September 30, 2021 | | December 31, 2020 | (In millions) | June 30, 2022 | | December 31, 2021 |
| LIABILITIES AND SHAREHOLDERS’ EQUITY | LIABILITIES AND SHAREHOLDERS’ EQUITY | | | | LIABILITIES AND SHAREHOLDERS’ EQUITY | | | |
| Current liabilities | Current liabilities | | Current liabilities | |
| Short-term borrowings | $ | — | | | $ | 323 | | |
| Long-term debt due within one year | — | | | 350 | | |
| | Accounts payable | Accounts payable | 596 | | | 683 | | Accounts payable | $ | 756 | | | $ | 647 | |
| Accrued expenses | Accrued expenses | 311 | | | 390 | | Accrued expenses | 345 | | | 384 | |
| Payables to affiliates | Payables to affiliates | 131 | | | 96 | | Payables to affiliates | 65 | | | 121 | |
| | Customer deposits | Customer deposits | 97 | | | 86 | | Customer deposits | 99 | | | 99 | |
| Regulatory liabilities | Regulatory liabilities | 197 | | | 289 | | Regulatory liabilities | 216 | | | 185 | |
| Mark-to-market derivative liabilities | Mark-to-market derivative liabilities | 5 | | | 33 | | Mark-to-market derivative liabilities | — | | | 18 | |
| | Other | Other | 165 | | | 143 | | Other | 253 | | | 133 | |
| Total current liabilities | Total current liabilities | 1,502 | | | 2,393 | | Total current liabilities | 1,734 | | | 1,587 | |
| Long-term debt | Long-term debt | 9,772 | | | 8,633 | | Long-term debt | 10,516 | | | 9,773 | |
| Long-term debt to financing trust | Long-term debt to financing trust | 205 | | | 205 | | Long-term debt to financing trust | 205 | | | 205 | |
| Deferred credits and other liabilities | Deferred credits and other liabilities | | Deferred credits and other liabilities | |
| Deferred income taxes and unamortized investment tax credits | Deferred income taxes and unamortized investment tax credits | 4,629 | | | 4,341 | | Deferred income taxes and unamortized investment tax credits | 4,852 | | | 4,685 | |
| Regulatory liabilities | | Regulatory liabilities | 6,111 | | | 6,759 | |
| Asset retirement obligations | Asset retirement obligations | 144 | | | 126 | | Asset retirement obligations | 145 | | | 144 | |
| | Non-pension postretirement benefits obligations | Non-pension postretirement benefits obligations | 183 | | | 173 | | Non-pension postretirement benefits obligations | 168 | | | 169 | |
| | Regulatory liabilities | 6,604 | | | 6,403 | | |
| Mark-to-market derivative liabilities | Mark-to-market derivative liabilities | 209 | | | 268 | | Mark-to-market derivative liabilities | 103 | | | 201 | |
| | Other | Other | 603 | | | 595 | | Other | 544 | | | 592 | |
| Total deferred credits and other liabilities | Total deferred credits and other liabilities | 12,372 | | | 11,906 | | Total deferred credits and other liabilities | 11,923 | | | 12,550 | |
| Total liabilities | Total liabilities | 23,851 | | | 23,137 | | Total liabilities | 24,378 | | | 24,115 | |
| Commitments and contingencies | Commitments and contingencies | 0 | | 0 | Commitments and contingencies | 0 | | 0 |
| Shareholders’ equity | Shareholders’ equity | | Shareholders’ equity | |
| Common stock | Common stock | 1,588 | | | 1,588 | | Common stock | 1,588 | | | 1,588 | |
| | Other paid-in capital | Other paid-in capital | 8,878 | | | 8,285 | | Other paid-in capital | 9,411 | | | 9,076 | |
| Retained deficit unappropriated | (1,639) | | | (1,639) | | |
| Retained earnings appropriated | 3,324 | | | 3,095 | | |
| Retained earnings | | Retained earnings | 1,817 | | | 1,691 | |
| | Total shareholders’ equity | Total shareholders’ equity | 12,151 | | | 11,329 | | Total shareholders’ equity | 12,816 | | | 12,355 | |
| Total liabilities and shareholders’ equity | Total liabilities and shareholders’ equity | $ | 36,002 | | | $ | 34,466 | | Total liabilities and shareholders’ equity | $ | 37,194 | | | $ | 36,470 | |
See the Combined Notes to Consolidated Financial Statements
2518
COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
(Unaudited)
| | | | Six Months Ended June 30, 2022 |
| (In millions) | | (In millions) | Common
Stock | | Other
Paid-In
Capital | | Retained
Earnings | | Total
Shareholders’
Equity |
| Balance, December 31, 2021 | | Balance, December 31, 2021 | $ | 1,588 | | | $ | 9,076 | | | $ | 1,691 | | | $ | 12,355 | |
| Net income | | Net income | — | | | — | | | 188 | | | 188 | |
| Common stock dividends | | Common stock dividends | — | | | — | | | (144) | | | (144) | |
| Contributions from parent | | Contributions from parent | — | | | 167 | | | — | | | 167 | |
| Balance, March 31, 2022 | | Balance, March 31, 2022 | $ | 1,588 | | | $ | 9,243 | | | $ | 1,735 | | | $ | 12,566 | |
| Net income | | Net income | — | | | — | | | 227 | | | 227 | |
| Common stock dividends | | Common stock dividends | — | | | — | | | (145) | | | (145) | |
| Contributions from parent | | Contributions from parent | — | | | 168 | | | — | | | 168 | |
| Balance, June 30, 2022 | | Balance, June 30, 2022 | $ | 1,588 | | | $ | 9,411 | | | $ | 1,817 | | | $ | 12,816 | |
| | | | Nine Months Ended September 30, 2021 | | Six Months Ended June 30, 2021 |
| (In millions) | (In millions) | Common
Stock | | Other
Paid-In
Capital | | Retained Deficit
Unappropriated | | Retained
Earnings
Appropriated | | Total
Shareholders’
Equity | (In millions) | Common
Stock | | Other
Paid-In
Capital | | Retained
Earnings | | Total
Shareholders’
Equity |
| Balance, December 31, 2020 | Balance, December 31, 2020 | $ | 1,588 | | | $ | 8,285 | | | $ | (1,639) | | | $ | 3,095 | | | $ | 11,329 | | Balance, December 31, 2020 | $ | 1,588 | | | $ | 8,285 | | | $ | 1,456 | | | $ | 11,329 | |
| Net income | Net income | — | | | — | | | 197 | | | — | | | 197 | | Net income | — | | | — | | | 197 | | | 197 | |
| Appropriation of retained earnings for future dividends | — | | | — | | | (197) | | | 197 | | | — | | |
| Common stock dividends | Common stock dividends | — | | | — | | | — | | | (127) | | | (127) | | Common stock dividends | — | | | — | | | (127) | | | (127) | |
| Contributions from parent | Contributions from parent | — | | | 198 | | | — | | | — | | | 198 | | Contributions from parent | — | | | 198 | | | — | | | 198 | |
| Balance, March 31, 2021 | Balance, March 31, 2021 | $ | 1,588 | | | $ | 8,483 | | | $ | (1,639) | | | $ | 3,165 | | | $ | 11,597 | | Balance, March 31, 2021 | $ | 1,588 | | | $ | 8,483 | | | $ | 1,526 | | | $ | 11,597 | |
| Net income | Net income | — | | | — | | | 192 | | | — | | | 192 | | Net income | — | | | — | | | 192 | | | 192 | |
| Appropriation of retained earnings for future dividends | — | | | — | | | (192) | | | 192 | | | — | | |
| Common stock dividends | Common stock dividends | — | | | — | | | — | | | (126) | | | (126) | | Common stock dividends | — | | | — | | | (126) | | | (126) | |
| Contributions from parent | Contributions from parent | — | | | 197 | | | — | | | — | | | 197 | | Contributions from parent | — | | | 197 | | | — | | | 197 | |
| Balance, June 30, 2021 | Balance, June 30, 2021 | $ | 1,588 | | | $ | 8,680 | | | $ | (1,639) | | | $ | 3,231 | | | $ | 11,860 | | Balance, June 30, 2021 | $ | 1,588 | | | $ | 8,680 | | | $ | 1,592 | | | $ | 11,860 | |
| Net income | — | | | — | | | 220 | | | — | | | 220 | | |
| Appropriation of retained earnings for future dividends | — | | | — | | | (220) | | | 220 | | | — | | |
| Common stock dividends | — | | | — | | | — | | | (127) | | | (127) | | |
| Contributions from parent | — | | | 198 | | | — | | | — | | | 198 | | |
| Balance, September 30, 2021 | $ | 1,588 | | | $ | 8,878 | | | $ | (1,639) | | | $ | 3,324 | | | $ | 12,151 | | |
| | | Nine Months Ended September 30, 2020 | |
| (In millions) | Common
Stock | | Other
Paid-In
Capital | | Retained Deficit
Unappropriated | | Retained
Earnings
Appropriated | | Total
Shareholders’
Equity | |
| Balance, December 31, 2019 | $ | 1,588 | | | $ | 7,572 | | | $ | (1,639) | | | $ | 3,156 | | | $ | 10,677 | | |
| Net income | — | | | — | | | 168 | | | — | | | 168 | | |
| Appropriation of retained earnings for future dividends | — | | | — | | | (168) | | | 168 | | | — | | |
| Common stock dividends | — | | | — | | | — | | | (125) | | | (125) | | |
| Contributions from parent | — | | | 125 | | | — | | | — | | | 125 | | |
| Balance, March 31, 2020 | $ | 1,588 | | | $ | 7,697 | | | $ | (1,639) | | | $ | 3,199 | | | $ | 10,845 | | |
| Net loss | — | | | — | | | (61) | | | — | | | (61) | | |
| | Common stock dividends | — | | | — | | | — | | | (124) | | | (124) | | |
| Contributions from parent | — | | | 124 | | | — | | | — | | | 124 | | |
| Balance, June 30, 2020 | $ | 1,588 | | | $ | 7,821 | | | $ | (1,700) | | | $ | 3,075 | | | $ | 10,784 | | |
| Net income | — | | | — | | | 196 | | | — | | | 196 | | |
| Appropriation of retained earnings for future dividends | — | | | — | | | (196) | | | 196 | | | — | | |
| Common stock dividends | — | | | — | | | — | | | (124) | | | (124) | | |
| Contributions from parent | — | | | 239 | | | — | | | — | | | 239 | | |
| Balance, September 30, 2020 | $ | 1,588 | | | $ | 8,060 | | | $ | (1,700) | | | $ | 3,147 | | | $ | 11,095 | | |
|
See the Combined Notes to Consolidated Financial Statements
2619
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
| | | | Three Months Ended
September 30, | | Nine Months Ended
September 30, | | Three Months Ended
June 30, | | Six Months Ended
June 30, |
| (In millions) | (In millions) | 2021 | | 2020 | | 2021 | | 2020 | (In millions) | 2022 | | 2021 | | 2022 | | 2021 |
| Operating revenues | Operating revenues | | | | | | | | Operating revenues | | | | | | | |
| Electric operating revenues | Electric operating revenues | $ | 757 | | | $ | 751 | | | $ | 2,008 | | | $ | 1,931 | | Electric operating revenues | $ | 707 | | | $ | 602 | | | $ | 1,441 | | | $ | 1,251 | |
| Natural gas operating revenues | Natural gas operating revenues | 56 | | | 54 | | | 365 | | | 358 | | Natural gas operating revenues | 108 | | | 82 | | | 414 | | | 310 | |
| Revenues from alternative revenue programs | Revenues from alternative revenue programs | 3 | | | 5 | | | 20 | | | 10 | | Revenues from alternative revenue programs | — | | | 7 | | | 6 | | | 17 | |
| Operating revenues from affiliates | Operating revenues from affiliates | 2 | | | 3 | | | 6 | | | 7 | | Operating revenues from affiliates | 1 | | | 2 | | | 2 | | | 4 | |
| Total operating revenues | Total operating revenues | 818 | | | 813 | | | 2,399 | | | 2,306 | | Total operating revenues | 816 | | | 693 | | | 1,863 | | | 1,582 | |
| Operating expenses | Operating expenses | | | | | | | | Operating expenses | | | | | | | |
| Purchased power | Purchased power | 206 | | | 190 | | | 540 | | | 495 | | Purchased power | 244 | | | 145 | | | 472 | | | 334 | |
| Purchased fuel | Purchased fuel | 11 | | | 12 | | | 119 | | | 129 | | Purchased fuel | 39 | | | 22 | | | 184 | | | 108 | |
| Purchased power from affiliate | Purchased power from affiliate | 60 | | | 67 | | | 141 | | | 144 | | Purchased power from affiliate | — | | | 40 | | | 33 | | | 81 | |
| Operating and maintenance | Operating and maintenance | 220 | | | 214 | | | 580 | | | 628 | | Operating and maintenance | 168 | | | 166 | | | 364 | | | 360 | |
| Operating and maintenance from affiliates | Operating and maintenance from affiliates | 43 | | | 37 | | | 126 | | | 114 | | Operating and maintenance from affiliates | 47 | | | 43 | | | 99 | | | 83 | |
| Depreciation and amortization | Depreciation and amortization | 86 | | | 85 | | | 259 | | | 259 | | Depreciation and amortization | 93 | | | 87 | | | 185 | | | 173 | |
| Taxes other than income taxes | Taxes other than income taxes | 51 | | | 53 | | | 143 | | | 131 | | Taxes other than income taxes | 48 | | | 49 | | | 95 | | | 92 | |
| Total operating expenses | Total operating expenses | 677 | | | 658 | | | 1,908 | | | 1,900 | | Total operating expenses | 639 | | | 552 | | | 1,432 | | | 1,231 | |
| | Operating income | Operating income | 141 | | | 155 | | | 491 | | | 406 | | Operating income | 177 | | | 141 | | | 431 | | | 351 | |
| Other income and (deductions) | Other income and (deductions) | | | | | | | | Other income and (deductions) | | | | | | | |
| Interest expense, net | Interest expense, net | (37) | | | (36) | | | (110) | | | (100) | | Interest expense, net | (40) | | | (39) | | | (78) | | | (74) | |
| Interest expense to affiliates | Interest expense to affiliates | (3) | | | (3) | | | (9) | | | (8) | | Interest expense to affiliates | (3) | | | (3) | | | (6) | | | (6) | |
| Other, net | Other, net | 7 | | | 6 | | | 20 | | | 12 | | Other, net | 8 | | | 7 | | | 16 | | | 12 | |
| Total other income and (deductions) | Total other income and (deductions) | (33) | | | (33) | | | (99) | | | (96) | | Total other income and (deductions) | (35) | | | (35) | | | (68) | | | (68) | |
| Income before income taxes | Income before income taxes | 108 | | | 122 | | | 392 | | | 310 | | Income before income taxes | 142 | | | 106 | | | 363 | | | 283 | |
| Income taxes | Income taxes | (3) | | | (16) | | | 9 | | | (7) | | Income taxes | 9 | | | 2 | | | 24 | | | 12 | |
| | Net income | Net income | $ | 111 | | | $ | 138 | | | $ | 383 | | | $ | 317 | | Net income | $ | 133 | | | $ | 104 | | | $ | 339 | | | $ | 271 | |
| Comprehensive income | Comprehensive income | $ | 111 | | | $ | 138 | | | $ | 383 | | | $ | 317 | | Comprehensive income | $ | 133 | | | $ | 104 | | | $ | 339 | | | $ | 271 | |
See the Combined Notes to Consolidated Financial Statements
2720
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
| | | Nine Months Ended
September 30, | | Six Months Ended
June 30, |
| (In millions) | (In millions) | 2021 | | 2020 | (In millions) | 2022 | | 2021 |
| Cash flows from operating activities | Cash flows from operating activities | | | | Cash flows from operating activities | | | |
| Net income | Net income | $ | 383 | | | $ | 317 | | Net income | $ | 339 | | | $ | 271 | |
| Adjustments to reconcile net income to net cash flows provided by operating activities: | Adjustments to reconcile net income to net cash flows provided by operating activities: | | Adjustments to reconcile net income to net cash flows provided by operating activities: | |
| Depreciation and amortization | Depreciation and amortization | 259 | | | 259 | | Depreciation and amortization | 185 | | | 173 | |
| | Deferred income taxes and amortization of investment tax credits | Deferred income taxes and amortization of investment tax credits | 19 | | | (5) | | Deferred income taxes and amortization of investment tax credits | 14 | | | 21 | |
| Other non-cash operating activities | Other non-cash operating activities | 4 | | | 27 | | Other non-cash operating activities | 4 | | | (5) | |
| Changes in assets and liabilities: | Changes in assets and liabilities: | | Changes in assets and liabilities: | |
| Accounts receivable | Accounts receivable | 47 | | | (2) | | Accounts receivable | (29) | | | 86 | |
| Receivables from and payables to affiliates, net | Receivables from and payables to affiliates, net | 16 | | | (7) | | Receivables from and payables to affiliates, net | (40) | | | 2 | |
| Inventories | Inventories | (21) | | | (3) | | Inventories | (8) | | | 3 | |
| Accounts payable and accrued expenses | Accounts payable and accrued expenses | (23) | | | 32 | | Accounts payable and accrued expenses | 5 | | | (46) | |
| | Income taxes | Income taxes | 55 | | | 48 | | Income taxes | 49 | | | 24 | |
| Regulatory assets and liabilities, net | | Regulatory assets and liabilities, net | (24) | | | (14) | |
| Pension and non-pension postretirement benefit contributions | Pension and non-pension postretirement benefit contributions | (15) | | | (18) | | Pension and non-pension postretirement benefit contributions | (13) | | | (15) | |
| Other assets and liabilities | Other assets and liabilities | (87) | | | (13) | | Other assets and liabilities | (70) | | | (126) | |
| Net cash flows provided by operating activities | Net cash flows provided by operating activities | 637 | | | 635 | | Net cash flows provided by operating activities | 412 | | | 374 | |
| Cash flows from investing activities | Cash flows from investing activities | | | | Cash flows from investing activities | | | |
| Capital expenditures | Capital expenditures | (878) | | | (824) | | Capital expenditures | (658) | | | (577) | |
| Changes in Exelon intercompany money pool | — | | | 68 | | |
| | | Other investing activities | Other investing activities | 5 | | | 4 | | Other investing activities | 5 | | | 4 | |
| Net cash flows used in investing activities | Net cash flows used in investing activities | (873) | | | (752) | | Net cash flows used in investing activities | (653) | | | (573) | |
| Cash flows from financing activities | Cash flows from financing activities | | | | Cash flows from financing activities | | | |
| | Changes in short-term borrowings | | Changes in short-term borrowings | 210 | | | — | |
| Issuance of long-term debt | Issuance of long-term debt | 750 | | | 350 | | Issuance of long-term debt | 350 | | | 375 | |
| Retirement of long-term debt | Retirement of long-term debt | (300) | | | — | | Retirement of long-term debt | (350) | | | — | |
| | Changes in Exelon intercompany money pool | Changes in Exelon intercompany money pool | (40) | | | — | | Changes in Exelon intercompany money pool | — | | | (40) | |
| Dividends paid on common stock | Dividends paid on common stock | (254) | | | (255) | | Dividends paid on common stock | (200) | | | (169) | |
| Contributions from parent | Contributions from parent | 414 | | | 248 | | Contributions from parent | 227 | | | 395 | |
| | Other financing activities | Other financing activities | (8) | | | (4) | | Other financing activities | (8) | | | (4) | |
| Net cash flows provided by financing activities | Net cash flows provided by financing activities | 562 | | | 339 | | Net cash flows provided by financing activities | 229 | | | 557 | |
| Increase in cash, restricted cash, and cash equivalents | 326 | | | 222 | | |
| (Decrease) increase in cash, restricted cash, and cash equivalents | | (Decrease) increase in cash, restricted cash, and cash equivalents | (12) | | | 358 | |
| Cash, restricted cash, and cash equivalents at beginning of period | Cash, restricted cash, and cash equivalents at beginning of period | 26 | | | 27 | | Cash, restricted cash, and cash equivalents at beginning of period | 44 | | | 26 | |
| Cash, restricted cash, and cash equivalents at end of period | Cash, restricted cash, and cash equivalents at end of period | $ | 352 | | | $ | 249 | | Cash, restricted cash, and cash equivalents at end of period | $ | 32 | | | $ | 384 | |
| | Supplemental cash flow information | Supplemental cash flow information | | Supplemental cash flow information | |
| Increase in capital expenditures not paid | $ | 25 | | | $ | 28 | | |
| Decrease in capital expenditures not paid | | Decrease in capital expenditures not paid | $ | (11) | | | $ | (16) | |
|
See the Combined Notes to Consolidated Financial Statements
2821
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
| | (In millions) | (In millions) | September 30, 2021 | | December 31, 2020 | (In millions) | June 30, 2022 | | December 31, 2021 |
| ASSETS | ASSETS | | | | ASSETS | | | |
| Current assets | Current assets | | Current assets | |
| Cash and cash equivalents | Cash and cash equivalents | $ | 344 | | | $ | 19 | | Cash and cash equivalents | $ | 23 | | | $ | 36 | |
| Restricted cash and cash equivalents | Restricted cash and cash equivalents | 8 | | | 7 | | Restricted cash and cash equivalents | 9 | | | 8 | |
| Accounts receivable | Accounts receivable | | Accounts receivable | |
| Customer accounts receivable | Customer accounts receivable | 411 | | 511 | Customer accounts receivable | 493 | | 489 |
| Customer allowance for credit losses | Customer allowance for credit losses | (101) | | (116) | Customer allowance for credit losses | (107) | | (105) |
| Customer accounts receivable, net | Customer accounts receivable, net | 310 | | | 395 | | Customer accounts receivable, net | 386 | | | 384 | |
| Other accounts receivable | Other accounts receivable | 124 | | 130 | Other accounts receivable | 138 | | 116 |
| Other allowance for credit losses | Other allowance for credit losses | (7) | | (8) | Other allowance for credit losses | (10) | | (7) |
| Other accounts receivable, net | Other accounts receivable, net | 117 | | | 122 | | Other accounts receivable, net | 128 | | | 109 | |
| | Receivables from affiliates | Receivables from affiliates | 9 | | | 2 | | Receivables from affiliates | — | | | 1 | |
| | Inventories, net | Inventories, net | | Inventories, net | |
| Fossil fuel | Fossil fuel | 47 | | | 33 | | Fossil fuel | 55 | | | 51 | |
| Materials and supplies | Materials and supplies | 45 | | | 38 | | Materials and supplies | 48 | | | 45 | |
| Prepaid utility taxes | Prepaid utility taxes | 34 | | | — | | Prepaid utility taxes | 85 | | | 1 | |
| Regulatory assets | Regulatory assets | 35 | | | 25 | | Regulatory assets | 61 | | | 48 | |
| | Other | Other | 29 | | | 21 | | Other | 36 | | | 28 | |
| Total current assets | Total current assets | 978 | | | 662 | | Total current assets | 831 | | | 711 | |
| Property, plant, and equipment (net of accumulated depreciation and amortization of $3,921 and $3,843 as of September 30, 2021 and December 31, 2020, respectively) | 10,841 | | | 10,181 | | |
| Property, plant, and equipment (net of accumulated depreciation and amortization of $4,021 and $3,964 as of June 30, 2022 and December 31, 2021, respectively) | | Property, plant, and equipment (net of accumulated depreciation and amortization of $4,021 and $3,964 as of June 30, 2022 and December 31, 2021, respectively) | 11,591 | | | 11,117 | |
| Deferred debits and other assets | Deferred debits and other assets | | Deferred debits and other assets | |
| Regulatory assets | Regulatory assets | 901 | | | 776 | | Regulatory assets | 1,033 | | | 943 | |
| | Investments | 34 | | | 30 | | |
| | Receivables from affiliates | Receivables from affiliates | 546 | | | 475 | | Receivables from affiliates | — | | | 597 | |
| Receivable related to Regulatory Agreement Units | | Receivable related to Regulatory Agreement Units | 292 | | | — | |
| Investments | | Investments | 32 | | | 34 | |
| Prepaid pension asset | Prepaid pension asset | 386 | | | 375 | | Prepaid pension asset | 405 | | | 386 | |
| | Other | Other | 47 | | | 32 | | Other | 32 | | | 36 | |
| Total deferred debits and other assets | Total deferred debits and other assets | 1,914 | | | 1,688 | | Total deferred debits and other assets | 1,794 | | | 1,996 | |
| Total assets | Total assets | $ | 13,733 | | | $ | 12,531 | | Total assets | $ | 14,216 | | | $ | 13,824 | |
See the Combined Notes to Consolidated Financial Statements
2922
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
| | (In millions) | (In millions) | September 30, 2021 | | December 31, 2020 | (In millions) | June 30, 2022 | | December 31, 2021 |
| LIABILITIES AND SHAREHOLDER'S EQUITY | LIABILITIES AND SHAREHOLDER'S EQUITY | | | | LIABILITIES AND SHAREHOLDER'S EQUITY | | | |
| Current liabilities | Current liabilities | | Current liabilities | |
| | Short-term borrowings | | Short-term borrowings | $ | 210 | | | $ | — | |
| Long-term debt due within one year | Long-term debt due within one year | $ | 350 | | | $ | 300 | | Long-term debt due within one year | 50 | | | 350 | |
| Accounts payable | Accounts payable | 487 | | | 479 | | Accounts payable | 525 | | | 494 | |
| Accrued expenses | Accrued expenses | 168 | | | 129 | | Accrued expenses | 161 | | | 136 | |
| Payables to affiliates | Payables to affiliates | 60 | | | 50 | | Payables to affiliates | 29 | | | 70 | |
| Borrowings from Exelon intercompany money pool | — | | | 40 | | |
| | Customer deposits | Customer deposits | 48 | | | 59 | | Customer deposits | 53 | | | 48 | |
| Regulatory liabilities | Regulatory liabilities | 102 | | | 121 | | Regulatory liabilities | 75 | | | 94 | |
| | Other | Other | 31 | | | 30 | | Other | 47 | | | 35 | |
| Total current liabilities | Total current liabilities | 1,246 | | | 1,208 | | Total current liabilities | 1,150 | | | 1,227 | |
| Long-term debt | Long-term debt | 3,846 | | | 3,453 | | Long-term debt | 4,142 | | | 3,847 | |
| Long-term debt to financing trusts | Long-term debt to financing trusts | 184 | | | 184 | | Long-term debt to financing trusts | 184 | | | 184 | |
| Deferred credits and other liabilities | Deferred credits and other liabilities | | Deferred credits and other liabilities | |
| Deferred income taxes and unamortized investment tax credits | Deferred income taxes and unamortized investment tax credits | 2,385 | | | 2,242 | | Deferred income taxes and unamortized investment tax credits | 2,534 | | | 2,421 | |
| Regulatory liabilities | | Regulatory liabilities | 329 | | | 635 | |
| Asset retirement obligations | Asset retirement obligations | 29 | | | 29 | | Asset retirement obligations | 29 | | | 29 | |
| Non-pension postretirement benefits obligations | Non-pension postretirement benefits obligations | 288 | | | 286 | | Non-pension postretirement benefits obligations | 288 | | | 286 | |
| | Regulatory liabilities | 588 | | | 503 | | |
| | Other | Other | 92 | | | 93 | | Other | 82 | | | 83 | |
| Total deferred credits and other liabilities | Total deferred credits and other liabilities | 3,382 | | | 3,153 | | Total deferred credits and other liabilities | 3,262 | | | 3,454 | |
| Total liabilities | Total liabilities | 8,658 | | | 7,998 | | Total liabilities | 8,738 | | | 8,712 | |
| Commitments and contingencies | Commitments and contingencies | 0 | | 0 | Commitments and contingencies | 0 | | 0 |
| Shareholder’s equity | Shareholder’s equity | | Shareholder’s equity | |
| Common stock | Common stock | 3,428 | | | 3,014 | | Common stock | 3,655 | | | 3,428 | |
| | Retained earnings | Retained earnings | 1,647 | | | 1,519 | | Retained earnings | 1,823 | | | 1,684 | |
| | Total shareholder’s equity | Total shareholder’s equity | 5,075 | | | 4,533 | | Total shareholder’s equity | 5,478 | | | 5,112 | |
| Total liabilities and shareholder's equity | Total liabilities and shareholder's equity | $ | 13,733 | | | $ | 12,531 | | Total liabilities and shareholder's equity | $ | 14,216 | | | $ | 13,824 | |
See the Combined Notes to Consolidated Financial Statements
3023
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER’S EQUITY
(Unaudited)
| | | | Six Months Ended June 30, 2022 |
| (In millions) | | (In millions) | Common
Stock | | Retained
Earnings | | | Total
Shareholder's
Equity |
| Balance, December 31, 2021 | | Balance, December 31, 2021 | $ | 3,428 | | | $ | 1,684 | | | | $ | 5,112 | |
| Net income | | Net income | — | | | 206 | | | | 206 | |
| Common stock dividends | | Common stock dividends | — | | | (100) | | | | (100) | |
| Contributions from parent | | Contributions from parent | 227 | | | — | | | | 227 | |
| Balance, March 31, 2022 | | Balance, March 31, 2022 | $ | 3,655 | | | $ | 1,790 | | | | $ | 5,445 | |
| Net income | | Net income | — | | | 133 | | | | 133 | |
| Common stock dividends | | Common stock dividends | — | | | (100) | | | | (100) | |
| | Balance, June 30, 2022 | | Balance, June 30, 2022 | $ | 3,655 | | | $ | 1,823 | | | | $ | 5,478 | |
| | | | Nine Months Ended September 30, 2021 | | Six Months Ended June 30, 2021 |
| (In millions) | (In millions) | Common
Stock | | Retained
Earnings | | | Total
Shareholder's
Equity | (In millions) | Common
Stock | | Retained
Earnings | | | Total
Shareholder's
Equity |
| Balance, December 31, 2020 | Balance, December 31, 2020 | $ | 3,014 | | | $ | 1,519 | | | | $ | 4,533 | | Balance, December 31, 2020 | $ | 3,014 | | | $ | 1,519 | | | | $ | 4,533 | |
| Net income | Net income | — | | | 167 | | | | 167 | | Net income | — | | | 167 | | | | 167 | |
| Common stock dividends | Common stock dividends | — | | | (85) | | | | (85) | | Common stock dividends | — | | | (85) | | | | (85) | |
| | Balance, March 31, 2021 | Balance, March 31, 2021 | $ | 3,014 | | | $ | 1,601 | | | | $ | 4,615 | | Balance, March 31, 2021 | $ | 3,014 | | | $ | 1,601 | | | | $ | 4,615 | |
| Net income | Net income | — | | | 104 | | | | 104 | | Net income | — | | | 104 | | | | 104 | |
| Common stock dividends | Common stock dividends | — | | | (84) | | | | (84) | | Common stock dividends | — | | | (84) | | | | (84) | |
| Contributions from parent | Contributions from parent | 395 | | | — | | | | 395 | | Contributions from parent | 395 | | | — | | | | 395 | |
| | Balance, June 30, 2021 | Balance, June 30, 2021 | $ | 3,409 | | | $ | 1,621 | | | | $ | 5,030 | | Balance, June 30, 2021 | $ | 3,409 | | | $ | 1,621 | | | | $ | 5,030 | |
| Net income | — | | | 111 | | | | 111 | | |
| Common stock dividends | — | | | (85) | | | | (85) | | |
| Contributions from parent | 19 | | | — | | | | 19 | | |
| Balance, September 30, 2021 | $ | 3,428 | | | $ | 1,647 | | | | $ | 5,075 | | |
| | | Nine Months Ended September 30, 2020 | |
| (In millions) | Common
Stock | | Retained
Earnings | | | Total
Shareholder's
Equity | |
| Balance, December 31, 2019 | $ | 2,766 | | | $ | 1,412 | | | | $ | 4,178 | | |
| Net income | — | | | 140 | | | | 140 | | |
| Common stock dividends | — | | | (85) | | | | (85) | | |
| Contributions from parent | 231 | | | — | | | | 231 | | |
| Balance, March 31, 2020 | $ | 2,997 | | | $ | 1,467 | | | | $ | 4,464 | | |
| Net income | — | | | 39 | | | | 39 | | |
| Common stock dividends | — | | | (85) | | | | (85) | | |
| | Balance, June 30, 2020 | $ | 2,997 | | | $ | 1,421 | | | | $ | 4,418 | | |
| Net income | — | | | 138 | | | | 138 | | |
| Common stock dividends | — | | | (85) | | | | (85) | | |
| Contributions from parent | 17 | | | — | | | | 17 | | |
| Balance, September 30, 2020 | $ | 3,014 | | | $ | 1,474 | | | | $ | 4,488 | | |
See the Combined Notes to Consolidated Financial Statements
3124
BALTIMORE GAS AND ELECTRIC COMPANY
STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
| | | Three Months Ended
September 30, | | Nine Months Ended
September 30, | | Three Months Ended
June 30, | | Six Months Ended
June 30, |
| (In millions) | (In millions) | 2021 | | 2020 | | 2021 | | 2020 | (In millions) | 2022 | | 2021 | | 2022 | | 2021 |
| Operating revenues | Operating revenues | | | | | | | | Operating revenues | | | | | | | |
| Electric operating revenues | Electric operating revenues | $ | 694 | | | $ | 649 | | | $ | 1,874 | | | $ | 1,775 | | Electric operating revenues | $ | 642 | | | $ | 560 | | | $ | 1,377 | | | $ | 1,180 | |
| Natural gas operating revenues | Natural gas operating revenues | 93 | | | 85 | | | 549 | | | 503 | | Natural gas operating revenues | 161 | | | 125 | | | 585 | | | 455 | |
| Revenues from alternative revenue programs | Revenues from alternative revenue programs | (24) | | | (9) | | | (17) | | | (10) | | Revenues from alternative revenue programs | (20) | | | (10) | | | (32) | | | 8 | |
| Operating revenues from affiliates | Operating revenues from affiliates | 7 | | | 6 | | | 20 | | | 16 | | Operating revenues from affiliates | 3 | | | 7 | | | 10 | | | 13 | |
| Total operating revenues | Total operating revenues | 770 | | | 731 | | | 2,426 | | | 2,284 | | Total operating revenues | 786 | | | 682 | | | 1,940 | | | 1,656 | |
| Operating expenses | Operating expenses | | | | | | | | Operating expenses | | | | | | | |
| Purchased power | Purchased power | 206 | | | 155 | | | 501 | | | 376 | | Purchased power | 241 | | | 133 | | | 526 | | | 295 | |
| Purchased fuel | Purchased fuel | 20 | | | 12 | | | 146 | | | 106 | | Purchased fuel | 48 | | | 27 | | | 199 | | | 126 | |
| Purchased power and fuel from affiliate | Purchased power and fuel from affiliate | 64 | | | 83 | | | 193 | | | 249 | | Purchased power and fuel from affiliate | — | | | 59 | | | 18 | | | 129 | |
| Operating and maintenance | Operating and maintenance | 159 | | | 152 | | | 458 | | | 445 | | Operating and maintenance | 154 | | | 147 | | | 321 | | | 299 | |
| Operating and maintenance from affiliates | Operating and maintenance from affiliates | 46 | | | 39 | | | 137 | | | 122 | | Operating and maintenance from affiliates | 51 | | | 46 | | | 102 | | | 91 | |
| Depreciation and amortization | Depreciation and amortization | 142 | | | 133 | | | 434 | | | 405 | | Depreciation and amortization | 152 | | | 141 | | | 322 | | | 293 | |
| Taxes other than income taxes | Taxes other than income taxes | 72 | | | 68 | | | 211 | | | 200 | | Taxes other than income taxes | 71 | | | 67 | | | 148 | | | 139 | |
| Total operating expenses | Total operating expenses | 709 | | | 642 | | | 2,080 | | | 1,903 | | Total operating expenses | 717 | | | 620 | | | 1,636 | | | 1,372 | |
| | Operating income | Operating income | 61 | | | 89 | | | 346 | | | 381 | | Operating income | 69 | | | 62 | | | 304 | | | 284 | |
| Other income and (deductions) | Other income and (deductions) | | | | | | | | Other income and (deductions) | | | | | | | |
| Interest expense, net | Interest expense, net | (36) | | | (34) | | | (103) | | | (99) | | Interest expense, net | (36) | | | (34) | | | (71) | | | (67) | |
| | Other, net | Other, net | 7 | | | 6 | | | 23 | | | 17 | | Other, net | 5 | | | 9 | | | 11 | | | 16 | |
| Total other income and (deductions) | Total other income and (deductions) | (29) | | | (28) | | | (80) | | | (82) | | Total other income and (deductions) | (31) | | | (25) | | | (60) | | | (51) | |
| Income before income taxes | Income before income taxes | 32 | | | 61 | | | 266 | | | 299 | | Income before income taxes | 38 | | | 37 | | | 244 | | | 233 | |
| Income taxes | Income taxes | (4) | | | 8 | | | (24) | | | 26 | | Income taxes | 1 | | | (8) | | | 10 | | | (21) | |
| | Net income | Net income | $ | 36 | | | $ | 53 | | | $ | 290 | | | $ | 273 | | Net income | $ | 37 | | | $ | 45 | | | $ | 234 | | | $ | 254 | |
| | Comprehensive income | Comprehensive income | $ | 36 | | | $ | 53 | | | $ | 290 | | | $ | 273 | | Comprehensive income | $ | 37 | | | $ | 45 | | | $ | 234 | | | $ | 254 | |
|
See the Combined Notes to Consolidated Financial Statements
3225
BALTIMORE GAS AND ELECTRIC COMPANY
STATEMENTS OF CASH FLOWS
(Unaudited)
| | | Nine Months Ended
September 30, | | Six Months Ended
June 30, |
| (In millions) | (In millions) | 2021 | | 2020 | (In millions) | 2022 | | 2021 |
| Cash flows from operating activities | Cash flows from operating activities | | | | Cash flows from operating activities | | | |
| Net income | Net income | $ | 290 | | | $ | 273 | | Net income | $ | 234 | | | $ | 254 | |
| Adjustments to reconcile net income to net cash flows provided by operating activities: | Adjustments to reconcile net income to net cash flows provided by operating activities: | | Adjustments to reconcile net income to net cash flows provided by operating activities: | |
| Depreciation and amortization | Depreciation and amortization | 434 | | | 405 | | Depreciation and amortization | 322 | | | 293 | |
| | Deferred income taxes and amortization of investment tax credits | Deferred income taxes and amortization of investment tax credits | 7 | | | 35 | | Deferred income taxes and amortization of investment tax credits | 13 | | | 11 | |
| | Other non-cash operating activities | Other non-cash operating activities | 77 | | | 82 | | Other non-cash operating activities | 79 | | | 28 | |
| Changes in assets and liabilities: | Changes in assets and liabilities: | | Changes in assets and liabilities: | |
| Accounts receivable | Accounts receivable | 92 | | | (19) | | Accounts receivable | (14) | | | 73 | |
| Receivables from and payables to affiliates, net | Receivables from and payables to affiliates, net | (13) | | | (27) | | Receivables from and payables to affiliates, net | (11) | | | (19) | |
| Inventories | Inventories | (30) | | | 2 | | Inventories | (27) | | | (9) | |
| Accounts payable and accrued expenses | Accounts payable and accrued expenses | 14 | | | 53 | | Accounts payable and accrued expenses | (12) | | | (51) | |
| | Collateral received, net | | Collateral received, net | 190 | | | 2 | |
| Income taxes | Income taxes | 3 | | | 46 | | Income taxes | (27) | | | (27) | |
| Regulatory assets and liabilities, net | | Regulatory assets and liabilities, net | (36) | | | (61) | |
| Pension and non-pension postretirement benefit contributions | Pension and non-pension postretirement benefit contributions | (76) | | | (74) | | Pension and non-pension postretirement benefit contributions | (59) | | | (71) | |
| Other assets and liabilities | Other assets and liabilities | (129) | | | (50) | | Other assets and liabilities | 24 | | | (35) | |
| Net cash flows provided by operating activities | Net cash flows provided by operating activities | 669 | | | 726 | | Net cash flows provided by operating activities | 676 | | | 388 | |
| Cash flows from investing activities | Cash flows from investing activities | | | | Cash flows from investing activities | | | |
| Capital expenditures | Capital expenditures | (907) | | | (838) | | Capital expenditures | (578) | | | (620) | |
| | Other investing activities | Other investing activities | 13 | | | — | | Other investing activities | 7 | | | 10 | |
| Net cash flows used in investing activities | Net cash flows used in investing activities | (894) | | | (838) | | Net cash flows used in investing activities | (571) | | | (610) | |
| Cash flows from financing activities | Cash flows from financing activities | | | | Cash flows from financing activities | | | |
| Changes in short-term borrowings | Changes in short-term borrowings | — | | | (76) | | Changes in short-term borrowings | (130) | | | — | |
| Issuance of long-term debt | Issuance of long-term debt | 600 | | | 400 | | Issuance of long-term debt | 500 | | | 600 | |
| Retirement of long-term debt | (300) | | | — | | |
| | | Dividends paid on common stock | Dividends paid on common stock | (219) | | | (186) | | Dividends paid on common stock | (150) | | | (146) | |
| Contributions from parent | Contributions from parent | 257 | | | 284 | | Contributions from parent | 186 | | | — | |
| Other financing activities | Other financing activities | (6) | | | (8) | | Other financing activities | (7) | | | (6) | |
| Net cash flows provided by financing activities | Net cash flows provided by financing activities | 332 | | | 414 | | Net cash flows provided by financing activities | 399 | | | 448 | |
| Increase in cash, restricted cash, and cash equivalents | Increase in cash, restricted cash, and cash equivalents | 107 | | | 302 | | Increase in cash, restricted cash, and cash equivalents | 504 | | | 226 | |
| Cash, restricted cash, and cash equivalents at beginning of period | Cash, restricted cash, and cash equivalents at beginning of period | 145 | | | 25 | | Cash, restricted cash, and cash equivalents at beginning of period | 55 | | | 145 | |
| Cash, restricted cash, and cash equivalents at end of period | Cash, restricted cash, and cash equivalents at end of period | $ | 252 | | | $ | 327 | | Cash, restricted cash, and cash equivalents at end of period | $ | 559 | | | $ | 371 | |
| | Supplemental cash flow information | Supplemental cash flow information | | Supplemental cash flow information | |
| (Decrease) increase in capital expenditures not paid | $ | (70) | | | $ | 7 | | |
| Decrease in capital expenditures not paid | | Decrease in capital expenditures not paid | $ | (21) | | | $ | (71) | |
|
See the Combined Notes to Consolidated Financial Statements
3326
BALTIMORE GAS AND ELECTRIC COMPANY
BALANCE SHEETS
(Unaudited)
| | (In millions) | (In millions) | September 30, 2021 | | December 31, 2020 | (In millions) | June 30, 2022 | | December 31, 2021 |
| ASSETS | ASSETS | | | | ASSETS | | | |
| Current assets | Current assets | | Current assets | |
| Cash and cash equivalents | Cash and cash equivalents | $ | 225 | | | $ | 144 | | Cash and cash equivalents | $ | 354 | | | $ | 51 | |
| Restricted cash and cash equivalents | Restricted cash and cash equivalents | 27 | | | 1 | | Restricted cash and cash equivalents | 205 | | | 4 | |
| Accounts receivable | Accounts receivable | | Accounts receivable | |
| Customer accounts receivable | Customer accounts receivable | 351 | | 487 | Customer accounts receivable | 462 | | 436 |
| Customer allowance for credit losses | Customer allowance for credit losses | (31) | | (35) | Customer allowance for credit losses | (57) | | (38) |
| Customer accounts receivable, net | Customer accounts receivable, net | 320 | | | 452 | | Customer accounts receivable, net | 405 | | | 398 | |
| Other accounts receivable | Other accounts receivable | 149 | | 117 | Other accounts receivable | 122 | | 124 |
| Other allowance for credit losses | Other allowance for credit losses | (8) | | (9) | Other allowance for credit losses | (11) | | (9) |
| Other accounts receivable, net | Other accounts receivable, net | 141 | | | 108 | | Other accounts receivable, net | 111 | | | 115 | |
| | Receivables from affiliates | Receivables from affiliates | 2 | | | 3 | | Receivables from affiliates | — | | | 1 | |
| | Inventories, net | Inventories, net | | Inventories, net | |
| Fossil fuel | Fossil fuel | 46 | | | 25 | | Fossil fuel | 68 | | | 42 | |
| Materials and supplies | Materials and supplies | 50 | | | 41 | | Materials and supplies | 54 | | | 53 | |
| | Prepaid utility taxes | | Prepaid utility taxes | — | | | 49 | |
| Regulatory assets | Regulatory assets | 185 | | | 168 | | Regulatory assets | 178 | | | 215 | |
| | Other | Other | 8 | | | 6 | | Other | 10 | | | 8 | |
| Total current assets | Total current assets | 1,004 | | | 948 | | Total current assets | 1,385 | | | 936 | |
| Property, plant, and equipment (net of accumulated depreciation and amortization of $4,212 and $4,034 as of September 30, 2021 and December 31, 2020, respectively) | 10,374 | | | 9,872 | | |
| Property, plant, and equipment (net of accumulated depreciation and amortization of $4,464 and $4,299 as of June 30, 2022 and December 31, 2021, respectively) | | Property, plant, and equipment (net of accumulated depreciation and amortization of $4,464 and $4,299 as of June 30, 2022 and December 31, 2021, respectively) | 10,899 | | | 10,577 | |
| Deferred debits and other assets | Deferred debits and other assets | | Deferred debits and other assets | |
| Regulatory assets | Regulatory assets | 468 | | | 481 | | Regulatory assets | 465 | | | 477 | |
| | Investments | Investments | 15 | | | 10 | | Investments | 7 | | | 14 | |
| | Prepaid pension asset | Prepaid pension asset | 289 | | | 270 | | Prepaid pension asset | 307 | | | 276 | |
| | Other | Other | 47 | | | 69 | | Other | 30 | | | 44 | |
| Total deferred debits and other assets | Total deferred debits and other assets | 819 | | | 830 | | Total deferred debits and other assets | 809 | | | 811 | |
| Total assets | Total assets | $ | 12,197 | | | $ | 11,650 | | Total assets | $ | 13,093 | | | $ | 12,324 | |
See the Combined Notes to Consolidated Financial Statements
3427
BALTIMORE GAS AND ELECTRIC COMPANY
BALANCE SHEETS
(Unaudited)
| | (In millions) | (In millions) | September 30, 2021 | | December 31, 2020 | (In millions) | June 30, 2022 | | December 31, 2021 |
| LIABILITIES AND SHAREHOLDER'S EQUITY | LIABILITIES AND SHAREHOLDER'S EQUITY | | | | LIABILITIES AND SHAREHOLDER'S EQUITY | | | |
| Current liabilities | Current liabilities | | Current liabilities | |
| | Short-term borrowings | | Short-term borrowings | $ | — | | | $ | 130 | |
| Long-term debt due within one year | Long-term debt due within one year | $ | 250 | | | $ | 300 | | Long-term debt due within one year | 250 | | | 250 | |
| Accounts payable | Accounts payable | 291 | | | 346 | | Accounts payable | 339 | | | 349 | |
| Accrued expenses | Accrued expenses | 204 | | | 205 | | Accrued expenses | 133 | | | 176 | |
| Payables to affiliates | Payables to affiliates | 49 | | | 61 | | Payables to affiliates | 30 | | | 48 | |
| | Customer deposits | Customer deposits | 98 | | | 110 | | Customer deposits | 100 | | | 97 | |
| Regulatory liabilities | Regulatory liabilities | 34 | | | 30 | | Regulatory liabilities | 45 | | | 26 | |
| | Other | Other | 81 | | | 91 | | Other | 224 | | | 48 | |
| Total current liabilities | Total current liabilities | 1,007 | | | 1,143 | | Total current liabilities | 1,121 | | | 1,124 | |
| Long-term debt | Long-term debt | 3,710 | | | 3,364 | | Long-term debt | 4,206 | | | 3,711 | |
| | Deferred credits and other liabilities | Deferred credits and other liabilities | | Deferred credits and other liabilities | |
| Deferred income taxes and unamortized investment tax credits | Deferred income taxes and unamortized investment tax credits | 1,656 | | | 1,521 | | Deferred income taxes and unamortized investment tax credits | 1,777 | | | 1,686 | |
| Regulatory liabilities | | Regulatory liabilities | 869 | | | 934 | |
| Asset retirement obligations | Asset retirement obligations | 26 | | | 23 | | Asset retirement obligations | 26 | | | 26 | |
| Non-pension postretirement benefits obligations | Non-pension postretirement benefits obligations | 177 | | | 189 | | Non-pension postretirement benefits obligations | 169 | | | 175 | |
| | Regulatory liabilities | 989 | | | 1,109 | | |
| | Other | Other | 107 | | | 104 | | Other | 85 | | | 98 | |
| Total deferred credits and other liabilities | Total deferred credits and other liabilities | 2,955 | | | 2,946 | | Total deferred credits and other liabilities | 2,926 | | | 2,919 | |
| Total liabilities | Total liabilities | 7,672 | | | 7,453 | | Total liabilities | 8,253 | | | 7,754 | |
| Commitments and contingencies | Commitments and contingencies | 0 | | 0 | Commitments and contingencies | 0 | | 0 |
| Shareholder's equity | Shareholder's equity | | Shareholder's equity | |
| Common stock | Common stock | 2,575 | | | 2,318 | | Common stock | 2,761 | | | 2,575 | |
| | Retained earnings | Retained earnings | 1,950 | | | 1,879 | | Retained earnings | 2,079 | | | 1,995 | |
| | Total shareholder's equity | Total shareholder's equity | 4,525 | | | 4,197 | | Total shareholder's equity | 4,840 | | | 4,570 | |
| | Total liabilities and shareholder's equity | Total liabilities and shareholder's equity | $ | 12,197 | | | $ | 11,650 | | Total liabilities and shareholder's equity | $ | 13,093 | | | $ | 12,324 | |
See the Combined Notes to Consolidated Financial Statements
3528
BALTIMORE GAS AND ELECTRIC COMPANY
STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY
(Unaudited)
| | | | Six Months Ended June 30, 2022 | |
| (In millions) | | (In millions) | Common
Stock | | Retained
Earnings | | Total
Shareholder's
Equity | |
| Balance, December 31, 2021 | | Balance, December 31, 2021 | $ | 2,575 | | | $ | 1,995 | | | $ | 4,570 | | |
| Net income | | Net income | — | | | 198 | | | 198 | | |
| Common stock dividends | | Common stock dividends | — | | | (76) | | | (76) | | |
| | Balance, March 31, 2022 | | Balance, March 31, 2022 | $ | 2,575 | | | $ | 2,117 | | | $ | 4,692 | | |
| Net income | | Net income | — | | | 37 | | | 37 | | |
| Common stock dividends | | Common stock dividends | — | | | (75) | | | (75) | | |
| Contributions from parent | | Contributions from parent | 186 | | | — | | | 186 | | |
| | Balance, June 30, 2022 | | Balance, June 30, 2022 | $ | 2,761 | | | $ | 2,079 | | | $ | 4,840 | | |
| | | Nine Months Ended September 30, 2021 | | | Six Months Ended June 30, 2021 | |
| (In millions) | (In millions) | Common
Stock | | Retained
Earnings | | Total
Shareholder's
Equity | | (In millions) | Common
Stock | | Retained
Earnings | | Total
Shareholder's
Equity | |
| Balance, December 31, 2020 | Balance, December 31, 2020 | $ | 2,318 | | | $ | 1,879 | | | $ | 4,197 | | | Balance, December 31, 2020 | $ | 2,318 | | | $ | 1,879 | | | $ | 4,197 | | |
| Net income | Net income | — | | | 209 | | | 209 | | | Net income | — | | | 209 | | | 209 | | |
| Common stock dividends | Common stock dividends | — | | | (74) | | | (74) | | | Common stock dividends | — | | | (74) | | | (74) | | |
| | Balance, March 31, 2021 | Balance, March 31, 2021 | $ | 2,318 | | | $ | 2,014 | | | $ | 4,332 | | | Balance, March 31, 2021 | $ | 2,318 | | | $ | 2,014 | | | $ | 4,332 | | |
| Net income | Net income | — | | | 45 | | | 45 | | | Net income | — | | | 45 | | | 45 | | |
| Common stock dividends | Common stock dividends | — | | | (72) | | | (72) | | | Common stock dividends | — | | | (72) | | | (72) | | |
| | Balance, June 30, 2021 | Balance, June 30, 2021 | $ | 2,318 | | | $ | 1,987 | | | $ | 4,305 | | | Balance, June 30, 2021 | $ | 2,318 | | | $ | 1,987 | | | $ | 4,305 | | |
| Net income | — | | | 36 | | | 36 | | | |
| Common stock dividends | — | | | (73) | | | (73) | | | |
| Contributions from parent | 257 | | | — | | | 257 | | | |
| Balance, September 30, 2021 | $ | 2,575 | | | $ | 1,950 | | | $ | 4,525 | | | |
| | | Nine Months Ended September 30, 2020 | | |
| (In millions) | Common
Stock | | Retained
Earnings | | Total
Shareholder's
Equity | | |
| Balance, December 31, 2019 | $ | 1,907 | | | $ | 1,776 | | | $ | 3,683 | | | |
| Net income | — | | | 181 | | | 181 | | | |
| Common stock dividends | — | | | (62) | | | (62) | | | |
| Balance, March 31, 2020 | $ | 1,907 | | | $ | 1,895 | | | $ | 3,802 | | | |
| Net income | — | | | 39 | | | 39 | | | |
| Common stock dividends | — | | | (62) | | | (62) | | | |
| Contributions from parent | 26 | | | — | | | 26 | | | |
| Balance, June 30, 2020 | $ | 1,933 | | | $ | 1,872 | | | $ | 3,805 | | | |
| Net income | — | | | 53 | | | 53 | | | |
| Common stock dividends | — | | | (62) | | | (62) | | | |
| Contributions from parent | 258 | | | — | | | 258 | | | |
| Balance, September 30, 2020 | $ | 2,191 | | | $ | 1,863 | | | $ | 4,054 | | | |
|
See the Combined Notes to Consolidated Financial Statements
3629
PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
| | | Three Months Ended
September 30, | | Nine Months Ended
September 30, | | Three Months Ended
June 30, | | Six Months Ended
June 30, |
| (In millions) | (In millions) | 2021 | | 2020 | | 2021 | | 2020 | (In millions) | 2022 | | 2021 | | 2022 | | 2021 |
| Operating revenues | Operating revenues | | | | | | | | Operating revenues | | | | | | | |
| Electric operating revenues | Electric operating revenues | $ | 1,438 | | | $ | 1,308 | | | $ | 3,632 | | | $ | 3,440 | | Electric operating revenues | $ | 1,199 | | | $ | 1,071 | | | $ | 2,522 | | | $ | 2,195 | |
| Natural gas operating revenues | Natural gas operating revenues | 23 | | | 23 | | | 118 | | | 116 | | Natural gas operating revenues | 37 | | | 24 | | | 120 | | | 94 | |
| Revenues from alternative revenue programs | Revenues from alternative revenue programs | 6 | | | 31 | | | 94 | | | (15) | | Revenues from alternative revenue programs | (17) | | | 41 | | | (22) | | | 88 | |
| Operating revenues from affiliates | Operating revenues from affiliates | 3 | | | 6 | | | 10 | | | 13 | | Operating revenues from affiliates | 2 | | | 4 | | | 6 | | | 7 | |
| Total operating revenues | Total operating revenues | 1,470 | | | 1,368 | | | 3,854 | | | 3,554 | | Total operating revenues | 1,221 | | | 1,140 | | | 2,626 | | | 2,384 | |
| Operating expenses | Operating expenses | | | | | | | | Operating expenses | | | | | | | |
| Purchased power | Purchased power | 431 | | | 393 | | | 1,087 | | | 979 | | Purchased power | 401 | | | 308 | | | 888 | | | 656 | |
| Purchased fuel | Purchased fuel | 9 | | | 7 | | | 50 | | | 49 | | Purchased fuel | 19 | | | 9 | | | 61 | | | 41 | |
| Purchased power from affiliates | Purchased power from affiliates | 100 | | | 106 | | | 277 | | | 288 | | Purchased power from affiliates | — | | | 79 | | | 50 | | | 177 | |
| Operating and maintenance | Operating and maintenance | 235 | | | 237 | | | 668 | | | 702 | | Operating and maintenance | 245 | | | 217 | | | 493 | | | 434 | |
| Operating and maintenance from affiliates | Operating and maintenance from affiliates | 43 | | | 38 | | | 122 | | | 111 | | Operating and maintenance from affiliates | 47 | | | 39 | | | 98 | | | 79 | |
| Depreciation and amortization | Depreciation and amortization | 210 | | | 200 | | | 614 | | | 585 | | Depreciation and amortization | 240 | | | 194 | | | 459 | | | 404 | |
| Taxes other than income taxes | Taxes other than income taxes | 127 | | | 121 | | | 349 | | | 343 | | Taxes other than income taxes | 114 | | | 109 | | | 233 | | | 222 | |
| Total operating expenses | Total operating expenses | 1,155 | | | 1,102 | | | 3,167 | | | 3,057 | | Total operating expenses | 1,066 | | | 955 | | | 2,282 | | | 2,013 | |
| | Gain on sales of assets | — | | | — | | | — | | | 2 | | |
| | Operating income | Operating income | 315 | | | 266 | | | 687 | | | 499 | | Operating income | 155 | | | 185 | | | 344 | | | 371 | |
| Other income and (deductions) | Other income and (deductions) | | | | | | | | Other income and (deductions) | | | | | | | |
| Interest expense, net | Interest expense, net | (67) | | | (67) | | | (201) | | | (201) | | Interest expense, net | (73) | | | (67) | | | (143) | | | (134) | |
| | Other, net | Other, net | 16 | | | 16 | | | 52 | | | 42 | | Other, net | 19 | | | 20 | | | 37 | | | 36 | |
| Total other income and (deductions) | Total other income and (deductions) | (51) | | | (51) | | | (149) | | | (159) | | Total other income and (deductions) | (54) | | | (47) | | | (106) | | | (98) | |
| Income before income taxes | Income before income taxes | 264 | | | 215 | | | 538 | | | 340 | | Income before income taxes | 101 | | | 138 | | | 238 | | | 273 | |
| Income taxes | Income taxes | (2) | | | (1) | | | 3 | | | (77) | | Income taxes | 1 | | | (3) | | | 8 | | | 5 | |
| Equity in earnings of unconsolidated affiliate | Equity in earnings of unconsolidated affiliate | — | | | — | | | — | | | 1 | | Equity in earnings of unconsolidated affiliate | — | | | — | | | — | | | 1 | |
| Net income | Net income | $ | 266 | | | $ | 216 | | | $ | 535 | | | $ | 418 | | Net income | $ | 100 | | | $ | 141 | | | $ | 230 | | | $ | 269 | |
| | Comprehensive income | Comprehensive income | $ | 266 | | | $ | 216 | | | $ | 535 | | | $ | 418 | | Comprehensive income | $ | 100 | | | $ | 141 | | | $ | 230 | | | $ | 269 | |
See the Combined Notes to Consolidated Financial Statements
3730
PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
| | | Nine Months Ended
September 30, | | Six Months Ended
June 30, |
| (In millions) | (In millions) | 2021 | | 2020 | (In millions) | 2022 | | 2021 |
| Cash flows from operating activities | Cash flows from operating activities | | | | Cash flows from operating activities | | | |
| Net income | Net income | $ | 535 | | | $ | 418 | | Net income | $ | 230 | | | $ | 269 | |
| | Adjustments to reconcile net income to net cash flows from operating activities: | Adjustments to reconcile net income to net cash flows from operating activities: | | Adjustments to reconcile net income to net cash flows from operating activities: | |
| Depreciation and amortization | Depreciation and amortization | 614 | | | 585 | | Depreciation and amortization | 459 | | | 404 | |
| | Deferred income taxes and amortization of investment tax credits | Deferred income taxes and amortization of investment tax credits | — | | | (99) | | Deferred income taxes and amortization of investment tax credits | (7) | | | 10 | |
| | Other non-cash operating activities | Other non-cash operating activities | (35) | | | 115 | | Other non-cash operating activities | 76 | | | (50) | |
| Changes in assets and liabilities: | Changes in assets and liabilities: | | Changes in assets and liabilities: | |
| Accounts receivable | Accounts receivable | (112) | | | (121) | | Accounts receivable | (92) | | | (30) | |
| Receivables from and payables to affiliates, net | Receivables from and payables to affiliates, net | (19) | | | (26) | | Receivables from and payables to affiliates, net | (53) | | | (22) | |
| Inventories | Inventories | (13) | | | (2) | | Inventories | (7) | | | 3 | |
| Accounts payable and accrued expenses | Accounts payable and accrued expenses | 19 | | | 57 | | Accounts payable and accrued expenses | 10 | | | (35) | |
| | Collateral received, net | | Collateral received, net | 403 | | | — | |
| Income taxes | Income taxes | 17 | | | (14) | | Income taxes | (2) | | | (1) | |
| Regulatory assets and liabilities, net | | Regulatory assets and liabilities, net | (71) | | | (33) | |
| Pension and non-pension postretirement benefit contributions | Pension and non-pension postretirement benefit contributions | (43) | | | (35) | | Pension and non-pension postretirement benefit contributions | (70) | | | (40) | |
| Other assets and liabilities | Other assets and liabilities | (120) | | | (61) | | Other assets and liabilities | (86) | | | (98) | |
| Net cash flows provided by operating activities | Net cash flows provided by operating activities | 843 | | | 817 | | Net cash flows provided by operating activities | 790 | | | 377 | |
| Cash flows from investing activities | Cash flows from investing activities | | | | Cash flows from investing activities | | | |
| Capital expenditures | Capital expenditures | (1,299) | | | (1,072) | | Capital expenditures | (776) | | | (889) | |
| | Other investing activities | Other investing activities | (1) | | | 3 | | Other investing activities | 3 | | | (2) | |
| Net cash flows used in investing activities | Net cash flows used in investing activities | (1,300) | | | (1,069) | | Net cash flows used in investing activities | (773) | | | (891) | |
| Cash flows from financing activities | Cash flows from financing activities | | | | Cash flows from financing activities | | | |
| Changes in short-term borrowings | Changes in short-term borrowings | (81) | | | (208) | | Changes in short-term borrowings | (425) | | | (36) | |
| | Issuance of long-term debt | Issuance of long-term debt | 750 | | | 601 | | Issuance of long-term debt | 700 | | | 625 | |
| Retirement of long-term debt | Retirement of long-term debt | (255) | | | (119) | | Retirement of long-term debt | (200) | | | (249) | |
| Changes in Exelon intercompany money pool | Changes in Exelon intercompany money pool | (5) | | | 9 | | Changes in Exelon intercompany money pool | 17 | | | (12) | |
| | Distributions to member | Distributions to member | (605) | | | (451) | | Distributions to member | (395) | | | (414) | |
| Contributions from member | Contributions from member | 667 | | | 493 | | Contributions from member | 704 | | | 560 | |
| | Other financing activities | Other financing activities | (12) | | | (10) | | Other financing activities | (12) | | | (8) | |
| Net cash flows provided by financing activities | Net cash flows provided by financing activities | 459 | | | 315 | | Net cash flows provided by financing activities | 389 | | | 466 | |
| Increase in cash, restricted cash, and cash equivalents | 2 | | | 63 | | |
| Increase (decrease) in cash, restricted cash, and cash equivalents | | Increase (decrease) in cash, restricted cash, and cash equivalents | 406 | | | (48) | |
| Cash, restricted cash, and cash equivalents at beginning of period | Cash, restricted cash, and cash equivalents at beginning of period | 160 | | | 181 | | Cash, restricted cash, and cash equivalents at beginning of period | 213 | | | 160 | |
| Cash, restricted cash, and cash equivalents at end of period | Cash, restricted cash, and cash equivalents at end of period | $ | 162 | | | $ | 244 | | Cash, restricted cash, and cash equivalents at end of period | $ | 619 | | | $ | 112 | |
| | Supplemental cash flow information | Supplemental cash flow information | | Supplemental cash flow information | |
| Decrease in capital expenditures not paid | Decrease in capital expenditures not paid | $ | (74) | | | $ | (5) | | Decrease in capital expenditures not paid | $ | (48) | | | $ | (41) | |
|
See the Combined Notes to Consolidated Financial Statements
3831
PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
| | (In millions) | (In millions) | September 30, 2021 | | December 31, 2020 | (In millions) | June 30, 2022 | | December 31, 2021 |
| ASSETS | ASSETS | | | | ASSETS | | | |
| Current assets | Current assets | | Current assets | |
| Cash and cash equivalents | Cash and cash equivalents | $ | 82 | | | $ | 111 | | Cash and cash equivalents | $ | 278 | | | $ | 136 | |
| Restricted cash and cash equivalents | Restricted cash and cash equivalents | 71 | | | 39 | | Restricted cash and cash equivalents | 341 | | | 77 | |
| Accounts receivable | Accounts receivable | | Accounts receivable | |
| Customer accounts receivable | Customer accounts receivable | 671 | | 611 | Customer accounts receivable | 676 | | 616 |
| Customer allowance for credit losses | Customer allowance for credit losses | (105) | | (86) | Customer allowance for credit losses | (109) | | (104) |
| Customer accounts receivable, net | Customer accounts receivable, net | 566 | | | 525 | | Customer accounts receivable, net | 567 | | | 512 | |
| Other accounts receivable | Other accounts receivable | 300 | | 260 | Other accounts receivable | 291 | | 283 |
| Other allowance for credit losses | Other allowance for credit losses | (40) | | (33) | Other allowance for credit losses | (42) | | (39) |
| Other accounts receivable, net | Other accounts receivable, net | 260 | | | 227 | | Other accounts receivable, net | 249 | | | 244 | |
| | Receivables from affiliates | Receivables from affiliates | 3 | | | 8 | | Receivables from affiliates | 1 | | | 2 | |
| | Inventories, net | Inventories, net | | Inventories, net | |
| Fossil fuel | Fossil fuel | 10 | | | 6 | | Fossil fuel | 10 | | | 11 | |
| Materials and supplies | Materials and supplies | 207 | | | 198 | | Materials and supplies | 217 | | | 209 | |
| | Regulatory assets | Regulatory assets | 434 | | | 440 | | Regulatory assets | 435 | | | 432 | |
| | Other | Other | 57 | | | 45 | | Other | 90 | | | 69 | |
| Total current assets | Total current assets | 1,690 | | | 1,599 | | Total current assets | 2,188 | | | 1,692 | |
| Property, plant, and equipment (net of accumulated depreciation and amortization of $1,995 and $1,811 as of September 30, 2021 and December 31, 2020, respectively) | 16,163 | | | 15,377 | | |
| Property, plant, and equipment (net of accumulated depreciation and amortization of $2,365 and $2,108 as of June 30, 2022 and December 31, 2021, respectively) | | Property, plant, and equipment (net of accumulated depreciation and amortization of $2,365 and $2,108 as of June 30, 2022 and December 31, 2021, respectively) | 16,915 | | | 16,498 | |
| Deferred debits and other assets | Deferred debits and other assets | | Deferred debits and other assets | |
| Regulatory assets | Regulatory assets | 1,848 | | | 1,933 | | Regulatory assets | 1,714 | | | 1,794 | |
| Goodwill | | Goodwill | 4,005 | | | 4,005 | |
| Investments | Investments | 146 | | | 140 | | Investments | 139 | | | 145 | |
| Goodwill | 4,005 | | | 4,005 | | |
| | Prepaid pension asset | Prepaid pension asset | 357 | | | 365 | | Prepaid pension asset | 380 | | | 344 | |
| | Deferred income taxes | Deferred income taxes | 10 | | | 10 | | Deferred income taxes | 6 | | | 8 | |
| Other | Other | 283 | | | 307 | | Other | 245 | | | 258 | |
| Total deferred debits and other assets | Total deferred debits and other assets | 6,649 | | | 6,760 | | Total deferred debits and other assets | 6,489 | | | 6,554 | |
Total assets(a) | Total assets(a) | $ | 24,502 | | | $ | 23,736 | | Total assets(a) | $ | 25,592 | | | $ | 24,744 | |
See the Combined Notes to Consolidated Financial Statements
3932
PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
| | | | | | | | | | | |
| (In millions) | September 30, 2021 | | December 31, 2020 |
| LIABILITIES AND MEMBER'S EQUITY | | | |
| Current liabilities | | | |
| Short-term borrowings | $ | 287 | | | $ | 368 | |
| Long-term debt due within one year | 405 | | | 347 | |
| Accounts payable | 479 | | | 539 | |
| Accrued expenses | 300 | | | 299 | |
| Payables to affiliates | 80 | | | 104 | |
| Borrowings from Exelon intercompany money pool | 16 | | | 21 | |
| | | |
| Customer deposits | 82 | | | 106 | |
| Regulatory liabilities | 122 | | | 137 | |
| Unamortized energy contract liabilities | 90 | | | 92 | |
| | | |
| Other | 154 | | | 141 | |
| Total current liabilities | 2,015 | | | 2,154 | |
| Long-term debt | 7,077 | | | 6,659 | |
| Deferred credits and other liabilities | | | |
| Deferred income taxes and unamortized investment tax credits | 2,635 | | | 2,439 | |
| Asset retirement obligations | 69 | | | 59 | |
| Non-pension postretirement benefit obligations | 71 | | | 86 | |
| Regulatory liabilities | 1,237 | | | 1,438 | |
| | | |
| | | |
| | | |
| | | |
| Unamortized energy contract liabilities | 168 | | | 235 | |
| Other | 589 | | | 622 | |
| Total deferred credits and other liabilities | 4,769 | | | 4,879 | |
Total liabilities(a) | 13,861 | | | 13,692 | |
| Commitments and contingencies | 0 | | 0 |
| | | |
| Member's equity | | | |
| Membership interest | 10,779 | | | 10,112 | |
| | | |
| Undistributed losses | (138) | | | (68) | |
| | | |
| Total member's equity | 10,641 | | | 10,044 | |
| Total liabilities and member's equity | $ | 24,502 | | | $ | 23,736 | |
__________
(a)PHI’s consolidated total assets include $18 million at both September 30, 2021 and December 31, 2020 of PHI's consolidated VIE that can only be used to settle the liabilities of the VIE. PHI’s consolidated total liabilities include $10 million and $26 million at September 30, 2021 and December 31, 2020, respectively, of PHI's consolidated VIE for which the VIE creditors do not have recourse to PHI. See Note 17 — Variable Interest Entities for additional information. | | | | | | | | | | | |
| (In millions) | June 30, 2022 | | December 31, 2021 |
| LIABILITIES AND MEMBER'S EQUITY | | | |
| Current liabilities | | | |
| Short-term borrowings | $ | 43 | | | $ | 468 | |
| Long-term debt due within one year | 200 | | | 399 | |
| Accounts payable | 574 | | | 578 | |
| Accrued expenses | 246 | | | 281 | |
| Payables to affiliates | 50 | | | 104 | |
| Borrowings from Exelon intercompany money pool | 24 | | | 7 | |
| | | |
| Customer deposits | 81 | | | 81 | |
| Regulatory liabilities | 71 | | | 68 | |
| Unamortized energy contract liabilities | 11 | | | 89 | |
| | | |
| PPA termination obligation | 87 | | | — | |
| Other | 580 | | | 171 | |
| Total current liabilities | 1,967 | | | 2,246 | |
| Long-term debt | 7,827 | | | 7,148 | |
| Deferred credits and other liabilities | | | |
| Deferred income taxes and unamortized investment tax credits | 2,752 | | | 2,675 | |
| Regulatory liabilities | 1,142 | | | 1,238 | |
| Asset retirement obligations | 70 | | | 70 | |
| Non-pension postretirement benefit obligations | 57 | | | 66 | |
| | | |
| | | |
| | | |
| | | |
| Unamortized energy contract liabilities | 38 | | | 146 | |
| Other | 615 | | | 570 | |
| Total deferred credits and other liabilities | 4,674 | | | 4,765 | |
| Total liabilities | 14,468 | | | 14,159 | |
| Commitments and contingencies | 0 | | 0 |
| | | |
| Member's equity | | | |
| Membership interest | 11,499 | | | 10,795 | |
| | | |
| Undistributed losses | (375) | | | (210) | |
| | | |
| Total member's equity | 11,124 | | | 10,585 | |
| Total liabilities and member's equity | $ | 25,592 | | | $ | 24,744 | |
See the Combined Notes to Consolidated Financial Statements
4033
PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER'S EQUITY
(Unaudited)
| | | Nine Months Ended September 30, 2021 | | Six Months Ended June 30, 2022 |
| (In millions) | (In millions) | Membership Interest | | Undistributed (Losses)/Earnings | | | Total Member's Equity | (In millions) | Membership Interest | | Undistributed (Losses)/Earnings | | | Total Member's Equity |
| Balance, December 31, 2020 | $ | 10,112 | | | $ | (68) | | | | $ | 10,044 | | |
| Balance, December 31, 2021 | | Balance, December 31, 2021 | $ | 10,795 | | | $ | (210) | | | | $ | 10,585 | |
| Net income | Net income | — | | | 128 | | | | 128 | | Net income | — | | | 130 | | | | 130 | |
| Distributions to member | Distributions to member | — | | | (81) | | | | (81) | | Distributions to member | — | | | (102) | | | | (102) | |
| Contributions from member | Contributions from member | 560 | | | — | | | | 560 | | Contributions from member | 704 | | | — | | | | 704 | |
| Balance, March 31, 2021 | $ | 10,672 | | | $ | (21) | | | | $ | 10,651 | | |
| Balance, March 31, 2022 | | Balance, March 31, 2022 | $ | 11,499 | | | $ | (182) | | | | $ | 11,317 | |
| Net income | Net income | — | | | 141 | | | | 141 | | Net income | — | | | 100 | | | | 100 | |
| Distributions to member | Distributions to member | — | | | (333) | | | | (333) | | Distributions to member | — | | | (293) | | | | (293) | |
| | Balance, June 30, 2021 | $ | 10,672 | | | $ | (213) | | | | $ | 10,459 | | |
| Net income | — | | | 266 | | | | 266 | | |
| Distributions to member | — | | | (191) | | | | (191) | | |
| Contributions from member | 107 | | | — | | | | 107 | | |
| Balance, June 30, 2022 | | Balance, June 30, 2022 | $ | 11,499 | | | $ | (375) | | | | $ | 11,124 | |
| | Balance, September 30, 2021 | $ | 10,779 | | | $ | (138) | | | | $ | 10,641 | | |
|
| | | Nine Months Ended September 30, 2020 | | Six Months Ended June 30, 2021 |
| (In millions) | (In millions) | Membership Interest | | Undistributed (Losses)/Earnings | | | Total Member's Equity | (In millions) | Membership Interest | | Undistributed (Losses)/Earnings | | | Total Member's Equity |
| Balance, December 31, 2019 | $ | 9,618 | | | $ | (10) | | | | $ | 9,608 | | |
| Balance, December 31, 2020 | | Balance, December 31, 2020 | $ | 10,112 | | | $ | (68) | | | | $ | 10,044 | |
| Net income | Net income | — | | | 108 | | | | 108 | | Net income | — | | | 128 | | | | 128 | |
| Distributions to member | Distributions to member | — | | | (134) | | | | (134) | | Distributions to member | — | | | (81) | | | | (81) | |
| Contributions from member | Contributions from member | 144 | | | — | | | | 144 | | Contributions from member | 560 | | | — | | | | 560 | |
| Balance, March 31, 2020 | $ | 9,762 | | | $ | (36) | | | | $ | 9,726 | | |
| Balance, March 31, 2021 | | Balance, March 31, 2021 | $ | 10,672 | | | $ | (21) | | | | $ | 10,651 | |
| Net income | Net income | — | | | 94 | | | | 94 | | Net income | — | | | 141 | | | | 141 | |
| Distributions to member | Distributions to member | — | | | (134) | | | | (134) | | Distributions to member | — | | | (333) | | | | (333) | |
| Contributions from member | 215 | | | — | | | | 215 | | |
| Balance, June 30, 2020 | $ | 9,977 | | | $ | (76) | | | | $ | 9,901 | | |
| Net income | — | | | 216 | | | | 216 | | |
| Distributions to member | — | | | (183) | | | | (183) | | |
| Contribution from member | 135 | | | — | | | | 135 | | |
| Balance, September 30, 2020 | $ | 10,112 | | | $ | (43) | | | | $ | 10,069 | | |
| | Balance, June 30, 2021 | | Balance, June 30, 2021 | $ | 10,672 | | | $ | (213) | | | | $ | 10,459 | |
|
See the Combined Notes to Consolidated Financial Statements
4134
POTOMAC ELECTRIC POWER COMPANY
STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
| | | Three Months Ended
September 30, | | Nine Months Ended
September 30, | | | Three Months Ended
June 30, | | Six Months Ended
June 30, | |
| (In millions) | (In millions) | 2021 | | 2020 | | 2021 | | 2020 | | (In millions) | 2022 | | 2021 | | 2022 | | 2021 | |
| Operating revenues | Operating revenues | | | | | | | | | Operating revenues | | | | | | | | |
| Electric operating revenues | Electric operating revenues | $ | 649 | | | $ | 590 | | | $ | 1,678 | | | $ | 1,624 | | | Electric operating revenues | $ | 580 | | | $ | 503 | | | $ | 1,200 | | | $ | 1,027 | | |
| Revenues from alternative revenue programs | Revenues from alternative revenue programs | 9 | | | 18 | | | 54 | | | 20 | | | Revenues from alternative revenue programs | (1) | | | 19 | | | (7) | | | 46 | | |
| Operating revenues from affiliates | Operating revenues from affiliates | 2 | | | 3 | | | 4 | | | 6 | | | Operating revenues from affiliates | 2 | | | 1 | | | 2 | | | 3 | | |
| Total operating revenues | Total operating revenues | 660 | | | 611 | | | 1,736 | | | 1,650 | | | Total operating revenues | 581 | | | 523 | | | 1,195 | | | 1,076 | | |
| Operating expenses | Operating expenses | | | | | | | | | Operating expenses | | | | | | | | |
| Purchased power | Purchased power | 103 | | | 83 | | | 271 | | | 248 | | | Purchased power | 162 | | | 76 | | | 336 | | | 168 | | |
| Purchased power from affiliate | Purchased power from affiliate | 69 | | | 80 | | | 200 | | | 219 | | | Purchased power from affiliate | — | | | 57 | | | 39 | | | 130 | | |
| Operating and maintenance | Operating and maintenance | 68 | | | 57 | | | 186 | | | 184 | | | Operating and maintenance | 72 | | | 62 | | | 145 | | | 118 | | |
| Operating and maintenance from affiliates | Operating and maintenance from affiliates | 52 | | | 49 | | | 155 | | | 152 | | | Operating and maintenance from affiliates | 56 | | | 51 | | | 115 | | | 103 | | |
| Depreciation and amortization | Depreciation and amortization | 104 | | | 96 | | | 302 | | | 282 | | | Depreciation and amortization | 105 | | | 96 | | | 213 | | | 199 | | |
| Taxes other than income taxes | Taxes other than income taxes | 105 | | | 100 | | | 282 | | | 279 | | | Taxes other than income taxes | 92 | | | 87 | | | 186 | | | 177 | | |
| Total operating expenses | Total operating expenses | 501 | | | 465 | | | 1,396 | | | 1,364 | | | Total operating expenses | 487 | | | 429 | | | 1,034 | | | 895 | | |
| | Operating income | Operating income | 159 | | | 146 | | | 340 | | | 286 | | | Operating income | 94 | | | 94 | | | 161 | | | 181 | | |
| Other income and (deductions) | Other income and (deductions) | | | | | | | | | Other income and (deductions) | | | | | | | | |
| Interest expense, net | Interest expense, net | (35) | | | (35) | | | (104) | | | (103) | | | Interest expense, net | (38) | | | (35) | | | (74) | | | (69) | | |
| | Other, net | Other, net | 12 | | | 10 | | | 37 | | | 28 | | | Other, net | 13 | | | 13 | | | 26 | | | 25 | | |
| Total other income and (deductions) | Total other income and (deductions) | (23) | | | (25) | | | (67) | | | (75) | | | Total other income and (deductions) | (25) | | | (22) | | | (48) | | | (44) | | |
| Income before income taxes | Income before income taxes | 136 | | | 121 | | | 273 | | | 211 | | | Income before income taxes | 69 | | | 72 | | | 113 | | | 137 | | |
| Income taxes | Income taxes | 6 | | | 3 | | | 9 | | | (16) | | | Income taxes | (1) | | | (3) | | | (3) | | | 3 | | |
| | Net income | Net income | $ | 130 | | | $ | 118 | | | $ | 264 | | | $ | 227 | | | Net income | $ | 70 | | | $ | 75 | | | $ | 116 | | | $ | 134 | | |
| | Comprehensive income | Comprehensive income | $ | 130 | | | $ | 118 | | | $ | 264 | | | $ | 227 | | | Comprehensive income | $ | 70 | | | $ | 75 | | | $ | 116 | | | $ | 134 | | |
See the Combined Notes to Consolidated Financial Statements
4235
POTOMAC ELECTRIC POWER COMPANY
STATEMENTS OF CASH FLOWS
(Unaudited)
| | | Nine Months Ended
September 30, | | Six Months Ended
June 30, |
| (In millions) | (In millions) | 2021 | | 2020 | (In millions) | 2022 | | 2021 |
| Cash flows from operating activities | Cash flows from operating activities | | | | Cash flows from operating activities | | | |
| Net income | Net income | $ | 264 | | | $ | 227 | | Net income | $ | 116 | | | $ | 134 | |
| Adjustments to reconcile net income to net cash flows provided by operating activities: | Adjustments to reconcile net income to net cash flows provided by operating activities: | | Adjustments to reconcile net income to net cash flows provided by operating activities: | |
| Depreciation and amortization | Depreciation and amortization | 302 | | | 282 | | Depreciation and amortization | 213 | | | 199 | |
| | Deferred income taxes and amortization of investment tax credits | Deferred income taxes and amortization of investment tax credits | 12 | | | (36) | | Deferred income taxes and amortization of investment tax credits | (7) | | | 10 | |
| | Other non-cash operating activities | Other non-cash operating activities | (54) | | | 6 | | Other non-cash operating activities | 17 | | | (43) | |
| Changes in assets and liabilities: | Changes in assets and liabilities: | | Changes in assets and liabilities: | |
| Accounts receivable | Accounts receivable | (57) | | | (61) | | Accounts receivable | (62) | | | (23) | |
| Receivables from and payables to affiliates, net | Receivables from and payables to affiliates, net | (2) | | | (23) | | Receivables from and payables to affiliates, net | (39) | | | (11) | |
| Inventories | Inventories | (6) | | | 2 | | Inventories | (6) | | | 1 | |
| Accounts payable and accrued expenses | Accounts payable and accrued expenses | 14 | | | 36 | | Accounts payable and accrued expenses | 6 | | | (26) | |
| | Collateral received, net | | Collateral received, net | 85 | | | — | |
| Income taxes | Income taxes | (10) | | | (11) | | Income taxes | (24) | | | (20) | |
| Regulatory assets and liabilities, net | | Regulatory assets and liabilities, net | (36) | | | (38) | |
| Pension and non-pension postretirement benefit contributions | Pension and non-pension postretirement benefit contributions | (9) | | | (8) | | Pension and non-pension postretirement benefit contributions | (7) | | | (7) | |
| Other assets and liabilities | Other assets and liabilities | (114) | | | 15 | | Other assets and liabilities | (15) | | | (41) | |
| Net cash flows provided by operating activities | Net cash flows provided by operating activities | 340 | | | 429 | | Net cash flows provided by operating activities | 241 | | | 135 | |
| Cash flows from investing activities | Cash flows from investing activities | | | | Cash flows from investing activities | | | |
| Capital expenditures | Capital expenditures | (641) | | | (512) | | Capital expenditures | (402) | | | (439) | |
| | Changes in PHI intercompany money pool | — | | | (117) | | |
| | Other investing activities | Other investing activities | (2) | | | (3) | | Other investing activities | 2 | | | (2) | |
| Net cash flows used in investing activities | Net cash flows used in investing activities | (643) | | | (632) | | Net cash flows used in investing activities | (400) | | | (441) | |
| Cash flows from financing activities | Cash flows from financing activities | | | | Cash flows from financing activities | | | |
| Changes in short-term borrowings | Changes in short-term borrowings | 5 | | | (82) | | Changes in short-term borrowings | (132) | | | 119 | |
| Issuance of long-term debt | Issuance of long-term debt | 275 | | | 300 | | Issuance of long-term debt | 400 | | | 150 | |
| Retirement of long-term debt | Retirement of long-term debt | (1) | | | (2) | | Retirement of long-term debt | (200) | | | — | |
| | Changes in PHI intercompany money pool | | Changes in PHI intercompany money pool | 73 | | | 9 | |
| Dividends paid on common stock | Dividends paid on common stock | (221) | | | (174) | | Dividends paid on common stock | (300) | | | (123) | |
| Contributions from parent | Contributions from parent | 244 | | | 262 | | Contributions from parent | 387 | | | 138 | |
| | Other financing activities | Other financing activities | (4) | | | (6) | | Other financing activities | (6) | | | (2) | |
| Net cash flows provided by financing activities | Net cash flows provided by financing activities | 298 | | | 298 | | Net cash flows provided by financing activities | 222 | | | 291 | |
| (Decrease) increase in cash, restricted cash, and cash equivalents | (5) | | | 95 | | |
| Increase (decrease) in cash, restricted cash, and cash equivalents | | Increase (decrease) in cash, restricted cash, and cash equivalents | 63 | | | (15) | |
| Cash, restricted cash, and cash equivalents at beginning of period | Cash, restricted cash, and cash equivalents at beginning of period | 65 | | | 63 | | Cash, restricted cash, and cash equivalents at beginning of period | 68 | | | 65 | |
| Cash, restricted cash, and cash equivalents at end of period | Cash, restricted cash, and cash equivalents at end of period | $ | 60 | | | $ | 158 | | Cash, restricted cash, and cash equivalents at end of period | $ | 131 | | | $ | 50 | |
| | Supplemental cash flow information | Supplemental cash flow information | | Supplemental cash flow information | |
| Decrease in capital expenditures not paid | Decrease in capital expenditures not paid | $ | (16) | | | $ | (23) | | Decrease in capital expenditures not paid | $ | (24) | | | $ | (15) | |
|
See the Combined Notes to Consolidated Financial Statements
4336
POTOMAC ELECTRIC POWER COMPANY
BALANCE SHEETS
(Unaudited)
| | (In millions) | (In millions) | September 30, 2021 | | December 31, 2020 | (In millions) | June 30, 2022 | | December 31, 2021 |
| ASSETS | ASSETS | | | | ASSETS | | | |
| Current assets | Current assets | | Current assets | |
| Cash and cash equivalents | Cash and cash equivalents | $ | 19 | | | $ | 30 | | Cash and cash equivalents | $ | 14 | | | $ | 34 | |
| Restricted cash and cash equivalents | Restricted cash and cash equivalents | 41 | | | 35 | | Restricted cash and cash equivalents | 117 | | | 34 | |
| Accounts receivable | Accounts receivable | | Accounts receivable | |
| Customer accounts receivable | Customer accounts receivable | 306 | | 279 | Customer accounts receivable | 328 | | 277 |
| Customer allowance for credit losses | Customer allowance for credit losses | (41) | | (32) | Customer allowance for credit losses | (42) | | (37) |
| Customer accounts receivable, net | Customer accounts receivable, net | 265 | | | 247 | | Customer accounts receivable, net | 286 | | | 240 | |
| Other accounts receivable | Other accounts receivable | 166 | | 131 | Other accounts receivable | 165 | | 160 |
| Other allowance for credit losses | Other allowance for credit losses | (17) | | (13) | Other allowance for credit losses | (20) | | (16) |
| Other accounts receivable, net | Other accounts receivable, net | 149 | | | 118 | | Other accounts receivable, net | 145 | | | 144 | |
| | Receivables from affiliates | Receivables from affiliates | — | | | 2 | | Receivables from affiliates | 9 | | | — | |
| | Inventories, net | Inventories, net | 117 | | | 111 | | Inventories, net | 125 | | | 119 | |
| | Regulatory assets | Regulatory assets | 215 | | | 214 | | Regulatory assets | 220 | | | 213 | |
| | Other | Other | 12 | | | 13 | | Other | 12 | | | 25 | |
| Total current assets | Total current assets | 818 | | | 770 | | Total current assets | 928 | | | 809 | |
| Property, plant, and equipment (net of accumulated depreciation and amortization of $3,831 and $3,697 as of September 30, 2021 and December 31, 2020, respectively) | 7,919 | | | 7,456 | | |
| Property, plant, and equipment (net of accumulated depreciation and amortization of $3,970 and $3,875 as of June 30, 2022 and December 31, 2021, respectively) | | Property, plant, and equipment (net of accumulated depreciation and amortization of $3,970 and $3,875 as of June 30, 2022 and December 31, 2021, respectively) | 8,365 | | | 8,104 | |
| Deferred debits and other assets | Deferred debits and other assets | | Deferred debits and other assets | |
| Regulatory assets | Regulatory assets | 548 | | | 570 | | Regulatory assets | 478 | | | 532 | |
| Investments | Investments | 120 | | | 115 | | Investments | 118 | | | 120 | |
| | Prepaid pension asset | Prepaid pension asset | 280 | | | 284 | | Prepaid pension asset | 277 | | | 279 | |
| | Other | Other | 63 | | | 69 | | Other | 60 | | | 59 | |
| Total deferred debits and other assets | Total deferred debits and other assets | 1,011 | | | 1,038 | | Total deferred debits and other assets | 933 | | | 990 | |
| Total assets | Total assets | $ | 9,748 | | | $ | 9,264 | | Total assets | $ | 10,226 | | | $ | 9,903 | |
See the Combined Notes to Consolidated Financial Statements
4437
POTOMAC ELECTRIC POWER COMPANY
BALANCE SHEETS
(Unaudited)
| | (In millions) | (In millions) | September 30, 2021 | | December 31, 2020 | (In millions) | June 30, 2022 | | December 31, 2021 |
| LIABILITIES AND SHAREHOLDER'S EQUITY | LIABILITIES AND SHAREHOLDER'S EQUITY | | | | LIABILITIES AND SHAREHOLDER'S EQUITY | | | |
| Current liabilities | Current liabilities | | Current liabilities | |
| Short-term borrowings | Short-term borrowings | $ | 40 | | | $ | 35 | | Short-term borrowings | $ | 43 | | | $ | 175 | |
| Long-term debt due within one year | Long-term debt due within one year | 313 | | | 3 | | Long-term debt due within one year | 114 | | | 313 | |
| Accounts payable | Accounts payable | 218 | | | 226 | | Accounts payable | 269 | | | 272 | |
| Accrued expenses | Accrued expenses | 149 | | | 164 | | Accrued expenses | 124 | | | 160 | |
| Payables to affiliates | Payables to affiliates | 51 | | | 55 | | Payables to affiliates | 29 | | | 59 | |
| | Borrowings from PHI intercompany money pool | | Borrowings from PHI intercompany money pool | 73 | | | — | |
| Customer deposits | Customer deposits | 37 | | | 51 | | Customer deposits | 36 | | | 35 | |
| Regulatory liabilities | Regulatory liabilities | 27 | | | 46 | | Regulatory liabilities | 12 | | | 14 | |
| Merger related obligation | Merger related obligation | 29 | | | 33 | | Merger related obligation | 25 | | | 27 | |
| Current portion of DC PLUG obligation | 30 | | | 30 | | |
| | Other | Other | 22 | | | 31 | | Other | 149 | | | 55 | |
| Total current liabilities | Total current liabilities | 916 | | | 674 | | Total current liabilities | 874 | | | 1,110 | |
| Long-term debt | Long-term debt | 3,128 | | | 3,162 | | Long-term debt | 3,528 | | | 3,132 | |
| | Deferred credits and other liabilities | Deferred credits and other liabilities | | Deferred credits and other liabilities | |
| Deferred income taxes and unamortized investment tax credits | Deferred income taxes and unamortized investment tax credits | 1,289 | | | 1,189 | | Deferred income taxes and unamortized investment tax credits | 1,314 | | | 1,275 | |
| Regulatory liabilities | | Regulatory liabilities | 507 | | | 549 | |
| Asset retirement obligations | Asset retirement obligations | 45 | | | 39 | | Asset retirement obligations | 45 | | | 45 | |
| | Non-pension postretirement benefit obligations | Non-pension postretirement benefit obligations | 5 | | | 13 | | Non-pension postretirement benefit obligations | — | | | 3 | |
| | Regulatory liabilities | 555 | | | 644 | | |
| Other | Other | 320 | | | 340 | | Other | 280 | | | 314 | |
| Total deferred credits and other liabilities | Total deferred credits and other liabilities | 2,214 | | | 2,225 | | Total deferred credits and other liabilities | 2,146 | | | 2,186 | |
| Total liabilities | Total liabilities | 6,258 | | | 6,061 | | Total liabilities | 6,548 | | | 6,428 | |
| Commitments and contingencies | Commitments and contingencies | 0 | | 0 | Commitments and contingencies | 0 | | 0 |
| Shareholder's equity | Shareholder's equity | | Shareholder's equity | |
| | Common stock | Common stock | 2,302 | | | 2,058 | | Common stock | 2,689 | | | 2,302 | |
| | Retained earnings | Retained earnings | 1,188 | | | 1,145 | | Retained earnings | 989 | | | 1,173 | |
| | Total shareholder's equity | Total shareholder's equity | 3,490 | | | 3,203 | | Total shareholder's equity | 3,678 | | | 3,475 | |
| Total liabilities and shareholder's equity | Total liabilities and shareholder's equity | $ | 9,748 | | | $ | 9,264 | | Total liabilities and shareholder's equity | $ | 10,226 | | | $ | 9,903 | |
See the Combined Notes to Consolidated Financial Statements
4538
POTOMAC ELECTRIC POWER COMPANY
STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY
(Unaudited)
| | | Nine Months Ended September 30, 2021 | | Six Months Ended June 30, 2022 |
| (In millions) | (In millions) | Common Stock | | | Retained Earnings | | Total Shareholder's Equity | (In millions) | Common Stock | | | Retained Earnings | | Total Shareholder's Equity |
| Balance, December 31, 2020 | $ | 2,058 | | | | $ | 1,145 | | | $ | 3,203 | | |
| Balance, December 31, 2021 | | Balance, December 31, 2021 | $ | 2,302 | | | | $ | 1,173 | | | $ | 3,475 | |
| Net income | Net income | — | | | | 59 | | | 59 | | Net income | — | | | | 46 | | | 46 | |
| Common stock dividends | Common stock dividends | — | | | | (28) | | | (28) | | Common stock dividends | — | | | | (42) | | | (42) | |
| Contributions from parent | Contributions from parent | 138 | | | | — | | | 138 | | Contributions from parent | 387 | | | | — | | | 387 | |
| Balance, March 31, 2021 | $ | 2,196 | | | | $ | 1,176 | | | $ | 3,372 | | |
| Balance, March 31, 2022 | | Balance, March 31, 2022 | $ | 2,689 | | | | $ | 1,177 | | | $ | 3,866 | |
| Net income | Net income | — | | | | 75 | | | 75 | | Net income | — | | | | 70 | | | 70 | |
| | Common stock dividends | Common stock dividends | — | | | | (95) | | | (95) | | Common stock dividends | — | | | | (258) | | | (258) | |
| | Balance, June 30, 2021 | $ | 2,196 | | | | $ | 1,156 | | | $ | 3,352 | | |
| Net income | — | | | | 130 | | | 130 | | |
| Balance, June 30, 2022 | | Balance, June 30, 2022 | $ | 2,689 | | | | $ | 989 | | | $ | 3,678 | |
| | Common stock dividends | — | | | | (98) | | | (98) | | |
| Contributions from parent | 106 | | | | — | | | 106 | | |
| Balance, September 30, 2021 | $ | 2,302 | | | | $ | 1,188 | | | $ | 3,490 | | |
|
| | | Nine Months Ended September 30, 2020 | | Six Months Ended June 30, 2021 |
| (In millions) | (In millions) | Common Stock | | | Retained Earnings | | Total Shareholder's Equity | (In millions) | Common Stock | | | Retained Earnings | | Total Shareholder's Equity |
| Balance, December 31, 2019 | $ | 1,796 | | | | $ | 1,111 | | | $ | 2,907 | | |
| Balance, December 31, 2020 | | Balance, December 31, 2020 | $ | 2,058 | | | | $ | 1,145 | | | $ | 3,203 | |
| Net income | Net income | — | | | | 52 | | | 52 | | Net income | — | | | | 59 | | | 59 | |
| Common stock dividends | Common stock dividends | — | | | | (28) | | | (28) | | Common stock dividends | — | | | | (28) | | | (28) | |
| Contributions from parent | Contributions from parent | 137 | | | | — | | | 137 | | Contributions from parent | 138 | | | | — | | | 138 | |
| Balance, March 31, 2020 | $ | 1,933 | | | | $ | 1,135 | | | $ | 3,068 | | |
| Balance, March 31, 2021 | | Balance, March 31, 2021 | $ | 2,196 | | | | $ | 1,176 | | | $ | 3,372�� | |
| Net income | Net income | — | | | | 57 | | | 57 | | Net income | — | | | | 75 | | | 75 | |
| | Common stock dividends | Common stock dividends | — | | | | (73) | | | (73) | | Common stock dividends | — | | | | (95) | | | (95) | |
| | Balance, June 30, 2020 | $ | 1,933 | | | | $ | 1,119 | | | $ | 3,052 | | |
| Net income | — | | | | 118 | | | 118 | | |
| Balance, June 30, 2021 | | Balance, June 30, 2021 | $ | 2,196 | | | | $ | 1,156 | | | $ | 3,352 | |
| | Common stock dividends | — | | | | (73) | | | (73) | | |
| Contributions from parent | 125 | | | | — | | | 125 | | |
| Balance, September 30, 2020 | $ | 2,058 | | | | $ | 1,164 | | | $ | 3,222 | | |
|
See the Combined Notes to Consolidated Financial Statements
4639
DELMARVA POWER & LIGHT COMPANY
STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
| | | Three Months Ended
September 30, | | Nine Months Ended
September 30, | | Three Months Ended
June 30, | | Six Months Ended
June 30, |
| (In millions) | (In millions) | 2021 | | 2020 | | 2021 | | 2020 | (In millions) | 2022 | | 2021 | | 2022 | | 2021 |
| Operating revenues | Operating revenues | | | | | | | | Operating revenues | | | | | | | |
| Electric operating revenues | Electric operating revenues | $ | 337 | | | $ | 303 | | | $ | 899 | | | $ | 846 | | Electric operating revenues | $ | 295 | | | $ | 262 | | | $ | 643 | | | $ | 562 | |
| Natural gas operating revenues | Natural gas operating revenues | 23 | | | 23 | | | 118 | | | 116 | | Natural gas operating revenues | 37 | | | 24 | | | 120 | | | 95 | |
| Revenues from alternative revenue programs | Revenues from alternative revenue programs | (2) | | | 8 | | | 17 | | | (15) | | Revenues from alternative revenue programs | (2) | | | 10 | | | (3) | | | 19 | |
| Operating revenues from affiliates | Operating revenues from affiliates | 2 | | | 3 | | | 6 | | | 7 | | Operating revenues from affiliates | 2 | | | 2 | | | 3 | | | 4 | |
| Total operating revenues | Total operating revenues | 360 | | | 337 | | | 1,040 | | | 954 | | Total operating revenues | 332 | | | 298 | | | 763 | | | 680 | |
| Operating expenses | Operating expenses | | | | | | | | Operating expenses | | | | | | | |
| Purchased power | Purchased power | 103 | | | 103 | | | 289 | | | 270 | | Purchased power | 116 | | | 82 | | | 253 | | | 185 | |
| Purchased fuel | Purchased fuel | 9 | | | 7 | | | 50 | | | 49 | | Purchased fuel | 19 | | | 9 | | | 61 | | | 41 | |
| Purchased power from affiliates | Purchased power from affiliates | 26 | | | 21 | | | 63 | | | 60 | | Purchased power from affiliates | — | | | 17 | | | 10 | | | 37 | |
| Operating and maintenance | Operating and maintenance | 47 | | | 64 | | | 132 | | | 160 | | Operating and maintenance | 45 | | | 41 | | | 97 | | | 85 | |
| Operating and maintenance from affiliates | Operating and maintenance from affiliates | 40 | | | 37 | | | 117 | | | 112 | | Operating and maintenance from affiliates | 43 | | | 39 | | | 84 | | | 79 | |
| Depreciation and amortization | Depreciation and amortization | 53 | | | 48 | | | 157 | | | 143 | | Depreciation and amortization | 56 | | | 51 | | | 113 | | | 104 | |
| Taxes other than income taxes | Taxes other than income taxes | 17 | | | 16 | | | 50 | | | 49 | | Taxes other than income taxes | 17 | | | 16 | | | 35 | | | 33 | |
| Total operating expenses | Total operating expenses | 295 | | | 296 | | | 858 | | | 843 | | Total operating expenses | 296 | | | 255 | | | 653 | | | 564 | |
| | Operating income | Operating income | 65 | | | 41 | | | 182 | | | 111 | | Operating income | 36 | | | 43 | | | 110 | | | 116 | |
| Other income and (deductions) | Other income and (deductions) | | | | | | | | Other income and (deductions) | | | | | | | |
| Interest expense, net | Interest expense, net | (15) | | | (15) | | | (47) | | | (47) | | Interest expense, net | (17) | | | (16) | | | (33) | | | (30) | |
| Other, net | Other, net | 3 | | | 2 | | | 9 | | | 7 | | Other, net | 4 | | | 4 | | | 6 | | | 6 | |
| Total other income and (deductions) | Total other income and (deductions) | (12) | | | (13) | | | (38) | | | (40) | | Total other income and (deductions) | (13) | | | (12) | | | (27) | | | (24) | |
| Income (loss) before income taxes | 53 | | | 28 | | | 144 | | | 71 | | |
| Income before income taxes | | Income before income taxes | 23 | | | 31 | | | 83 | | | 92 | |
| Income taxes | Income taxes | 3 | | | 1 | | | 9 | | | (20) | | Income taxes | 2 | | | 1 | | | 6 | | | 6 | |
| | Net income | Net income | $ | 50 | | | $ | 27 | | | $ | 135 | | | $ | 91 | | Net income | $ | 21 | | | $ | 30 | | | $ | 77 | | | $ | 86 | |
| Comprehensive income | Comprehensive income | $ | 50 | | | $ | 27 | | | $ | 135 | | | $ | 91 | | Comprehensive income | $ | 21 | | | $ | 30 | | | $ | 77 | | | $ | 86 | |
See the Combined Notes to Consolidated Financial Statements
4740
DELMARVA POWER & LIGHT COMPANY
STATEMENTS OF CASH FLOWS
(Unaudited)
| | | Nine Months Ended
September 30, | | Six Months Ended
June 30, |
| (In millions) | (In millions) | 2021 | | 2020 | (In millions) | 2022 | | 2021 |
| Cash flows from operating activities | Cash flows from operating activities | | | | Cash flows from operating activities | | | |
| Net income | Net income | $ | 135 | | | $ | 91 | | Net income | $ | 77 | | | $ | 86 | |
| Adjustments to reconcile net income to net cash flows provided by operating activities: | Adjustments to reconcile net income to net cash flows provided by operating activities: | | Adjustments to reconcile net income to net cash flows provided by operating activities: | |
| Depreciation and amortization | Depreciation and amortization | 157 | | | 143 | | Depreciation and amortization | 113 | | | 104 | |
| | Deferred income taxes and amortization of investment tax credits | Deferred income taxes and amortization of investment tax credits | 5 | | | (20) | | Deferred income taxes and amortization of investment tax credits | 3 | | | 4 | |
| | Other non-cash operating activities | Other non-cash operating activities | (2) | | | 47 | | Other non-cash operating activities | 13 | | | (12) | |
| Changes in assets and liabilities: | Changes in assets and liabilities: | | Changes in assets and liabilities: | |
| Accounts receivable | Accounts receivable | 26 | | | 3 | | Accounts receivable | (8) | | | 24 | |
| Receivables from and payables to affiliates, net | Receivables from and payables to affiliates, net | (12) | | | (5) | | Receivables from and payables to affiliates, net | (3) | | | (12) | |
| Inventories | Inventories | (5) | | | (3) | | Inventories | 1 | | | — | |
| Accounts payable and accrued expenses | Accounts payable and accrued expenses | 17 | | | 21 | | Accounts payable and accrued expenses | 12 | | | 7 | |
| | Collateral received, net | | Collateral received, net | 180 | | | — | |
| Income taxes | Income taxes | 19 | | | (12) | | Income taxes | 6 | | | 14 | |
| Regulatory assets and liabilities, net | | Regulatory assets and liabilities, net | (11) | | | (13) | |
| Pension and non-pension postretirement benefit contributions | Pension and non-pension postretirement benefit contributions | (1) | | | (1) | | Pension and non-pension postretirement benefit contributions | (1) | | | — | |
| Other assets and liabilities | Other assets and liabilities | (7) | | | (25) | | Other assets and liabilities | 1 | | | (9) | |
| Net cash flows provided by operating activities | Net cash flows provided by operating activities | 332 | | | 239 | | Net cash flows provided by operating activities | 383 | | | 193 | |
| Cash flows from investing activities | Cash flows from investing activities | | | | Cash flows from investing activities | | | |
| Capital expenditures | Capital expenditures | (320) | | | (278) | | Capital expenditures | (194) | | | (211) | |
| | Changes in PHI intercompany money pool | | Changes in PHI intercompany money pool | (73) | | | (9) | |
| Other investing activities | Other investing activities | 1 | | | (3) | | Other investing activities | 2 | | | 1 | |
| Net cash flows used in investing activities | Net cash flows used in investing activities | (319) | | | (281) | | Net cash flows used in investing activities | (265) | | | (219) | |
| Cash flows from financing activities | Cash flows from financing activities | | | | Cash flows from financing activities | | | |
| Changes in short-term borrowings | Changes in short-term borrowings | (124) | | | (56) | | Changes in short-term borrowings | (149) | | | (146) | |
| Issuance of long-term debt | Issuance of long-term debt | 125 | | | 178 | | Issuance of long-term debt | 125 | | | 125 | |
| Retirement of long-term debt | — | | | (79) | | |
| | | Dividends paid on common stock | Dividends paid on common stock | (106) | | | (99) | | Dividends paid on common stock | (56) | | | (63) | |
| Contributions from parent | Contributions from parent | 120 | | | 112 | | Contributions from parent | 144 | | | 120 | |
| Other financing activities | Other financing activities | (4) | | | (1) | | Other financing activities | (4) | | | (3) | |
| Net cash flows provided by financing activities | Net cash flows provided by financing activities | 11 | | | 55 | | Net cash flows provided by financing activities | 60 | | | 33 | |
| Increase in cash, restricted cash, and cash equivalents | Increase in cash, restricted cash, and cash equivalents | 24 | | | 13 | | Increase in cash, restricted cash, and cash equivalents | 178 | | | 7 | |
| Cash, restricted cash, and cash equivalents at beginning of period | Cash, restricted cash, and cash equivalents at beginning of period | 15 | | | 13 | | Cash, restricted cash, and cash equivalents at beginning of period | 71 | | | 15 | |
| Cash, restricted cash, and cash equivalents at end of period | Cash, restricted cash, and cash equivalents at end of period | $ | 39 | | | $ | 26 | | Cash, restricted cash, and cash equivalents at end of period | $ | 249 | | | $ | 22 | |
| | Supplemental cash flow information | Supplemental cash flow information | | Supplemental cash flow information | |
| (Decrease) increase in capital expenditures not paid | $ | (24) | | | $ | 8 | | |
| Decrease in capital expenditures not paid | | Decrease in capital expenditures not paid | $ | (5) | | | $ | (14) | |
|
See the Combined Notes to Consolidated Financial Statements
4841
DELMARVA POWER & LIGHT COMPANY
BALANCE SHEETS
(Unaudited)
| | (In millions) | (In millions) | September 30, 2021 | | December 31, 2020 | (In millions) | June 30, 2022 | | December 31, 2021 |
| ASSETS | ASSETS | | | | ASSETS | | | |
| Current assets | Current assets | | Current assets | |
| Cash and cash equivalents | Cash and cash equivalents | $ | 13 | | | $ | 15 | | Cash and cash equivalents | $ | 26 | | | $ | 28 | |
| Restricted cash and cash equivalents | Restricted cash and cash equivalents | 26 | | | — | | Restricted cash and cash equivalents | 223 | | | 43 | |
| Accounts receivable | Accounts receivable | | Accounts receivable | |
| Customer accounts receivable | Customer accounts receivable | 135 | | 176 | Customer accounts receivable | 154 | | 149 |
| Customer allowance for credit losses | Customer allowance for credit losses | (18) | | (22) | Customer allowance for credit losses | (22) | | (18) |
| Customer accounts receivable, net | Customer accounts receivable, net | 117 | | | 154 | | Customer accounts receivable, net | 132 | | | 131 | |
| Other accounts receivable | Other accounts receivable | 59 | | 68 | Other accounts receivable | 55 | | 58 |
| Other allowance for credit losses | Other allowance for credit losses | (8) | | (9) | Other allowance for credit losses | (8) | | (8) |
| Other accounts receivable, net | Other accounts receivable, net | 51 | | | 59 | | Other accounts receivable, net | 47 | | | 50 | |
| Receivables from affiliates | Receivables from affiliates | 1 | | | 1 | | Receivables from affiliates | — | | | 1 | |
| | Receivable from PHI intercompany pool | | Receivable from PHI intercompany pool | 73 | | | — | |
| Inventories, net | Inventories, net | | Inventories, net | |
| Fossil fuel | Fossil fuel | 10 | | | 6 | | Fossil fuel | 10 | | | 11 | |
| Materials and supplies | Materials and supplies | 52 | | | 51 | | Materials and supplies | 54 | | | 54 | |
| Prepaid utility taxes | Prepaid utility taxes | 16 | | | 11 | | Prepaid utility taxes | — | | | 20 | |
| | Regulatory assets | Regulatory assets | 72 | | | 58 | | Regulatory assets | 68 | | | 68 | |
| Renewable energy credits | 3 | | | 10 | | |
| | Other | Other | 4 | | | 3 | | Other | 29 | | | 16 | |
| Total current assets | Total current assets | 365 | | | 368 | | Total current assets | 662 | | | 422 | |
| Property, plant, and equipment (net of accumulated depreciation and amortization of $1,608 and $1,533 as of September 30, 2021 and December 31, 2020, respectively) | 4,485 | | | 4,314 | | |
| Property, plant, and equipment (net of accumulated depreciation and amortization of $1,704 and $1,635 as of June 30, 2022 and December 31, 2021, respectively) | | Property, plant, and equipment (net of accumulated depreciation and amortization of $1,704 and $1,635 as of June 30, 2022 and December 31, 2021, respectively) | 4,661 | | | 4,560 | |
| Deferred debits and other assets | Deferred debits and other assets | | Deferred debits and other assets | |
| Regulatory assets | Regulatory assets | 219 | | | 222 | | Regulatory assets | 204 | | | 212 | |
| | Goodwill | 8 | | | 8 | | |
| | Prepaid pension asset | Prepaid pension asset | 158 | | | 162 | | Prepaid pension asset | 156 | | | 157 | |
| Other | Other | 60 | | | 66 | | Other | 59 | | | 61 | |
| Total deferred debits and other assets | Total deferred debits and other assets | 445 | | | 458 | | Total deferred debits and other assets | 419 | | | 430 | |
| Total assets | Total assets | $ | 5,295 | | | $ | 5,140 | | Total assets | $ | 5,742 | | | $ | 5,412 | |
See the Combined Notes to Consolidated Financial Statements
4942
DELMARVA POWER & LIGHT COMPANY
BALANCE SHEETS
(Unaudited)
| | (In millions) | (In millions) | September 30, 2021 | | December 31, 2020 | (In millions) | June 30, 2022 | | December 31, 2021 |
| LIABILITIES AND SHAREHOLDER'S EQUITY | LIABILITIES AND SHAREHOLDER'S EQUITY | | | | LIABILITIES AND SHAREHOLDER'S EQUITY | | | |
| Current liabilities | Current liabilities | | Current liabilities | |
| Short-term borrowings | Short-term borrowings | $ | 22 | | | $ | 146 | | Short-term borrowings | $ | — | | | $ | 149 | |
| Long-term debt due within one year | Long-term debt due within one year | 83 | | | 82 | | Long-term debt due within one year | 84 | | | 83 | |
| Accounts payable | Accounts payable | 107 | | | 126 | | Accounts payable | 141 | | | 131 | |
| Accrued expenses | Accrued expenses | 61 | | | 46 | | Accrued expenses | 40 | | | 40 | |
| Payables to affiliates | Payables to affiliates | 24 | | | 36 | | Payables to affiliates | 29 | | | 33 | |
| | Customer deposits | Customer deposits | 27 | | | 32 | | Customer deposits | 27 | | | 28 | |
| Regulatory liabilities | Regulatory liabilities | 49 | | | 47 | | Regulatory liabilities | 31 | | | 25 | |
| Other | Other | 41 | | | 20 | | Other | 239 | | | 59 | |
| Total current liabilities | Total current liabilities | 414 | | | 535 | | Total current liabilities | 591 | | | 548 | |
| Long-term debt | Long-term debt | 1,725 | | | 1,595 | | Long-term debt | 1,854 | | | 1,727 | |
| Deferred credits and other liabilities | Deferred credits and other liabilities | | Deferred credits and other liabilities | |
| Deferred income taxes and unamortized investment tax credits | Deferred income taxes and unamortized investment tax credits | 761 | | | 715 | | Deferred income taxes and unamortized investment tax credits | 830 | | | 803 | |
| Regulatory liabilities | | Regulatory liabilities | 415 | | | 441 | |
| Asset retirement obligations | Asset retirement obligations | 16 | | | 14 | | Asset retirement obligations | 16 | | | 16 | |
| | Non-pension postretirement benefits obligations | Non-pension postretirement benefits obligations | 12 | | | 15 | | Non-pension postretirement benefits obligations | 10 | | | 11 | |
| Regulatory liabilities | 446 | | | 493 | | |
| Other | Other | 95 | | | 97 | | Other | 84 | | | 89 | |
| Total deferred credits and other liabilities | Total deferred credits and other liabilities | 1,330 | | | 1,334 | | Total deferred credits and other liabilities | 1,355 | | | 1,360 | |
| Total liabilities | Total liabilities | 3,469 | | | 3,464 | | Total liabilities | 3,800 | | | 3,635 | |
| Commitments and contingencies | Commitments and contingencies | 0 | | 0 | Commitments and contingencies | 0 | | 0 |
| Shareholder's equity | Shareholder's equity | | Shareholder's equity | |
| Common stock | Common stock | 1,209 | | | 1,089 | | Common stock | 1,353 | | | 1,209 | |
| | Retained earnings | Retained earnings | 617 | | | 587 | | Retained earnings | 589 | | | 568 | |
| Total shareholder's equity | Total shareholder's equity | 1,826 | | | 1,676 | | Total shareholder's equity | 1,942 | | | 1,777 | |
| Total liabilities and shareholder's equity | Total liabilities and shareholder's equity | $ | 5,295 | | | $ | 5,140 | | Total liabilities and shareholder's equity | $ | 5,742 | | | $ | 5,412 | |
See the Combined Notes to Consolidated Financial Statements
5043
DELMARVA POWER & LIGHT COMPANY
STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY
(Unaudited)
| | | Nine Months Ended September 30, 2021 | | Six Months Ended June 30, 2022 |
| (In millions) | (In millions) | Common Stock | | | Retained Earnings | | Total Shareholder's Equity | (In millions) | Common Stock | | | Retained Earnings | | Total Shareholder's Equity |
| Balance, December 31, 2020 | $ | 1,089 | | | | $ | 587 | | | $ | 1,676 | | |
| Balance, December 31, 2021 | | Balance, December 31, 2021 | $ | 1,209 | | | | $ | 568 | | | $ | 1,777 | |
| Net income | Net income | — | | | | 56 | | | 56 | | Net income | — | | | | 56 | | | 56 | |
| Common stock dividends | Common stock dividends | — | | | | (40) | | | (40) | | Common stock dividends | — | | | | (41) | | | (41) | |
| Contributions from parent | Contributions from parent | 120 | | | | — | | | 120 | | Contributions from parent | 144 | | | | — | | | 144 | |
| Balance, March 31, 2021 | $ | 1,209 | | | | $ | 603 | | | $ | 1,812 | | |
| Balance, March 31, 2022 | | Balance, March 31, 2022 | $ | 1,353 | | | | $ | 583 | | | $ | 1,936 | |
| Net income | Net income | — | | | | 30 | | | 30 | | Net income | — | | | | 21 | | | 21 | |
| Common stock dividends | Common stock dividends | — | | | | (23) | | | (23) | | Common stock dividends | — | | | | (15) | | | (15) | |
| | Balance, June 30, 2021 | $ | 1,209 | | | | $ | 610 | | | $ | 1,819 | | |
| Net income | — | | | | 50 | | | 50 | | |
| Common stock dividends | — | | | | (43) | | | (43) | | |
| | Balance, September 30, 2021 | $ | 1,209 | | | | $ | 617 | | | $ | 1,826 | | |
| Balance, June 30, 2022 | | Balance, June 30, 2022 | $ | 1,353 | | | | $ | 589 | | | $ | 1,942 | |
| | | Nine Months Ended September 30, 2020 | | Six Months Ended June 30, 2021 |
| (In millions) | (In millions) | Common Stock | | | Retained Earnings | | Total Shareholder's Equity | (In millions) | Common Stock | | | Retained Earnings | | Total Shareholder's Equity |
| Balance, December 31, 2019 | $ | 977 | | | | $ | 603 | | | $ | 1,580 | | |
| Balance, December 31, 2020 | | Balance, December 31, 2020 | $ | 1,089 | | | | $ | 587 | | | $ | 1,676 | |
| Net income | Net income | — | | | | 45 | | | 45 | | Net income | — | | | | 56 | | | 56 | |
| Common stock dividends | Common stock dividends | — | | | | (52) | | | (52) | | Common stock dividends | — | | | | (40) | | | (40) | |
| Contributions from parent | Contributions from parent | 6 | | | | — | | | 6 | | Contributions from parent | 120 | | | | — | | | 120 | |
| Balance, March 31, 2020 | $ | 983 | | | | $ | 596 | | | $ | 1,579 | | |
| Balance, March 31, 2021 | | Balance, March 31, 2021 | $ | 1,209 | | | | $ | 603 | | | $ | 1,812 | |
| Net income | Net income | — | | | | 19 | | | 19 | | Net income | — | | | | 30 | | | 30 | |
| Common stock dividends | Common stock dividends | — | | | | (14) | | | (14) | | Common stock dividends | — | | | | (23) | | | (23) | |
| Contributions from parent | 100 | | | | — | | | 100 | | |
| Balance, June 30, 2020 | $ | 1,083 | | | | $ | 601 | | | $ | 1,684 | | |
| Net income | — | | | | 27 | | | 27 | | |
| Common stock dividends | — | | | | (33) | | | (33) | | |
| Contributions from parent | 6 | | | | — | | | 6 | | |
| Balance, September 30, 2020 | $ | 1,089 | | | | $ | 595 | | | $ | 1,684 | | |
| | Balance, June 30, 2021 | | Balance, June 30, 2021 | $ | 1,209 | | | | $ | 610 | | | $ | 1,819 | |
See the Combined Notes to Consolidated Financial Statements
5144
ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
| | | Three Months Ended
September 30, | | Nine Months Ended
September 30, | | Three Months Ended
June 30, | | Six Months Ended
June 30, |
| (In millions) | (In millions) | 2021 | | 2020 | | 2021 | | 2020 | (In millions) | 2022 | | 2021 | | 2022 | | 2021 |
| Operating revenues | Operating revenues | | | | | | | | Operating revenues | | | | | | | |
| Electric operating revenues | Electric operating revenues | $ | 450 | | | $ | 414 | | | $ | 1,055 | | | $ | 969 | | Electric operating revenues | $ | 323 | | | $ | 306 | | | $ | 668 | | | $ | 605 | |
| Revenues from alternative revenue programs | Revenues from alternative revenue programs | — | | | 5 | | | 23 | | | (20) | | Revenues from alternative revenue programs | (15) | | | 12 | | | (12) | | | 23 | |
| Operating revenues from affiliates | Operating revenues from affiliates | 1 | | | 1 | | | 2 | | | 3 | | Operating revenues from affiliates | 1 | | | 1 | | | 2 | | | 1 | |
| Total operating revenues | Total operating revenues | 451 | | | 420 | | | 1,080 | | | 952 | | Total operating revenues | 309 | | | 319 | | | 658 | | | 629 | |
| Operating expenses | Operating expenses | | | | | | | | Operating expenses | | | | | | | |
| Purchased power | Purchased power | 225 | | | 207 | | | 527 | | | 460 | | Purchased power | 123 | | | 149 | | | 299 | | | 302 | |
| Purchased power from affiliate | Purchased power from affiliate | 5 | | | 4 | | | 14 | | | 9 | | Purchased power from affiliate | — | | | 5 | | | 2 | | | 9 | |
| Operating and maintenance | Operating and maintenance | 46 | | | 45 | | | 128 | | | 140 | | Operating and maintenance | 50 | | | 39 | | | 97 | | | 82 | |
| Operating and maintenance from affiliates | Operating and maintenance from affiliates | 35 | | | 32 | | | 103 | | | 98 | | Operating and maintenance from affiliates | 36 | | | 34 | | | 73 | | | 68 | |
| Depreciation and amortization | Depreciation and amortization | 46 | | | 48 | | | 133 | | | 134 | | Depreciation and amortization | 72 | | | 40 | | | 118 | | | 87 | |
| Taxes other than income taxes | Taxes other than income taxes | 2 | | | 2 | | | 6 | | | 6 | | Taxes other than income taxes | 2 | | | 2 | | | 4 | | | 4 | |
| Total operating expenses | Total operating expenses | 359 | | | 338 | | | 911 | | | 847 | | Total operating expenses | 283 | | | 269 | | | 593 | | | 552 | |
| Gain on sales of assets | — | | | — | | | — | | | 2 | | |
| | | Operating income | Operating income | 92 | | | 82 | | | 169 | | | 107 | | Operating income | 26 | | | 50 | | | 65 | | | 77 | |
| Other income and (deductions) | Other income and (deductions) | | | | | | | | Other income and (deductions) | | | | | | | |
| Interest expense, net | Interest expense, net | (14) | | | (15) | | | (43) | | | (45) | | Interest expense, net | (17) | | | (14) | | | (32) | | | (29) | |
| | Other, net | Other, net | 1 | | | 1 | | | 3 | | | 5 | | Other, net | 2 | | | — | | | 5 | | | 2 | |
| Total other income and (deductions) | Total other income and (deductions) | (13) | | | (14) | | | (40) | | | (40) | | Total other income and (deductions) | (15) | | | (14) | | | (27) | | | (27) | |
| Income before income taxes | Income before income taxes | 79 | | | 68 | | | 129 | | | 67 | | Income before income taxes | 11 | | | 36 | | | 38 | | | 50 | |
| Income taxes | Income taxes | (11) | | | (7) | | | (12) | | | (39) | | Income taxes | — | | | (1) | | | 1 | | | (1) | |
| | Net income | Net income | $ | 90 | | | $ | 75 | | | $ | 141 | | | $ | 106 | | Net income | $ | 11 | | | $ | 37 | | | $ | 37 | | | $ | 51 | |
| Comprehensive income | Comprehensive income | $ | 90 | | | $ | 75 | | | $ | 141 | | | $ | 106 | | Comprehensive income | $ | 11 | | | $ | 37 | | | $ | 37 | | | $ | 51 | |
See the Combined Notes to Consolidated Financial Statements
5245
ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
| | | Nine Months Ended
September 30, | | Six Months Ended
June 30, |
| (In millions) | (In millions) | 2021 | | 2020 | (In millions) | 2022 | | 2021 |
| Cash flows from operating activities | Cash flows from operating activities | | | | Cash flows from operating activities | | | |
| Net income | Net income | $ | 141 | | | $ | 106 | | Net income | $ | 37 | | | $ | 51 | |
| Adjustments to reconcile net income to net cash flows provided by operating activities: | Adjustments to reconcile net income to net cash flows provided by operating activities: | | Adjustments to reconcile net income to net cash flows provided by operating activities: | |
| Depreciation and amortization | Depreciation and amortization | 133 | | | 134 | | Depreciation and amortization | 118 | | | 87 | |
| Deferred income taxes and amortization of investment tax credits | Deferred income taxes and amortization of investment tax credits | (20) | | | (40) | | Deferred income taxes and amortization of investment tax credits | — | | | (2) | |
| Other non-cash operating activities | Other non-cash operating activities | (8) | | | 34 | | Other non-cash operating activities | 25 | | | (14) | |
| Changes in assets and liabilities: | Changes in assets and liabilities: | | Changes in assets and liabilities: | |
| Accounts receivable | Accounts receivable | (81) | | | (62) | | Accounts receivable | (20) | | | (30) | |
| Receivables from and payables to affiliates, net | Receivables from and payables to affiliates, net | — | | | 2 | | Receivables from and payables to affiliates, net | (10) | | | 4 | |
| Inventories | Inventories | (1) | | | — | | Inventories | (2) | | | 2 | |
| Accounts payable and accrued expenses | Accounts payable and accrued expenses | (3) | | | 16 | | Accounts payable and accrued expenses | 9 | | | (2) | |
| Collateral received, net | | Collateral received, net | 137 | | | — | |
| Income taxes | Income taxes | 10 | | | 4 | | Income taxes | 8 | | | 2 | |
| Regulatory assets and liabilities, net | | Regulatory assets and liabilities, net | (11) | | | 18 | |
| Pension and non-pension postretirement benefit contributions | Pension and non-pension postretirement benefit contributions | (3) | | | (3) | | Pension and non-pension postretirement benefit contributions | (7) | | | (3) | |
| Other assets and liabilities | Other assets and liabilities | 15 | | | (53) | | Other assets and liabilities | (63) | | | (43) | |
| Net cash flows provided by operating activities | Net cash flows provided by operating activities | 183 | | | 138 | | Net cash flows provided by operating activities | 221 | | | 70 | |
| Cash flows from investing activities | Cash flows from investing activities | | | | Cash flows from investing activities | | | |
| Capital expenditures | Capital expenditures | (336) | | | (281) | | Capital expenditures | (179) | | | (239) | |
| | Other investing activities | 1 | | | 5 | | |
| | Net cash flows used in investing activities | Net cash flows used in investing activities | (335) | | | (276) | | Net cash flows used in investing activities | (179) | | | (239) | |
| Cash flows from financing activities | Cash flows from financing activities | | | | Cash flows from financing activities | | | |
| Changes in short-term borrowings | Changes in short-term borrowings | 38 | | | (70) | | Changes in short-term borrowings | (144) | | | (9) | |
| | Issuance of long-term debt | Issuance of long-term debt | 350 | | | 123 | | Issuance of long-term debt | 175 | | | 350 | |
| Retirement of long-term debt | Retirement of long-term debt | (254) | | | (38) | | Retirement of long-term debt | — | | | (249) | |
| Changes in PHI intercompany money pool | — | | | 117 | | |
| | Dividends paid on common stock | Dividends paid on common stock | (280) | | | (111) | | Dividends paid on common stock | (38) | | | (229) | |
| Contributions from parent | Contributions from parent | 303 | | | 117 | | Contributions from parent | 173 | | | 303 | |
| Other financing activities | Other financing activities | (5) | | | (1) | | Other financing activities | (4) | | | (4) | |
| Net cash flows provided by financing activities | Net cash flows provided by financing activities | 152 | | | 137 | | Net cash flows provided by financing activities | 162 | | | 162 | |
| Decrease in cash, restricted cash, and cash equivalents | — | | | (1) | | |
| Increase (decrease) in cash, restricted cash, and cash equivalents | | Increase (decrease) in cash, restricted cash, and cash equivalents | 204 | | | (7) | |
| Cash, restricted cash, and cash equivalents at beginning of period | Cash, restricted cash, and cash equivalents at beginning of period | 30 | | | 28 | | Cash, restricted cash, and cash equivalents at beginning of period | 29 | | | 30 | |
| Cash, restricted cash, and cash equivalents at end of period | Cash, restricted cash, and cash equivalents at end of period | $ | 30 | | | $ | 27 | | Cash, restricted cash, and cash equivalents at end of period | $ | 233 | | | $ | 23 | |
| | Supplemental cash flow information | Supplemental cash flow information | | Supplemental cash flow information | |
| (Decrease) increase in capital expenditures not paid | $ | (34) | | | $ | 9 | | |
| Decrease in capital expenditures not paid | | Decrease in capital expenditures not paid | $ | (19) | | | $ | (13) | |
|
See the Combined Notes to Consolidated Financial Statements
5346
ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
| | (In millions) | (In millions) | September 30, 2021 | | December 31, 2020 | (In millions) | June 30, 2022 | | December 31, 2021 |
| ASSETS | ASSETS | | | | ASSETS | | | |
| Current assets | Current assets | | Current assets | |
| Cash and cash equivalents | Cash and cash equivalents | $ | 16 | | | $ | 17 | | Cash and cash equivalents | $ | 233 | | | $ | 29 | |
| Restricted cash and cash equivalents | 5 | | | 3 | | |
| | Accounts receivable | Accounts receivable | | Accounts receivable | |
| Customer accounts receivable | Customer accounts receivable | 230 | | 156 | Customer accounts receivable | 194 | | 190 |
| Customer allowance for credit losses | Customer allowance for credit losses | (46) | | (32) | Customer allowance for credit losses | (45) | | (49) |
| Customer accounts receivable, net | Customer accounts receivable, net | 184 | | | 124 | | Customer accounts receivable, net | 149 | | | 141 | |
| Other accounts receivable | Other accounts receivable | 75 | | 72 | Other accounts receivable | 70 | | 76 |
| Other allowance for credit losses | Other allowance for credit losses | (15) | | (11) | Other allowance for credit losses | (14) | | (15) |
| Other accounts receivable, net | Other accounts receivable, net | 60 | | | 61 | | Other accounts receivable, net | 56 | | | 61 | |
| | Receivables from affiliates | Receivables from affiliates | 1 | | | 6 | | Receivables from affiliates | 1 | | | 2 | |
| | Inventories, net | Inventories, net | 38 | | | 37 | | Inventories, net | 38 | | | 36 | |
| | Prepaid utility taxes | Prepaid utility taxes | 10 | | | — | | Prepaid utility taxes | 40 | | | — | |
| Regulatory assets | Regulatory assets | 57 | | | 75 | | Regulatory assets | 135 | | | 61 | |
| Other | Other | 5 | | | 3 | | Other | 7 | | | 3 | |
| Total current assets | Total current assets | 376 | | | 326 | | Total current assets | 659 | | | 333 | |
| Property, plant, and equipment (net of accumulated depreciation and amortization of $1,390 and $1,303 as of September 30, 2021 and December 31, 2020, respectively) | 3,649 | | | 3,475 | | |
| Property, plant, and equipment (net of accumulated depreciation and amortization of $1,491 and $1,420 as of June 30, 2022 and December 31, 2021, respectively) | | Property, plant, and equipment (net of accumulated depreciation and amortization of $1,491 and $1,420 as of June 30, 2022 and December 31, 2021, respectively) | 3,798 | | | 3,729 | |
| Deferred debits and other assets | Deferred debits and other assets | | Deferred debits and other assets | |
| Regulatory assets | Regulatory assets | 428 | | | 395 | | Regulatory assets | 535 | | | 430 | |
| | Prepaid pension asset | Prepaid pension asset | 31 | | | 40 | | Prepaid pension asset | 26 | | | 27 | |
| | Other | Other | 48 | | | 50 | | Other | 34 | | | 37 | |
| Total deferred debits and other assets | Total deferred debits and other assets | 507 | | | 485 | | Total deferred debits and other assets | 595 | | | 494 | |
Total assets(a) | Total assets(a) | $ | 4,532 | | | $ | 4,286 | | Total assets(a) | $ | 5,052 | | | $ | 4,556 | |
See the Combined Notes to Consolidated Financial Statements
5447
ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
| | | | | | | | | | | |
| (In millions) | September 30, 2021 | | December 31, 2020 |
| LIABILITIES AND SHAREHOLDER'S EQUITY | | | |
| Current liabilities | | | |
| Short-term borrowings | $ | 225 | | | $ | 187 | |
| Long-term debt due within one year | 8 | | | 261 | |
| Accounts payable | 146 | | | 177 | |
| Accrued expenses | 43 | | | 46 | |
| Payables to affiliates | 26 | | | 31 | |
| | | |
| | | |
| | | |
| Customer deposits | 19 | | | 23 | |
| Regulatory liabilities | 46 | | | 44 | |
| Other | 15 | | | 11 | |
| Total current liabilities | 528 | | | 780 | |
| Long-term debt | 1,502 | | | 1,152 | |
| Deferred credits and other liabilities | | | |
| Deferred income taxes and unamortized investment tax credits | 671 | | | 624 | |
| | | |
| | | |
| Non-pension postretirement benefit obligations | 13 | | | 17 | |
| | | |
| Regulatory liabilities | 211 | | | 274 | |
| | | |
| | | |
| Other | 52 | | | 48 | |
| Total deferred credits and other liabilities | 947 | | | 963 | |
Total liabilities(a) | 2,977 | | | 2,895 | |
| Commitments and contingencies | 0 | | 0 |
| Shareholder's equity | | | |
| Common stock | 1,574 | | | 1,271 | |
| Retained (deficit) earnings | (19) | | | 120 | |
| | | |
| Total shareholder's equity | 1,555 | | | 1,391 | |
| Total liabilities and shareholder's equity | $ | 4,532 | | | $ | 4,286 | |
__________ | | | | | | | | | | | |
| (In millions) | June 30, 2022 | | December 31, 2021 |
| LIABILITIES AND SHAREHOLDER'S EQUITY | | | |
| Current liabilities | | | |
| Short-term borrowings | $ | — | | | $ | 144 | |
| Long-term debt due within one year | 3 | | | 3 | |
| Accounts payable | 157 | | | 165 | |
| Accrued expenses | 43 | | | 44 | |
| Payables to affiliates | 20 | | | 31 | |
| | | |
| | | |
| | | |
| Customer deposits | 18 | | | 18 | |
| Regulatory liabilities | 29 | | | 28 | |
| PPA termination obligation | 87 | | | — | |
| Other | 149 | | | 12 | |
| Total current liabilities | 506 | | | 445 | |
| Long-term debt | 1,754 | | | 1,579 | |
| Deferred credits and other liabilities | | | |
| Deferred income taxes and unamortized investment tax credits | 695 | | | 682 | |
| Regulatory liabilities | 197 | | | 214 | |
| | | |
| | | |
| Non-pension postretirement benefit obligations | 10 | | | 12 | |
| | | |
| | | |
| | | |
| Other | 143 | | | 49 | |
| Total deferred credits and other liabilities | 1,045 | | | 957 | |
| Total liabilities | 3,305 | | | 2,981 | |
| Commitments and contingencies | 0 | | 0 |
| Shareholder's equity | | | |
| Common stock | 1,763 | | | 1,590 | |
| Retained deficit | (16) | | | (15) | |
| | | |
| Total shareholder's equity | 1,747 | | | 1,575 | |
| Total liabilities and shareholder's equity | $ | 5,052 | | | $ | 4,556 | |
(a)ACE’s consolidated total assets include $14 million and $13 million at September 30, 2021 and December 31, 2020, respectively, of ACE's consolidated VIE that can only be used to settle the liabilities of the VIE. ACE’s consolidated total liabilities include $6 million and $21 million at September 30, 2021 and December 31, 2020, respectively, of ACE's consolidated VIE for which the VIE creditors do not have recourse to ACE. See Note 17 — Variable Interest Entities for additional information.
See the Combined Notes to Consolidated Financial Statements
5548
ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY
(Unaudited)
| | | Nine Months Ended September 30, 2021 | | Six Months Ended June 30, 2022 |
| (In millions) | (In millions) | Common Stock | | | Retained Earnings (Deficit) | | Total Shareholder's Equity | (In millions) | Common Stock | | | Retained Deficit | | Total Shareholder's Equity |
| Balance, December 31, 2020 | $ | 1,271 | | | | $ | 120 | | | $ | 1,391 | | |
| Balance, December 31, 2021 | | Balance, December 31, 2021 | $ | 1,590 | | | | $ | (15) | | | $ | 1,575 | |
| Net income | Net income | — | | | | 14 | | | 14 | | Net income | — | | | | 26 | | | 26 | |
| Common stock dividends | Common stock dividends | — | | | | (14) | | | (14) | | Common stock dividends | — | | | | (19) | | | (19) | |
| Contributions from parent | Contributions from parent | 303 | | | | — | | | 303 | | Contributions from parent | 173 | | | | — | | | 173 | |
| Balance, March 31, 2021 | $ | 1,574 | | | | $ | 120 | | | $ | 1,694 | | |
| Balance, March 31, 2022 | | Balance, March 31, 2022 | $ | 1,763 | | | | $ | (8) | | | $ | 1,755 | |
| Net income | Net income | — | | | | 37 | | | 37 | | Net income | — | | | | 11 | | | 11 | |
| Common stock dividends | Common stock dividends | — | | | | (215) | | | (215) | | Common stock dividends | — | | | | (19) | | | (19) | |
| | Balance, June 30, 2021 | $ | 1,574 | | | | $ | (58) | | | $ | 1,516 | | |
| Net income | — | | | | 90 | | | 90 | | |
| Common stock dividends | — | | | | (51) | | | (51) | | |
| | Balance, September 30, 2021 | $ | 1,574 | | | | $ | (19) | | | $ | 1,555 | | |
| Balance, June 30, 2022 | | Balance, June 30, 2022 | $ | 1,763 | | | | $ | (16) | | | $ | 1,747 | |
| | | Nine Months Ended September 30, 2020 | | Six Months Ended June 30, 2021 |
| (In millions) | (In millions) | Common Stock | | | Retained Earnings | | Total Shareholder's Equity | (In millions) | Common Stock | | | Retained Earnings (Deficit) | | Total Shareholder's Equity |
| Balance, December 31, 2019 | $ | 1,154 | | | | $ | 122 | | | $ | 1,276 | | |
| Balance, December 31, 2020 | | Balance, December 31, 2020 | $ | 1,271 | | | | $ | 127 | | | $ | 1,398 | |
| Net income | Net income | — | | | | 13 | | | 13 | | Net income | — | | | | 14 | | | 14 | |
| Common stock dividends | Common stock dividends | — | | | | (23) | | | (23) | | Common stock dividends | — | | | | (14) | | | (14) | |
| Contributions from parent | Contributions from parent | 1 | | | | — | | | 1 | | Contributions from parent | 303 | | | | — | | | 303 | |
| Balance, March 31, 2020 | $ | 1,155 | | | | $ | 112 | | | $ | 1,267 | | |
| Balance, March 31, 2021 | | Balance, March 31, 2021 | $ | 1,574 | | | | $ | 127 | | | $ | 1,701 | |
| Net income | Net income | — | | | | 18 | | | 18 | | Net income | — | | | | 37 | | | 37 | |
| Common stock dividends | Common stock dividends | — | | | | (12) | | | (12) | | Common stock dividends | — | | | | (215) | | | (215) | |
| Contributions from parent | 115 | | | — | | | 115 | | |
| Balance, June 30, 2020 | $ | 1,270 | | | | $ | 118 | | | $ | 1,388 | | |
| Net income | — | | | | 75 | | | 75 | | |
| Common stock dividends | — | | | | (76) | | | (76) | | |
| Contributions from parent | 1 | | | | — | | | 1 | | |
| Balance, September 30, 2020 | $ | 1,271 | | | | $ | 117 | | | $ | 1,388 | | |
| | Balance, June 30, 2021 | | Balance, June 30, 2021 | $ | 1,574 | | | | $ | (51) | | | $ | 1,523 | |
See the Combined Notes to Consolidated Financial Statements
5649
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)
Note 1 — Significant Accounting Policies
1. Significant Accounting Policies (All Registrants)
Description of Business (All Registrants)
Exelon is a utility services holding company engaged in the generation, delivery and marketing of energy through Generation and the energy distribution and transmission businesses through ComEd, PECO, BGE, Pepco, DPL, and ACE.
On February 21, 2021, Exelon's Board of Directors approved a plan to separate the Utility Registrants and Generation. The separation was completed on February 1, 2022, creating two publicly traded companies, Exelon and Constellation. See Note 2 — Discontinued Operations for additional information.
| | | | | | | | | | | | | | |
| Name of Registrant | | Business | | Service Territories |
Exelon Generation
Company, LLC | | Generation, physical delivery and marketing of power across multiple geographical regions through its customer-facing business, Constellation, which sells electricity to both wholesale and retail customers. Generation also sells natural gas, renewable energy, and other energy-related products and services. | | Five reportable segments: Mid-Atlantic, Midwest, New York, ERCOT, and Other Power Regions |
| | | | |
| Commonwealth Edison Company | | Purchase and regulated retail sale of electricity | | Northern Illinois, including the City of Chicago |
| | Transmission and distribution of electricity to retail customers | | |
| PECO Energy Company | | Purchase and regulated retail sale of electricity and natural gas | | Southeastern Pennsylvania, including the City of Philadelphia (electricity) |
| | Transmission and distribution of electricity and distribution of natural gas to retail customers | | Pennsylvania counties surrounding the City of Philadelphia (natural gas) |
| Baltimore Gas and Electric Company | | Purchase and regulated retail sale of electricity and natural gas | | Central Maryland, including the City of Baltimore (electricity and natural gas) |
| | Transmission and distribution of electricity and distribution of natural gas to retail customers | | |
| Pepco Holdings LLC | | Utility services holding company engaged, through its reportable segments Pepco, DPL, and ACE | | Service Territories of Pepco, DPL, and ACE |
| | | | |
Potomac Electric
Power Company | | Purchase and regulated retail sale of electricity | | District of Columbia, and major portions of Montgomery and Prince George’s Counties, Maryland |
| | Transmission and distribution of electricity to retail customers | | |
Delmarva Power &
Light Company | | Purchase and regulated retail sale of electricity and natural gas | | Portions of Delaware and Maryland (electricity) |
| | Transmission and distribution of electricity and distribution of natural gas to retail customers | | Portions of New Castle County, Delaware (natural gas) |
| Atlantic City Electric Company | | Purchase and regulated retail sale of electricity | | Portions of Southern New Jersey |
| | Transmission and distribution of electricity to retail customers | | |
Basis of Presentation (All Registrants)
This is a combined quarterly report of all Registrants. The Notes to the Consolidated Financial Statements apply to the Registrants as indicated parenthetically next to each corresponding disclosure. When appropriate, the Registrants are named specifically for their related activities and disclosures. Each of the Registrant’s Consolidated Financial Statements includes the accounts of its subsidiaries. All intercompany transactions have been eliminated.eliminated, except for the historical transactions between the Utility Registrants and Generation for the purposes of presenting discontinued operations in all periods presented in the Consolidated Statements of Operations and Comprehensive Income.
Through its business services subsidiary, BSC, Exelon provides its subsidiaries with a variety of support services at cost, including legal, human resources, financial, information technology, and supply management services. PHI also has a business services subsidiary, PHISCO, which provides a variety of support services at cost, including legal, accounting, engineering, customer operations, distribution and transmission planning, asset management, system operations, and power procurement, to PHI operating companies. The costs of BSC and PHISCO are directly charged or allocated to the applicable subsidiaries. The results of Exelon’s corporate operations are presented as “Other��“Other” in the consolidated financial statements and include intercompany eliminations unless otherwise disclosed.
The accompanying consolidated financial statements as of SeptemberJune 30, 20212022 and for the three and ninesix months ended SeptemberJune 30, 20212022 and 20202021 are unaudited but, in the opinion of the management of each Registrant include all adjustments that are considered necessary for a fair statement of the Registrants’ respective financial statements in accordance with GAAP. All adjustments are of a normal, recurring nature, except as otherwise
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)
Note 1 — Significant Accounting Policies
except as otherwise disclosed. The December 31, 20202021 Consolidated Balance Sheets were derived from audited financial statements. FinancialThe interim financial statements are to be read in conjunction with prior annual financial statements and notes. Additionally, financial results for interim periods are not necessarily indicative of results that may be expected for any other interim period or for the fiscal year ending December 31, 2021.2022. These Combined Notes to Consolidated Financial Statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations.
2. Mergers, Acquisitions,The separation of Constellation, including Generation and Dispositions (Exelonits subsidiaries, meets the criteria for discontinued operations and Generation)
CENG Put Option (Exelonas such, results of operations are presented as discontinued operations and Generation)
Priorhave been excluded from continuing operations for all periods presented. Accounting rules require that certain BSC costs previously allocated to August 6, 2021, Generation owned a 50.01% membership interestbe presented as part of Exelon’s continuing operations as these costs do not qualify as expenses of the discontinued operations. Comprehensive income, shareholders' equity, and cash flows related to Constellation have not been segregated and are included in CENG, a joint venture with EDF, which wholly owns the Calvert CliffsConsolidated Statements of Operations and Ginna nuclear stationsComprehensive Income, Consolidated Statements of Changes in Shareholders’ Equity, and Nine Mile Point Unit 1, in addition to an 82% undivided ownership interest in Nine Mile Point Unit 2. CENG is 100% consolidated in Exelon's and Generation's financial statements.Consolidated Statements of Cash Flows, respectively, for all periods presented. See Note 172 — Variable Interest EntitiesDiscontinued Operations for additional information.
2. Discontinued Operations (Exelon)
On AprilFebruary 21, 2021, Exelon's Board of Directors approved a plan to separate the Utility Registrants and Generation, creating two publicly traded companies ("the separation"). Exelon completed the separation on February 1, 2014,2022, through the distribution of 326,663,937 common stock shares of Constellation, the new publicly traded company, to Exelon shareholders. Under the separation plan, Exelon shareholders retained their current shares of Exelon stock and received one share of Constellation common stock for every three shares of Exelon common stock held on January 20, 2022, the record date for the distribution, in a transaction that is tax-free to Exelon and its shareholders for U.S. federal income tax purposes.
Constellation was newly formed and incorporated in Pennsylvania on June 15, 2021 for the purposes of separation and holds Generation and EDF(including Generation's subsidiaries).
Pursuant to the separation:
•Exelon entered into various agreements includingfour term loans consisting of a NOSA, an amended LLC Operating Agreement, an Employee Matters Agreement,364-day term loan for $1.15 billion and a Put Option Agreement, among others. Under the amended LLC Operating Agreement, CENG made a $400three 18-month term loans for $300 million, special distribution to EDF and committed to make preferred distributions to Generation until Generation has received aggregate distributions of $400 million plus a return of 8.50% per annum.
Under the terms of the Put Option Agreement, EDF had the option to sell its 49.99% equity interest in CENG to Generation exercisable beginning on January 1, 2016 and thereafter until June 30, 2022.
On November 20, 2019, Generation received notice of EDF’s intention to exercise the put option to sell its interest in CENG to Generation, and the put automatically exercised on January 19, 2020 at the end of the sixty-day advance notice period. The transaction required approval by FERC and the NYPSC, which approvals were received on July 30, 2020 and April 15, 2021, respectively. On August 6, 2021, Generation and EDF entered into a settlement agreement pursuant to which Generation purchased EDF’s equity interest in CENG for a net purchase price of $885 million, which includes, among other things, an adjustment for EDF’s share of the balance of the preferred distribution payable by CENG to Generation. The difference between the net purchase price and EDF’s Noncontrolling Interest as of August 6, 2021 was recorded in Common Stock in Exelon’s Consolidated Balance Sheet and Membership Interest in Generation’s Consolidated Balance Sheet. As a result of the transaction, Exelon and Generation recorded deferred tax liabilities of $290$300 million and $288$250 million, respectively, in Common Stock in Exelon’s Consolidated Balance Sheetrespectively. Exelon issued these term loans primarily to fund the cash payment to Constellation and Membership Interest in Generation’s Consolidated Balance Sheet.for general corporate purposes. See Note 10 — Income TaxesDebt and Credit Agreements for additional information.
•Exelon made a cash payment of $1.75 billion to Constellation on January 31, 2022.
•Exelon contributed its equity ownership interest in Generation to Constellation. Exelon no longer retains any equity ownership interest in Generation or Constellation.
•Exelon transferred certain corporate assets and employee-related obligations to Constellation.
•Exelon received cash from Generation of $258 million to settle the intercompany loan on January 31, 2022. See Note 10 — Debt and Credit Agreements for additional information.
Continuing Involvement
In order to govern the ongoing relationships between Exelon and Constellation after the separation, and to facilitate an orderly transition, Exelon and Constellation have entered into several agreements, including the following:
•Separation Agreement – governs the rights and obligations between Exelon and Constellation regarding certain actions to be taken in connection with the separation, among others, including the allocation of assets and liabilities between Exelon and Constellation.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 2 — Mergers, Acquisitions, and DispositionsDiscontinued Operations
•Tax Matters Agreement (TMA) – governs the respective rights, responsibilities and obligations of Exelon and Constellation with respect to all tax matters, including tax liabilities and benefits, tax attributes, tax returns, tax contests and other tax sharing regarding U.S. federal, state, local and foreign income taxes, other tax matters and related tax returns. See Note 7. Income Taxes for additional information.
In addition, the Utility Registrants will continue to incur expenses from transactions with Generation after the separation. Prior to the separation, such expenses were primarily recorded as Purchased power from affiliates and an immaterial amount recorded as Operating and maintenance expense from affiliates at the Utility Registrants. After the separation, such expenses are primarily recorded as Purchased power and an immaterial amount recorded as Operating and maintenance expense at the Utility Registrants.
•ComEd had an ICC-approved RFP contract with Generation to provide a portion of ComEd’s electric supply requirements. ComEd also purchased RECs and ZECs from Generation.
•PECO received electric supply from Generation under contracts executed through PECO’s competitive procurement process. In addition, PECO had a ten-year agreement with Generation to sell solar AECs.
•BGE received a portion of its energy requirements from Generation under its MDPSC-approved market-based SOS and gas commodity programs.
•Pepco received electric supply from Generation under contracts executed through Pepco’s competitive procurement process approved by the MDPSC and DCPSC.
•DPL received a portion of its energy requirements from Generation under its MDPSC and DEPSC approved market-based SOS commodity programs.
•ACE received electric supply from Generation under contracts executed through ACE’s competitive procurement process approved by the NJBPU.
ComEd and PECO also have receivables with Generation as a result of the nuclear decommissioning contractual construct whereby, to the extent NDT funds are greater than the underlying ARO at the end of decommissioning, such amounts are due back to ComEd and PECO, as applicable, for payment to their respective customers. See Note 9 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements of the 2021 Recast Form 10-K and Note 15 — Related Party Transactions for additional information.
Discontinued Operations
The separation represented a strategic shift that would have a major effect on Exelon’s operations and financial results. Accordingly, the separation meets the criteria for discontinued operations.
The following tables summarizetable presents the effectsresults of the changes in Generation's ownership interest in CENG in Exelon's Shareholders' EquityConstellation that have been reclassified from continuing operations and Generation's Member's Equity:
| | | | | | | | | | | | | | |
| | Three Months Ended September 30, 2021 | | Nine Months Ended September 30, 2021 |
| Net income attributable to Exelon's common shareholders | | $ | 1,203 | | | $ | 1,315 | |
Pre-tax increase in Exelon's common stock for purchase of EDF's 49.99% equity interest(a) | | 1,080 | | | 1,080 | |
Decrease in Exelon's common stock due to deferred tax liabilities resulting from purchase of EDF's 49.99% equity interest(a) | | (290) | | | (290) | |
| Change from net income attributable to common stock and transfers from noncontrolling interest | | $ | 1,993 | | | $ | 2,105 | |
| | | | |
| | Three Months Ended September 30, 2021 | | Nine Months Ended September 30, 2021 |
| Net income (loss) attributable to Generation's membership interest | | $ | 607 | | | $ | (247) | |
Pre-tax increase in Generation's membership interest for purchase of EDF's 49.99% equity interest(a) | | 1,080 | | | 1,080 | |
Decrease in Generation's membership interest due to deferred tax liabilities resulting from purchase of EDF's 49.99% equity interest(a) | | (288) | | | (288) | |
| Change from net income (loss) attributable to membership interest and transfers from noncontrolling interest | | $ | 1,399 | | | $ | 545 | |
_________
(a)Represents non-cash activity in Exelon’s and Generation’s consolidated financial statements.
Agreement for Sale of Generation’s Solar Business (Exelon and Generation)
On December 8, 2020, Generation entered into an agreement with an affiliate of Brookfield Renewable, for the sale of a significant portion of Generation’s solar business, including 360 MW of generation in operation or under construction across more than 600 sites across the United States. Generation will retain certain solar assets not included in this agreement, primarily Antelope Valley.
Completion of the transaction contemplated by the sale agreement was subject to the satisfaction of several closing conditions which were satisfied in the first quarter of 2021. The sale was completed on March 31, 2021 for a purchase price of $810 million. Generation received cash proceeds of $675 million, net of $125 million long-term debt assumed by the buyer and certain working capital and other post-closing adjustments. Exelon and Generation recognized a pre-tax gain of $68 million which is included in Gain on sales of assets and businesses indiscontinued operations within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.Income for the three and six months ended June 30, 2022 and June 30, 2021.
See These results are primarily Generation, which is comprised of Exelon’s Mid-Atlantic, Midwest, New York, ERCOT, and Other Power Regions reportable segments, and include the impact of transaction costs, certain BSC costs, including any transition costs, that were historically allocated and directly attributable to Generation, transactions between Generation and the Utility Registrants, and tax-related adjustments. Transaction costs include costs for
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 172 — DebtDiscontinued Operations
external bankers, accountants, appraisers, lawyers, external counsels and Credit Agreementsother advisors, among others, who are involved in the negotiation, appraisal, due diligence and regulatory approval of the Exelon 2020 Form 10-K for additionalseparation. Transition costs are primarily employee-related costs such as recruitment expenses, costs to establish certain stand-alone functions and information ontechnology systems, professional services fees and other separation-related costs during the SolGen nonrecourse debt included as parttransition to separate Generation. For the purposes of the transaction.
Agreement for the Sale of a Generation Biomass Facility (Exelon and Generation)
On April 28, 2021,reporting discontinued operations, these results also include transactions between Generation and ReGenerate Energy Holdings, LLC (“ReGenerate”) entered into a purchase agreement, under which ReGenerate agreed to purchase Generation’s interest in the Albany Green Energy biomass facility. As a result, in the second quarter of 2021, Exelon and Generation recorded a pre-tax impairment charge of $140 million in Operating and maintenance expense inUtility Registrants that were historically eliminated within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. Completionas these transactions will be ongoing after the separation. Certain BSC costs that were historically allocated to Generation are presented as part of continuing operations in Exelon’s Consolidated Statements of Operations as these costs do not qualify as expenses of the discontinued operations per the accounting rules.
| | | | | | | | | | | | | | | | | | | |
| | | Three Months Ended
June 30, | | Six Months Ended
June 30, |
| | | 2021 | | 2022 | | 2021 |
| Operating revenues | | | | | | | |
| Competitive business revenues | | | $ | 3,900 | | | $ | 1,855 | | | $ | 9,165 | |
| Competitive business revenues from affiliates | | | 255 | | | 161 | | | 549 | |
| Total operating revenues | | | 4,155 | | | 2,016 | | | 9,714 | |
| Operating expenses | | | | | | | |
| Competitive businesses purchased power and fuel | | | 1,947 | | | 1,138 | | | 6,557 | |
| | | | | | | |
Operating and maintenance(a) | | | 1,382 | | | 371 | | | 2,287 | |
| | | | | | | |
| Depreciation and amortization | | | 930 | | | 94 | | | 1,869 | |
| Taxes other than income taxes | | | 118 | | | 44 | | | 239 | |
| Total operating expenses | | | 4,377 | | | 1,647 | | | 10,952 | |
| Gain on sales of assets and businesses | | | 8 | | | 10 | | | 79 | |
| Operating income (loss) | | | (214) | | | 379 | | | (1,159) | |
| Other income and (deductions) | | | | | | | |
| Interest expense, net | | | (72) | | | (20) | | | (140) | |
| | | | | | | |
| Other, net | | | 508 | | | (281) | | | 675 | |
| Total other income and (deductions) | | | 436 | | | (301) | | | 535 | |
| Income (loss) before income taxes | | | 222 | | | 78 | | | (624) | |
| Income taxes | | | 71 | | | (40) | | | 13 | |
| Equity in losses of unconsolidated affiliates | | | (1) | | | (1) | | | (3) | |
| Net income (loss) | | | 150 | | | 117 | | | (640) | |
| Net income attributable to noncontrolling interests | | | 75 | | | 1 | | | 99 | |
| Net income (loss) from discontinued operations | | | $ | 75 | | | $ | 116 | | | $ | (739) | |
__________
(a)Includes transaction was subjectand transition costs related to the satisfactionseparation of various customary closing conditions which were satisfied in$52 million for the second quarter of 2021. The sale was completed onsix months ended June 30, 2022 and $4 million and $7 million for the three and six months ended June 30, 2021, respectively. See discussion above for additional information.
There were no assets and liabilities of discontinued operations included in Exelon’s Consolidated Balance Sheet as of June 30, 2022. Constellation had net assets of $11,573 million that separated on February 1, 2022 that resulted in a net purchase pricereduction to Exelon’s equity during the six months ended June 30, 2022. Refer to the Distribution of $36 million.Constellation line in Exelon’s Consolidated Statement of Changes in Shareholders’ Equity for further information.
The following table presents the assets and liabilities of discontinued operations in Exelon’s Consolidated Balance Sheet as of December 31, 2021:
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 2 — Discontinued Operations
| | | | | | | | |
| | December 31, 2021 |
| ASSETS | | |
| Current assets | | |
| Cash and cash equivalents | | $ | 510 | |
| Restricted cash and cash equivalents | | 72 | |
| Accounts receivable | | |
| Customer accounts receivable | | 1,724 |
| Customer allowance for credit losses | | (55) |
| Customer accounts receivable, net | | 1,669 | |
| Other accounts receivable | | 596 |
| Other allowance for credit losses | | (4) |
| Other accounts receivable, net | | 592 | |
| Mark-to-market derivative assets | | 2,169 | |
| Inventories, net | | |
| Fossil fuel and emission allowances | | 284 | |
| Materials and supplies | | 1,004 | |
| Renewable energy credits | | 529 | |
| Assets held for sale | | 13 | |
| Other | | 993 | |
| Total current assets of discontinued operations | | 7,835 | |
| Property, plant, and equipment (net of accumulated depreciation and amortization of $15,888) | | 19,661 | |
| Deferred debits and other assets | | |
| Nuclear decommissioning trust funds | | 15,938 | |
| Investments | | 193 | |
| | |
| Mark-to-market derivative assets | | 949 | |
| Other | | 1,768 | |
| Total property, plant, and equipment, deferred debits, and other assets of discontinued operations | | 38,509 | |
| Total assets of discontinued operations | | $ | 46,344 | |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 2 — Discontinued Operations
| | | | | | | | |
| | December 31, 2021 |
| LIABILITIES AND SHAREHOLDERS’ EQUITY | | |
| Current liabilities | | |
| Short-term borrowings | | $ | 2,082 | |
| Long-term debt due within one year | | 1,220 | |
| Accounts payable | | 1,757 | |
| Accrued expenses | | 818 | |
| Mark-to-market derivative liabilities | | 981 | |
| | |
| Renewable energy credit obligation | | 779 | |
| Liabilities held for sale | | 3 | |
| Other | | 300 | |
| Total current liabilities of discontinued operations | | 7,940 | |
| Long-term debt | | 4,575 | |
| Deferred credits and other liabilities | | |
| Deferred income taxes and unamortized investment tax credits | | 3,583 | |
| Asset retirement obligations | | 12,819 | |
| Pension obligations | | 939 | |
| Non-pension postretirement benefit obligations | | 876 | |
| Spent nuclear fuel obligation | | 1,210 | |
| Mark-to-market derivative liabilities | | 513 | |
| | |
| Other | | 1,161 | |
| Total long-term debt, deferred credits, and other liabilities of discontinued operations | | 25,676 | |
| Total liabilities of discontinued operations | | $ | 33,616 | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
The following table presents selected financial information regarding cash flows of the discontinued operations that are included within Exelon’s Consolidated Statements of Cash Flows for the six months ended June 30, 2022 and June 30, 2021.
| | | | | | | | | | | |
| Six Months Ended
June 30, |
| 2022 | | 2021 |
| Non-cash items included in net income (loss) from discontinued operations: | | | |
| Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization | $ | 207 | | | $ | 2,686 | |
| Asset impairments | — | | | 493 | |
| Gain on sales of assets and businesses | 9 | | | (79) | |
| Deferred income taxes and amortization of investment tax credits | (143) | | | (268) | |
| Net fair value changes related to derivatives | (59) | | | (490) | |
| Net realized and unrealized losses (gains) on NDT fund investments | 205 | | | (376) | |
| Net unrealized losses (gains) on equity investments | 16 | | | (96) | |
| Other decommissioning-related activity | 36 | | | (636) | |
| Cash flows from investing activities: | | | |
| Capital expenditures | (227) | | | (731) | |
| Collection of DPP | 169 | | | 2,209 | |
| Supplemental cash flow information: | | | |
| Decrease in capital expenditures not paid | (128) | | | (66) | |
| Increase in DPP | 348 | | | 1,958 | |
| Increase in PP&E related to ARO update | 335 | | | — | |
| | | |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 3 — Regulatory Matters
3. Regulatory Matters (All Registrants)
As discussed in Note 3 — Regulatory Matters of the Exelon 20202021 Recast Form 10-K, the Registrants are involved in rate and regulatory proceedings at FERC and their state commissions. The following discusses developments in 20212022 and updates to the 20202021 Recast Form 10-K.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)
Note 3 — Regulatory Matters
Utility Regulatory Matters (Exelon, PHI, and the Utility Registrants)
Distribution Base Rate Case Proceedings
The following tables show the completed and pending distribution base rate case proceedings in 2021.2022.
Completed Distribution Base Rate Case Proceedings
| | Registrant/Jurisdiction | Registrant/Jurisdiction | | Filing Date | | Service | | Requested Revenue Requirement (Decrease) Increase | | Approved Revenue Requirement (Decrease) Increase | | Approved ROE | | Approval Date | | Rate Effective Date | Registrant/Jurisdiction | | Filing Date | | Service | | Requested Revenue Requirement Increase | | Approved Revenue Requirement Increase | | Approved ROE | | Approval Date | | Rate Effective Date |
ComEd - Illinois(a) | ComEd - Illinois(a) | | April 16, 2020 | | Electric | | $ | (11) | | | $ | (14) | | | 8.38 | % | | December 9, 2020 | | January 1, 2021 | ComEd - Illinois(a) | | April 16, 2021 | | Electric | | $ | 51 | | | $ | 46 | | | 7.36 | % | | December 1, 2021 | | January 1, 2022 |
| PECO - Pennsylvania | PECO - Pennsylvania | | September 30, 2020 | | Natural Gas | | 69 | | | 29 | | | 10.24 | % | | June 22, 2021 | | July 1, 2021 | PECO - Pennsylvania | | March 30, 2021 | | Electric | | 246 | | | 132 | | | N/A(b) | | November 18, 2021 | | January 1, 2022 |
BGE - Maryland(b)(c) | BGE - Maryland(b)(c) | | May 15, 2020 (amended September 11, 2020) | | Electric | | 203 | | | 140 | | | 9.50 | % | | December 16, 2020 | | January 1, 2021 | BGE - Maryland(b)(c) | | May 15, 2020 (amended September 11, 2020) | | Electric | | 203 | | | 140 | | | 9.50 | % | | December 16, 2020 | | January 1, 2021 |
| Natural Gas | | 108 | | | 74 | | | 9.65 | % | | | Natural Gas | | 108 | | | 74 | | | 9.65 | % | |
Pepco - District of Columbia(c)(d) | Pepco - District of Columbia(c)(d) | | May 30, 2019 (amended June 1, 2020) | | Electric | | 136 | | | 109 | | | 9.275 | % | | June 8, 2021 | | July 1, 2021 | Pepco - District of Columbia(c)(d) | | May 30, 2019 (amended June 1, 2020) | | Electric | | 136 | | | 109 | | | 9.275 | % | | June 8, 2021 | | July 1, 2021 |
Pepco - Maryland(d)(e) | Pepco - Maryland(d)(e) | | October 26, 2020 (amended March 31, 2021) | | Electric | | 104 | | | 52 | | | 9.55 | % | | June 28, 2021 | | June 28, 2021 | Pepco - Maryland(d)(e) | | October 26, 2020 (amended March 31, 2021) | | Electric | | 104 | | | 52 | | | 9.55 | % | | June 28, 2021 | | June 28, 2021 |
| DPL - Delaware | | March 6, 2020 (amended February 2, 2021) | | Electric | | 23 | | | 14 | | | 9.60 | % | | September 15, 2021 | | October 6, 2020 | |
DPL - Maryland(f) | | DPL - Maryland(f) | | September 1, 2021 (amended December 23, 2021) | | Electric | | 27 | | | 13 | | | 9.60 | % | | March 2, 2022 | | March 2, 2022 |
ACE - New Jersey(e)(g) | ACE - New Jersey(e)(g) | | December 9, 2020 (amended February 26, 2021) | | Electric | | 67 | | | 41 | | | 9.60 | % | | July 14, 2021 | | January 1, 2022 | ACE - New Jersey(e)(g) | | December 9, 2020 (amended February 26, 2021) | | Electric | | 67 | | | 41 | | | 9.60 | % | | July 14, 2021 | | January 1, 2022 |
__________
(a)ComEd's 20212022 approved revenue requirement reflects an increase of $50$37 million for the initial year revenue requirement for 20212022 and a decreasean increase of $64$9 million related to the annual reconciliation for 2019.2020. The revenue requirement for 2021 and the revenue requirement for 2019 provide2022 provides for a weighted average debt and equity return on distribution rate base of 6.28%5.72%, inclusive of an allowed ROE of 8.38%7.36%, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points. The reconciliation revenue requirement for 2020 provides for a weighted average debt and equity return on distribution rate base of 5.69%, inclusive of an allowed ROE of 7.29%, reflecting the monthly yields on 30-year treasury bonds plus 580 basis points less a performance metrics penalty of 7 basis points.
(b)The PECO electric base rate case proceeding was resolved through a settlement agreement, which did not specify an approved ROE.
(c)Reflects a three-year cumulative multi-year plan for 2021 through 2023. The MDPSC awarded BGE electric revenue requirement increases of $59 million, $39 million, and $42 million, before offsets, in 2021, 2022, and 2023, respectively, and natural gas revenue requirement increases of $53 million, $11 million, and $10 million, before offsets, in 2021, 2022, and 2023, respectively. BGE proposed to use certain tax benefits to fully offset the increases in 2021 and 2022 and partially offset the increase in 2023. However, the MDPSC only utilized the tax benefits to fully offset the increases in 2021 and January 2022 such that customer rates will remain unchanged from 2020remained unchanged. For the remainder of 2022, the MDPSC chose to 2021. The MDPSC has deferred a decision on whether to useoffset only 25% of the cumulative 2021 and 2022 electric revenue requirement increases and 50% of the cumulative gas revenue requirement increases. Whether certain tax benefits will be used to offset the customer rate increases in 2022 and 2023 has not been decided, and BGE cannot predict the outcome.
(c)(d)Reflects a cumulative multi-year plan with 18-months remaining in 2021 through 2022. The DCPSC awarded Pepco electric incremental revenue requirement increases of $42 million and $67 million, before offsets, for the remainder of 2021 and 2022, respectively. However, the DCPSC utilized the acceleration of refunds for certain tax benefits along with other rate relief to partially offset the customer rate increases by $22 million and $40 million for the remainder of 2021 and 2022, respectively.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 3 — Regulatory Matters
(e)Reflects a three-year cumulative multi-year plan for April 1, 2021 through March 31, 2024. The MDPSC awarded Pepco electric incremental revenue requirement increases of $21 million, $16 million, and $15 million, before offsets, for the 12-month periods ending March 31, 2022, 2023, and 2024, respectively. Pepco proposed to utilize certain tax benefits to fully offset the increase through 2023 and partially offset customer rate increases in 2024. However, the MDPSC only utilized the acceleration of refunds for certain tax benefits to fully offset the increases such that customer rates remain unchanged through March 31, 2022. TheOn February 23, 2022, the MDPSC has deferred decision on whetherchose to use additionaloffset 25% of the cumulative revenue requirement increase for the 12-month period ending March 31, 2023. Whether certain tax benefits will be used to offset the customer rate increases for periods afterthe 12-month period ending March 31, 20222024 has not been decided, and Pepco cannot predict the outcome.
(e)(f)The approved settlement reflects a 9.60% ROE, which is solely for the purposes of calculating AFUDC and regulatory asset carrying costs.
(g)Requested and approved increases are before New Jersey sales and use tax. The order allows ACE to retain approximately $11 million of certain tax benefits which resulted in a decrease to income tax expense in Exelon's, PHI's, and ACE's Consolidated Statements of Operations and Comprehensive Income in the third quarter of 2021.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)
Note 3 — Regulatory Matters
Pending Distribution Base Rate Case Proceedings
| | Registrant/Jurisdiction | Registrant/Jurisdiction | | Filing Date | | Service | | Requested Revenue Requirement Increase | | Requested ROE | | Expected Approval Timing | Registrant/Jurisdiction | | Filing Date | | Service | | Requested Revenue Requirement Increase | | Requested ROE | | Expected Approval Timing |
ComEd - Illinois(a) | ComEd - Illinois(a) | | April 16, 2021 | | Electric | | $ | 51 | | | 7.36 | % | | Fourth quarter of 2021 | ComEd - Illinois(a) | | April 15, 2022 | | Electric | | $ | 199 | | | 7.85 | % | | Fourth quarter of 2022 |
PECO - Pennsylvania(b) | | March 30, 2021 | | Electric | | 246 | | | 10.95 | % | | Fourth quarter of 2021 | |
| | PECO - Pennsylvania | | PECO - Pennsylvania | | March 31, 2022 | | Natural Gas | | 82 | | | 10.95 | % | | Fourth quarter of 2022 |
| DPL - Delaware(b) | | DPL - Delaware(b) | | January 14, 2022 (amended February 28, 2022) | | Natural Gas | | 15 | | | 10.30 | % | | First quarter of 2023 |
DPL - Maryland(c) | | DPL - Maryland(c) | | May 19, 2022 | | Electric | | 38 | | | 10.25 | % | | Fourth quarter of 2022 |
| | DPL - Maryland | | September 1, 2021 | | Electric | | 29 | | | 10.10 | % | | First quarter of 2022 | |
|
(a)ComEd's 20222023 requested revenue requirement reflects an increase of $40$144 million for the initial year revenue requirement for 20222023 and an increase of $11$55 million related to the annual reconciliation for 2020.2021. The revenue requirement for 20222023 provides for a weighted average debt and equity return on distribution rate base of 5.72%5.94%, inclusive of an allowed ROE of 7.36%7.85%, reflecting the average monthly yields for 30-year treasury bonds plus 580 basis points. The reconciliation revenue requirement for 20202021 provides for a weighted average debt and equity return on distribution rate base of 5.69%5.91%, inclusive of an allowed ROE of 7.29%7.78%, reflecting the average monthly yields for 30-year treasury bonds plus 580 basis points less a performance metrics penalty of 7 basis points. This is ComEd's last performance-based electric distribution formula rate update filing under EIMA as a result of the law authorizing the rate setting process sunsetting at the end of 2022. See Note 3 - Regulatory Matters of the 2021 Recast Form 10-K for additional information on ComEd's transition away from the electric distribution formula rate.
(b)The Joint Petitionrates will go into effect on August 14, 2022, subject to refund.
(c)Reflects a three-year cumulative multi-year plan for Settlement was filed on September 15,January 1, 2023 to December 31, 2025 and total requested revenue requirement increases, before offsets, of $23 million effective January 1, 2023, $8 million effective January 1, 2024, and $7 million effective January 1, 2025, to recover capital investments made in 2021 and recommendedplanned capital investments through the end of 2025. DPL is proposing the acceleration of refunds for approvalcertain tax benefits to partially offset the customer rate increases by the administrative law judge on October 6, 2021. PAPUC approval is expected$12 million and $8 million in the fourth quarter of 2021.2023 and 2024, respectively.
Transmission Formula Rates
The Utility Registrants' transmission rates are each established based on a FERC-approved formula. ComEd, BGE, Pepco, DPL, and ACE are required to file an annual update to the FERC-approved formula on or before May 15, and PECO is required to file on or before May 31, with the resulting rates effective on June 1 of the same year. The annual update for ComEd is based on prior year actual costs and current year projected capital additions (initial year revenue requirement). The update for ComEd also reconciles any differences between the revenue requirement in effect beginning June 1 of the prior year and actual costs incurred for that year (annual reconciliation). The annual update for PECO is based on prior year actual costs and current year projected capital additions, accumulated depreciation, and accumulated deferred income taxes. The annual update for BGE, Pepco, DPL, and ACE is based on prior year actual costs and current year projected capital additions, accumulated depreciation, depreciation and amortization expense, and accumulated deferred income taxes. The update for ComEd also reconciles any differences between the revenue requirement in effect beginning June 1 of the prior year and actual costs incurred for that year (annual reconciliation). The update for PECO, BGE, Pepco, DPL, and ACE also reconciles any differences between the actual costs and actual revenues for the calendar year (annual reconciliation).
For 2021, the following total increases/(decreases) were included in the Utility Registrants’ electric transmission formula rate updates:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Registrant(a) | | Initial Revenue Requirement Increase (Decrease) | | Annual Reconciliation Increase | | Total Revenue Requirement Increase(b) | | Allowed Return on Rate Base(c) | | Allowed ROE(d) |
| ComEd | | $ | 33 | | | $ | 12 | | | $ | 45 | | | 8.20 | % | | 11.50 | % |
| PECO | | (2) | | | 26 | | | 24 | | | 7.37 | % | | 10.35 | % |
| BGE | | 38 | | | 27 | | | 65 | | | 7.35 | % | | 10.50 | % |
| Pepco | | (9) | | | 21 | | | 12 | | | 7.68 | % | | 10.50 | % |
| DPL | | 19 | | | 33 | | | 52 | | | 7.20 | % | | 10.50 | % |
| ACE | | 27 | | | 24 | | | 51 | | | 7.45 | % | | 10.50 | % |
__________
(a)All rates are effective June 1, 2021 - May 31, 2022, subject to review by interested parties pursuant to review protocols of each Utility Registrants' tariff.
(b)In 2020, ComEd, BGE, Pepco, DPL, and ACE's transmission revenue requirement included a one-time decrease in accordance with the April 24, 2020 settlement agreement related to excess deferred income taxes which now completed has resulted in an increase to the 2021 transmission revenue requirement. In 2020, PECO's transmission revenue requirement included a one-time decrease in accordance with the December 5, 2019 settlement agreement related to refunds which now completed has resulted in an increase to the 2021 transmission revenue requirement.
(c)Represents the weighted average debt and equity return on transmission rate bases.
(d)As part of the FERC-approved settlements of ComEd’s 2007 and PECO's 2017 rate cases, the rate of return on common equity is 11.50% and 10.35%, respectively, inclusive of a 50-basis-point incentive adder for being a member of a RTO, and the common equity component of the ratio used to calculate the weighted average debt and equity return for the
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 3 — Regulatory Matters
For 2022, the following total increases/(decreases) were included in the Utility Registrants' electric transmission formula rate update:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Registrant(a) | | Initial Revenue Requirement Increase | | Annual Reconciliation (Decrease) Increase | | Total Revenue Requirement Increase | | Allowed Return on Rate Base(b) | | Allowed ROE(c) |
| ComEd | | $ | 24 | | | $ | (24) | | | $ | — | | | 8.11 | % | | 11.50 | % |
| PECO | | 23 | | | 16 | | | 39 | | | 7.30 | % | | 10.35 | % |
| BGE | | 25 | | | (4) | | | 16 | | (d) | 7.30 | % | | 10.50 | % |
| Pepco | | 16 | | | 15 | | | 31 | | | 7.60 | % | | 10.50 | % |
| DPL | | 9 | | | 2 | | | 11 | | | 7.09 | % | | 10.50 | % |
| ACE | | 21 | | | 13 | | | 34 | | | 7.18 | % | | 10.50 | % |
__________
(a)All rates are effective June 1, 2022 - May 31, 2023, subject to review by interested parties pursuant to review protocols of each Utility Registrants' tariff.
(b)Represents the weighted average debt and equity return on transmission rate bases. For ComEd and PECO, the common equity component of the ratio used to calculate the weighted average debt and equity return on the transmission formula rate base is currently capped at 55% and 55.75%, respectively. As part of the FERC-approved settlement of the ROE complaint against BGE, Pepco, DPL, and ACE, the
(c)The rate of return on common equity is 10.50%, inclusive offor each Utility Registrant includes a 50-basis-point incentive adder for being a member of a RTO.
(d)The increase in BGE's transmission revenue requirement includes a $5 million reduction related to a FERC-approved dedicated facilities charge to recover the costs of providing transmission service to specifically designated load by BGE.
Other State Regulatory Matters
IllinoisIllinois Regulatory Matters
Clean Energy LawCEJA (Exelon and ComEd). On September 15, 2021, the Governor of Illinois Public Act 102-0662 was signed into law by the Governor of Illinois (“Clean Energy Law”). The Clean Energy LawCEJA. CEJA includes, among other features, (1) procurement of carbon mitigation credits (CMCs)CMCs from qualifying nuclear-powered generating facilities, (2) a requirement to file a general rate case or a new four-year multi-year plan no later than January 20, 2023 to establish rates effective after ComEd’s existing performance-based distribution formula rate sunsets, (3) an extension of and certain adjustments to ComEd’s energy efficiency MWh savings goals, (4) revisions to the Illinois RPS requirements, including expanded charges for the procurement of RECs from wind and solar generation, (5) a requirement to accelerate amortization of ComEd’s unprotected excess deferred income taxes ("EDIT") that ComEd was previously directed by the ICC to amortize using the average rate assumption method which equates to approximately 39.5 years, and (6) requirements that ComEd and the ICC initiate and conduct various regulatory proceedings on subjects including ethics, spending, grid investments, and performance metrics. Regulatory or legal challenges regarding the validity or implementation of the Clean Energy LawCEJA are possible and Exelon Generation, and ComEd cannot reasonably predict the outcome of any such challenges.
Carbon Mitigation Credit
The Clean Energy LawCEJA establishes decarbonization requirements for Illinois as well as programs to support the retention and development of emissions-free sources of electricity. Among other things, the Clean Energy Law authorizes the IPAComEd is required to procure up to 54.5 millionpurchase CMCs from qualifying nuclear plants for a five-year period beginning onbetween June 1, 2022 throughand May 31, 2027. CMCs are credits for the carbon-free attributes2027 and all its costs of eligible nuclear power plants in PJM. The Byron, Dresden, and Braidwood nuclear plants located in Illinoisdoing so will be eligible to participate in the CMC procurement process and, if awarded contracts, would be committed to operaterecovered through May 31, 2027. Selected generators will by December 3, 2021 contract directly with ComEd for the procurement of the CMCs based upon the number of MWhs produced annually by the eligible facilities, subject to specified caps and minimum performance requirements.a new rider. The price to be paid for each CMC will be determinedwas established through a competitive bidding process that includesincluded consumer-protection measures that capcapped the maximum acceptable bid amount and a formula that reduces CMC prices by an energy price index, the base residual auction capacity price in the ComEd zone of PJM, and the monetized value of any federal tax credit or other subsidy if applicable. The consumer protection measures contained in the new lawCEJA will result in net payments to ComEd ratepayers if the energy index, the capacity price and applicable federal tax credits or subsidy exceed the maximum bid cap.
CMC contract price. ComEd is requiredbegan issuing credits to purchase CMCs from eligible nuclear facilitiesits retail customers under its new CMC rider in the June 2022 billing period and all its costsrecorded a regulatory asset of doing so will be recovered through a new rider. That rider will provide$255 million as of June 30, 2022 for an annual reconciliationthe difference between customer credits issued and true-up to actual costs incurred by ComEd to purchase CMCs, with any differencethe credit to be credited to or collected from ComEd’s retail customers in subsequent periods.
See Note 7 – Early Plant Retirements for the impacts of the provisions above on the Illinois nuclear plants and Generation’s consolidated financial statements. The provisions do not impact ComEd’s consolidated financial statements until 2022.
ComEd Electric Distribution Rates
The Clean Energy Law contains requirements associated with ComEd’s transition awayreceived from the performance-based electric distribution formula rate. The law authorizing that rate setting process sunsets at the end of 2022. The Clean Energy Law, and tariffs adopted under it, governs both the remaining reconciliations of rates set under that formula process and requires ComEd to file in 2023 its choice of either a general rate case or a four-year multi-year plan to set rates that take effect in 2024.
If ComEd elects to file a multi-year plan, that plan would set rates for 2024 – 2027, based on forecasted revenue requirements and an ICC determined rate of return on rate base, including the cost of common equity. Each year of the multi-year plan is subject to after the fact ICC review and reconciliation of the plan’s revenue requirement for that year with the actual costs that the ICC determines are prudently and reasonably incurred for that year.participating nuclear plants.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 3 — Regulatory Matters
That reconciliation is subject to adjustment for certain uncontrollable expenses and, unless the plan is modified, to a 5% cap on increases over the previously approved multi-year rate plan revenue requirement. ComEd would make its initial reconciliation filing in 2025, and the rate adjustments necessary to reconcile 2024 revenues to ComEd’s actual 2024 costs incurred would take effect in January 2026 after the ICC’s review. Excess Deferred Income Taxes
The ICC must also approve certain annual performance metrics, which can impose symmetrical performance adjustments in the total range of 20 to 60 basis points to ComEd’s rate of return on common equity based on the extent to which ComEd achieved the annual performance goals. ComEd will recover from retail customers, subject to certain exceptions, the costs it incurs pursuant to the Clean Energy Law either through its electric distribution rate or other recovery mechanisms.
The Clean Energy Law, among other things, also requires ComEd’s rates to include a decoupling mechanism to eliminate any impacts of weather or load from ComEd’s electric distribution rate revenues. The Clean Energy Law also requires the ICC to initiateinitiated a docket to accelerate and fully credit to customers TCJA unprotected property related TCJA excess deferred income taxesproperty-related EDIT no later than December 31, 2025.
Energy Efficiency
The Clean Energy Law extends ComEd’s current cumulative annual energy efficiency MWh savings goals On July 7, 2022, the ICC issued a final order on the schedule for the acceleration of EDIT amortization, adopting the proposal as submitted by several parties, including ComEd, ICC Staff, the Illinois Attorney General's Office, and the Citizens Utility Board. EDIT amortization will be credited to customers through 2040, adds expanded electrification measures to those goals, increases low-income commitments and adds a new performance adjustmentrider from January 1, 2023 through December 31, 2025.
Beneficial Electrification Plan
On July 1, 2022, ComEd filed a proposed plan to promote beneficial electrification efforts in its Northern Illinois service area with the energy efficiency formula rate.ICC as required by CEJA. ComEd's plan is designed to meaningfully reduce barriers to beneficial electrification, including those related to electric vehicles, such as upfront technology adoption costs, charging costs, and charging availability; promote equity and environmental justice; reduce carbon emissions and surface-level pollutants; and support customer education and awareness of electrification options. As proposed, ComEd expects its annual spend to increase in 2022 through 2040 to achieve these energy efficiency MWh savings goals, which will be deferred as a separate regulatory asset that will be recovered through the energy efficiency formula ratecould expend approximately $300 million over the weighted average useful life, as approvedthree-year period 2023 through 2025. The beneficial electrification plan requests recovery of all those costs through a rider mechanism, under which certain of the costs would be amortized over ten years with a return on the unrecovered balance. An order is expected to be issued by the ICC no later than the first quarter of 2023. At this time, ComEd cannot predict the outcome of these proceedings.
See Note 3 — Regulatory Matters of the related energy efficiency measures.2021 Recast Form 10-K for additional information on CEJA (referred to as Clean Energy Law).
Energy Efficiency Formula Rate (Exelon and ComEd). ComEd filed its annual energy efficiency formula rate update with the ICC on June 1, 2021.May 25, 2022. The filing establishes the revenue requirement used to set the rates that will take effect in January 20222023 after the ICC’sICC's review and approval. The requested revenue requirement update is based on a reconciliation of the 20202021 actual costs plus projected 20222023 expenditures.
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Initial Revenue Requirement Increase | | Annual Reconciliation Decrease | | Total Revenue Requirement Increase | | Requested Return on Rate Base(a) | | Requested ROE |
| $ | 55 | | | $ | (1) | | | $ | 54 | | | 5.72 | % | | 7.36 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Initial Revenue Requirement Increase | | Annual Reconciliation Decrease | | Total Revenue Requirement Increase | | Requested Return on Rate Base(a) | | Requested ROE |
| $ | 66 | | | $ | (16) | | | $ | 50 | | | 5.94 | % | | 7.85 | % |
__________
(a)The requested revenue requirement increase provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 5.72%5.94% inclusive of an allowed ROE of 7.36%7.85%, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points. For the 20202021 reconciliation year, the requested revenue requirement provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 6.26%5.52% inclusive of an allowed ROE of 8.46%6.99%, which includes an upwarda downward performance adjustment that increaseddecreased the ROE. The performance adjustment can either increase or decrease the ROE based upon the achievement of energy efficiency savings goals.
Maryland Regulatory Matters
Maryland Order Directing the Distribution of Energy Assistance Funds (Exelon, BGE, PHI, Pepco, and DPL). On June 15, 2021, the MDPSC issued an order authorizing the disbursal of funds to utilities in accordance with Maryland COVID-19 relief legislation. Under this order, BGE, Pepco, and DPL received funds of $50 million, $12 million, and $8 million, respectively, in July 2021. The funds have been used to reduce or eliminate certain qualifying past-due residential customer receivables.
New Jersey Regulatory Matters
Conservation Incentive Program (CIP)Termination of Energy Procurement Provisions of PPAs (Exelon, PHI, and ACE).
On September 25, 2020,December 22, 2021, ACE filed an application with the NJBPU asa petition to terminate the provisions in the PPAs to purchase electricity from two coal-powered generation facilities located in the state of New Jersey. The petition was required seeking approvalapproved by the NJBPU on March 23, 2022. Upon closing of the transaction on March 31, 2022, ACE recognized a liability of $203 million for the contract termination fee, which is to implementbe paid by the end of 2024, and recognized a portfoliocorresponding regulatory asset of energy efficiency programs pursuant to New Jersey’s clean energy legislation.$203 million.
As of June 30, 2022, the $180 million liability for the contract termination fee consists of $87 million and $93 million included in Other current liabilities and Other deferred credits and other liabilities, respectively, in Exelon's Consolidated Balance Sheet. The filingcurrent and noncurrent liability is included a request to implement a CIP that would eliminatein PPA termination obligation and Other deferred credits and other liabilities, respectively, in PHI's and ACE's Consolidated Balance Sheets. For the favorablesix months ended June 30, 2022, ACE has paid $23 million of the liability, which is recorded in Changes in Other assets and unfavorable impactsliabilities in Exelon's, PHI's, and ACE's Consolidated Statements of weather and customer usage patterns on distribution revenues for most customers. The CIP compares current distribution revenues by customer class to approved target revenues established in ACE’s most recent distribution base rate case. The CIP is calculated annually and recovery is subject to certain conditions, including an earnings test and ceilings on customer rate increases.Cash Flows.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 3 — Regulatory Matters
On April 27, 2021, the NJBPU approved the settlement filed by ACE and the third parties to the proceeding. The approved settlement addresses all material aspects of ACE’s filing, including ACE’s ability to implement the CIP prospectively effective July 1, 2021. As a result of this decoupling mechanism, operating revenues will no longer be impacted by abnormal weather or usage for most customers. Starting in third quarter of 2021, ACE will record alternative revenue program revenues for its best estimate of the distribution revenue impacts resulting from future changes in CIP rates that it believes are probable of approval by the NJBPU in accordance with this mechanism.
Advanced Metering Infrastructure Filing (Exelon, PHI, and ACE). On August 26, 2020, ACE filed an application with the NJBPU as was required seeking approval to deploy a smart energy network in alignment with New Jersey’s Energy Master Plan and Clean Energy Act. The proposal consisted of estimated costs totaling $220 million with deployment taking place over a 3-year implementation period from approximately 2021 to 2024 that involves the installation of an integrated system of smart meters for all customers accompanied by the requisite communications facilities and data management systems.
On July 14, 2021, the NJBPU approved the settlement filed by ACE and the third parties to the proceeding. The approved settlement addresses all material aspects of ACE's smart energy network deployment plan, including cost recovery of the investment costs, incremental O&M expenses, and the unrecovered balance of existing infrastructure through future distribution rates.
Illinois Regulatory Assets and LiabilitiesMatters
The Utility Registrants'CEJA (Exelon and ComEd). On September 15, 2021, the Governor of Illinois signed into law CEJA. CEJA includes, among other features, (1) procurement of CMCs from qualifying nuclear-powered generating facilities, (2) a requirement to file a general rate case or a new four-year multi-year plan no later than January 20, 2023 to establish rates effective after ComEd’s existing performance-based distribution formula rate sunsets, (3) an extension of and certain adjustments to ComEd’s energy efficiency MWh savings goals, (4) revisions to the Illinois RPS requirements, including expanded charges for the procurement of RECs from wind and solar generation, (5) a requirement to accelerate amortization of ComEd’s unprotected excess deferred income taxes ("EDIT") that ComEd was previously directed by the ICC to amortize using the average rate assumption method which equates to approximately 39.5 years, and (6) requirements that ComEd and the ICC initiate and conduct various regulatory assetsproceedings on subjects including ethics, spending, grid investments, and liabilities have not changed materially since December 31, 2020, unless noted below. See Note 3 —performance metrics. Regulatory Mattersor legal challenges regarding the validity or implementation of CEJA are possible and Exelon and ComEd cannot reasonably predict the Exelon 2020 Form 10-K for additional information on the specific regulatory assets and liabilities.outcome of any such challenges.
ComEd. Regulatory assets increased $93 million primarily dueCarbon Mitigation Credit
CEJA establishes decarbonization requirements for Illinois as well as programs to support the retention and development of emissions-free sources of electricity. ComEd is required to purchase CMCs between June 1, 2022 and May 31, 2027 and all its costs of doing so will be recovered through a new rider. The price to be paid for each CMC was established through a competitive bidding process that included consumer-protection measures that capped the maximum acceptable bid amount and a formula that reduces CMC prices by an increase of $47 millionenergy price index, the base residual auction capacity price in the Electric Distribution Formula Rate Annual ReconciliationsComEd zone of PJM, and the monetized value of any federal tax credit or other subsidy if applicable. The consumer protection measures contained in CEJA will result in net payments to ComEd ratepayers if the energy index, the capacity price and applicable federal tax credits or subsidy exceed the CMC contract price. ComEd began issuing credits to its retail customers under its new CMC rider in the June 2022 billing period and recorded a regulatory asset and $127of $255 million inas of June 30, 2022 for the Energy Efficiency Costs regulatory asset, partially offset by a decrease of $87 million in the renewable energy regulatory asset.
PECO. Regulatory assets increased $135 million primarily due to an increase of $123 million in the Deferred Income Taxes regulatory asset and $14 million in the Vacation Accrual regulatory asset. Regulatory liabilities increased by $66 million primarily due to an increase of $71 million in the Nuclear Decommissioning regulatory liability partially offset by a $18 million decrease in the Electric Energy and Natural Gas Costs regulatory liability.
BGE. Regulatory liabilities decreased $116 million primarily due to a decrease of $128 million in the Deferred Income Taxes regulatory liability offset by an increase of $12 million in Other regulatory liabilities.
Pepco. Regulatory liabilities decreased $108 million primarily due to a decrease of $89 million in the Deferred Income Taxes regulatory liability and $19 million in the Transmission Formula Rate regulatory liability.
DPL. Regulatory liabilities decreased $45 million primarily due to a decrease of $41 million in the Deferred Income Taxes regulatory liability.
ACE. Regulatory liabilities decreased $61 million primarily due to a decrease of $67 million in the Deferred Income Taxes regulatory liability partially offset by an increase of $14 million in the Stranded Costs regulatory liability.
Capitalized Ratemaking Amounts Not Recognized
The following table presents authorized amounts capitalized for ratemaking purposes related to earnings on shareholders’ investment that are not recognized for financial reporting purposes in Exelon'sdifference between customer credits issued and the Utility Registrant's Consolidated Balance Sheets. These amounts willcredit to be recognized as revenues inreceived from the related Consolidated Statements of Operations and Comprehensive Income in the periods they are billable to the Utility Registrants' customers.participating nuclear plants.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 3 — Regulatory Matters
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Exelon | | ComEd(a) | | PECO | | BGE(b) | | PHI | | Pepco(c) | | DPL(c) | | ACE |
| September 30, 2021 | $ | 44 | | | $ | — | | | $ | — | | | $ | 39 | | | $ | 5 | | | $ | 3 | | | $ | 2 | | | $ | — | |
| | | | | | | | | | | | | | | |
| December 31, 2020 | 51 | | | (1) | | | — | | | 45 | | | 7 | | | 4 | | | 3 | | | — | |
__________The ICC initiated a docket to accelerate and fully credit to customers TCJA unprotected property-related EDIT no later than December 31, 2025. On July 7, 2022, the ICC issued a final order on the schedule for the acceleration of EDIT amortization, adopting the proposal as submitted by several parties, including ComEd, ICC Staff, the Illinois Attorney General's Office, and the Citizens Utility Board. EDIT amortization will be credited to customers through a new rider from January 1, 2023 through December 31, 2025.
(a)ReflectsBeneficial Electrification Plan
On July 1, 2022, ComEd filed a proposed plan to promote beneficial electrification efforts in its Northern Illinois service area with the ICC as required by CEJA. ComEd's unrecognizedplan is designed to meaningfully reduce barriers to beneficial electrification, including those related to electric vehicles, such as upfront technology adoption costs, charging costs, and charging availability; promote equity returns/(losses) earned/(incurred) for ratemaking purposes on its electric distribution formula rate regulatory assets.
(b)BGE's authorized amounts capitalized for ratemaking purposes primarily relate to earnings on shareholders' investment on its AMI programs.
(c)Pepco's and DPL's authorized amounts capitalized for ratemaking purposes relate to earnings on shareholders' investment on their respective AMI Programsenvironmental justice; reduce carbon emissions and Energy Efficiencysurface-level pollutants; and Demand Response Programs.support customer education and awareness of electrification options. As proposed, ComEd could expend approximately $300 million over the three-year period 2023 through 2025. The earnings on energy efficiency are on Pepco DC and DPL DE programs only.
Generation Regulatory Matters (Exelon and Generation)
Impactsbeneficial electrification plan requests recovery of all those costs through a rider mechanism, under which certain of the February 2021 Extreme Cold Weather Event and Texas-based Generating Assets Outages
Beginning on February 15, 2021, Generation’s Texas-based generating assets within the ERCOT market, specifically Colorado Bend II, Wolf Hollow II, and Handley, experienced outages ascosts would be amortized over ten years with a result of extreme cold weather conditions. In addition, those weather conditions drove increased demand for service, dramatically increased wholesale power prices, and also increased gas prices in certain regions. In response to the high demand and significantly reduced total generationreturn on the system, the PUCT directed ERCOTunrecovered balance. An order is expected to use an administrative price cap of $9,000 per MWh during firm load shedding events.
The estimated impact to Exelon’s and Generation’s Net income for the nine months ended September 30, 2021 arising from these market and weather conditions was a reduction of approximately $880 million. The estimated impact to Exelon's and Generation's Net income for the three months ended September 30, 2021 was not material. The ultimate impact to Exelon’s and Generation’s consolidated financial statements for the full year 2021 may be affected by a number of factors, including the impacts of customer and counterparty credit losses, any state or federal solutions to address the financial challenges causedissued by the event, and related litigation and contract disputes.
During February and March 2021, various parties with differing interests, including generators and retail providers, filed requests withICC no later than the PUCT to void the PUCT’s orders setting prices at $9,000 per MWh during firm load shedding events. Other requests were made for the PUCT to enforce its order and reduce prices for 33 hours between February 18 and February 19 after firm load shedding ceased, and to cap ancillary services at $9,000 per MWh.On March 2, 2021, a third party filed a noticefirst quarter of appeal in the Court of Appeals for the Third District of Texas challenging the validity of the PUCT’s actions. Generation intervened in that appeal and filed its initial brief on June 2, 2021. On April 19, 2021, Generation filed a declaratory action and request for judicial review of the PUCT’s orders setting prices at $9,000 per MWh in District Court of Travis County, Texas. Generation subsequently requested that the District Court of Travis County, Texas stay its proceeding pending action by the Court of Appeals in the third party proceeding. On May 17, 2021, Generation amended its petition for declaratory action and request for judicial review pending in the District Court of Travis County, Texas. Exelon and Generation2023. At this time, ComEd cannot predict the outcome of these proceedings orproceedings.
See Note 3 — Regulatory Matters of the financial statement impact.2021 Recast Form 10-K for additional information on CEJA (referred to as Clean Energy Law).
DueEnergy Efficiency Formula Rate (Exelon and ComEd). ComEd filed its annual energy efficiency formula rate update with the ICC on May 25, 2022. The filing establishes the revenue requirement used to these events, a number of ERCOT market participants experienced bankruptcies or defaulted on payments to ERCOT, resultingset the rates that will take effect in approximately a $3.0 billion payment shortfall in collections, whichJanuary 2023 after the ICC's review and approval. The requested revenue requirement update is allocated to the remaining ERCOT market participants. As of September 30, 2021, Generation has recorded its estimated portion of this obligation of approximately $17 millionbased on a discountedreconciliation of the 2021 actual costs plus projected 2023 expenditures.
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Initial Revenue Requirement Increase | | Annual Reconciliation Decrease | | Total Revenue Requirement Increase | | Requested Return on Rate Base(a) | | Requested ROE |
| $ | 66 | | | $ | (16) | | | $ | 50 | | | 5.94 | % | | 7.85 | % |
__________
(a)The requested revenue requirement increase provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 5.94% inclusive of an allowed ROE of 7.85%, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points. For the 2021 reconciliation year, the requested revenue requirement provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 5.52% inclusive of an allowed ROE of 6.99%, which includes a downward performance adjustment that decreased the ROE. The performance adjustment can either increase or decrease the ROE based upon the achievement of energy efficiency savings goals.
New Jersey Regulatory Matters
Termination of Energy Procurement Provisions of PPAs (Exelon, PHI, and ACE).
On December 22, 2021, ACE filed with the NJBPU a petition to terminate the provisions in the PPAs to purchase electricity from two coal-powered generation facilities located in the state of New Jersey. The petition was approved by the NJBPU on March 23, 2022. Upon closing of the transaction on March 31, 2022, ACE recognized a liability of $203 million for the contract termination fee, which is to be paid overby the end of 2024, and recognized a termcorresponding regulatory asset of 83 years. ERCOT rules historically have limited recovery$203 million.
As of default from market participants to $2.5June 30, 2022, the $180 million per month market-wide. In February 2021, the PUCT gave ERCOT discretion to disregard those rules, but ERCOT has declined to exercise that discretion thus far. On March 8, 2021, a third party filed a notice of appeal in the Court of Appealsliability for the Third Districtcontract termination fee consists of Texas challenging$87 million and $93 million included in Other current liabilities and Other deferred credits and other liabilities, respectively, in Exelon's Consolidated Balance Sheet. The current and noncurrent liability is included in PPA termination obligation and Other deferred credits and other liabilities, respectively, in PHI's and ACE's Consolidated Balance Sheets. For the validitysix months ended June 30, 2022, ACE has paid $23 million of the PUCT's order to ERCOTliability, which is recorded in February 2021. Generation intervenedChanges in that appealOther assets and filed its initial brief on July 7, 2021. On May 7, 2021, Generation filed a declaratory actionliabilities in Exelon's, PHI's, and request for judicial reviewACE's Consolidated Statements of the PUCT's order in the District Court of Travis County, Texas. Generation subsequently requested that the District Court of Travis County, Texas stay its proceeding pending action by the Court of Appeals in the third party proceeding. Exelon and Generation cannot predict the outcome of these proceedings or the financial statement impact.Cash Flows.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 3 — Regulatory Matters
Additionally, several legislative proposals were introduced in the Texas legislature during February and March 2021 concerning the amount, timing and allocation of recovery of the $3.0 billion shortfall, as well as recovery of other costs associated with the PUCT's directive to set prices at $9,000 per MWh. Two of these proposals were enacted into law in June 2021 and establish financing mechanisms that ERCOT and certain market participants can utilize to fund amounts owed to ERCOT. Generation participated in proceedings before the PUCT addressing the proposed allocation of the $2.1 billion in securitized funds for reliability and ancillary service charges over $9,000/MWh. In September 2021, Generation entered into a settlement agreement and stipulation to resolve the allocation issues. The PUCT approved the settlement agreement and stipulation on October 13, 2021.
In addition, other legislative proposals were introduced in the Texas legislature during February and March 2021 addressing cold-weather preparation for power plants and natural gas production and transportation infrastructure and the market structure for reliability services. The Texas legislature addressed these proposals by enacting a bill with a broad set of market reforms that, among other things, directed the PUCT to establish weatherization standards for electric generators within six months of enactment and gave the PUCT authority to impose administrative penalties if the new proposed standards, once adopted, are not met. On October 21, 2021, the PUCT adopted rule change requiring generators by December 1, 2021 to complete a number of specified winter readiness preparations and to submit to ERCOT a report describing and certifying the completion of those preparations. The PUCT described these requirements as the first phase of its actions with respect to winter preparedness, to be followed by a second phase consisting of a year-round set of weather preparedness standards to be informed by a weather study that is being conducted by ERCOT.
The legislation also directs the PUCT to evaluate whether additional ancillary services are needed for reliability in the ERCOT power region to provide adequate incentives for dispatchable generation. Exelon and others have submitted various proposals to the PUCT with respect to a range of potential market reforms, including the implementation of additional ancillary service products as well as changes to the high system-wide offer cap and operating reserve demand curve, which remain pending. On September 23, 2021, the PUCT solicited comments regarding whether it should set ERCOT’s high system-wide offer cap at $4,500/MWh if the PUCT takes action to amend its rules with respect to that cap. Exelon and others submitted comments to the PUCT, which remain pending. The PUCT is expected to address potential changes to ERCOT’s market rules later in 2021.
In February 2021, more than 70 local distribution companies (LDCs) and natural gas pipelines in multiple states throughout the mid-continent region, where Generation serves natural gas customers, issued operational flow orders (OFOs), curtailments or other limitations on natural gas transportation or use to manage the operational integrity of the applicable LDC or pipeline system. When in effect, gas transportation or use above these limitations is subject to significant penalties according to the applicable LDCs’ and natural gas pipelines’ tariffs. Gas transportation and supply in many states became restricted due to wells freezing and pipeline compression disruption, while demand was increasing due to the extreme cold temperatures, resulting in extremely high natural gas prices. Due to the extraordinary circumstances, many LDCs and natural gas pipelines have either voluntarily waived or have sought applicable regulatory approvals to waive the tariff penalties associated with the extreme weather event. During March 2021, three natural gas pipelines filed individual petitions with FERC requesting approval to waive OFO penalties. Generation also filed motions in March 2021 to intervene and filed comments in support of these FERC waiver requests. On March 25, 2021, FERC issued an order on one of the petitions approving a pipeline’s request for a limited waiver of penalties for February 15, 2021. On April 23, 2021, Generation and several other entities filed a request at FERC for rehearing of this order which was denied on May 24, 2021. Generation and the other entities filed an appeal of the rehearing of the order with the U.S. Court of Appeals for the D.C. Circuit on July 21, 2021. Additionally, Generation and the other entities filed a complaint requesting that FERC expand the order to include additional days of the weather event in February, from February 16 through February 19, 2021. On October 21, 2021, FERC denied the complaint finding that a pipeline has the discretion whether to waive penalties under its tariff. Generation is evaluating whether to seek rehearing and appeal of the FERC order. During April 2021, FERC issued orders on the remaining petitions approving the requests to waive the penalties. During May 2021, an LDC filed a motion with the Kansas Corporation Commission (KCC) requesting the KCC to grant a waiver from the tariff and allow the LDC to reduce the amounts assessed by permitting the removal of a multiplier from the penalty calculation. On October 8, 2021, a settlement was filed with the KCC that, if approved, would resolve this matter. Exelon and Generation cannot predict the outcome of the pending FERC complaint proceeding, the KCC proceeding, or the determinations made by the LDCs and natural gas pipelines.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)
Note 3 — Regulatory Matters
Illinois Regulatory Matters
Clean Energy LawCEJA (Exelon and ComEd). . See Clean Energy Law above for additional information relatedOn September 15, 2021, the Governor of Illinois signed into law CEJA. CEJA includes, among other features, (1) procurement of CMCs from qualifying nuclear-powered generating facilities, (2) a requirement to Generation. See Note 7 – Early Plant Retirements for additional information on Generation’s Illinois nuclear plants.
New Jersey Regulatory Matters
New Jersey Clean Energy Legislation. On May 23, 2018, New Jersey enacted legislation that establishedfile a ZEC program that provides compensation for nuclear plants that demonstrategeneral rate case or a new four-year multi-year plan no later than January 20, 2023 to establish rates effective after ComEd’s existing performance-based distribution formula rate sunsets, (3) an extension of and certain adjustments to ComEd’s energy efficiency MWh savings goals, (4) revisions to the NJBPU that they meet certainIllinois RPS requirements, including expanded charges for the procurement of RECs from wind and solar generation, (5) a requirement to accelerate amortization of ComEd’s unprotected excess deferred income taxes ("EDIT") that they make a significant contributionComEd was previously directed by the ICC to air quality inamortize using the stateaverage rate assumption method which equates to approximately 39.5 years, and (6) requirements that their revenues are insufficient to cover their costs and risks. Under the legislation, the NJBPU will issue ZECs to qualifying nuclear power plantsComEd and the electric distribution utilities in New Jersey,ICC initiate and conduct various regulatory proceedings on subjects including ACE, will be required to purchase those ZECs. On April 18, 2019,ethics, spending, grid investments, and performance metrics. Regulatory or legal challenges regarding the NJBPU approved the awardvalidity or implementation of ZECs to Salem 1CEJA are possible and Salem 2. Upon approval, Generation began recognizing revenue for the sale of New Jersey ZECs in the month they are generated. On March 19, 2021, a three-judge panel of the Superior Court of New Jersey Appellate Division unanimously affirmed the NJBPU’s April 2019 order awarding ZECs for the first eligibility period. On April 8, 2021, New Jersey Rate Counsel filed a notice asking the New Jersey Supreme Court to hear the appeal of the Superior Court’s order. On July 9, 2021, the New Jersey Supreme Court declined to hear the appeal. On October 1, 2020, PSEG and Generation filed applications seeking ZECs for the second eligibility period (June 2022 through May 2025). On April 27, 2021, the NJBPU approved the award of ZECs to Salem 1 and Salem 2 for the second eligibility period. On May 11, 2021, the New Jersey Rate Counsel appealed the April 27, 2021 decision to the Superior Court of New Jersey Appellate Division. Briefing on the appeal is expected to conclude in the fourth quarter of 2021 or first quarter of 2022. Exelon and GenerationComEd cannot reasonably predict the outcome of this proceeding.any such challenges.
New England Regulatory MattersCarbon Mitigation Credit
Mystic Units 8CEJA establishes decarbonization requirements for Illinois as well as programs to support the retention and 9 and Everett Marine Terminal Costdevelopment of Service Agreement. On March 29, 2018, Generation notified grid operator ISO-NEemissions-free sources of its planselectricity. ComEd is required to early retire Mystic Units 8 and 9 absent regulatory reforms on June 1, 2022. On May 16, 2018, Generation made a filing with FERC to establish cost-of-service compensation and terms and conditions of service for Mystic Units 8 & 9 for the periodpurchase CMCs between June 1, 2022 -and May 31, 2024. On December 20, 2018, FERC issued an order accepting the cost2027 and all its costs of service compensation, reflecting a number of adjustments to the annual fixed revenue requirement and allowing for recovery of a substantial portion of the costs associated with the adjacent Everett Marine Terminal acquired by Generation in October 2018. Those adjustments were reflected in a compliance filing made on March 1, 2019. In the December 20, 2018 order, FERC also directed a paper hearing on ROE usingdoing so will be recovered through a new methodology. On January 22, 2019, Exelonrider. The price to be paid for each CMC was established through a competitive bidding process that included consumer-protection measures that capped the maximum acceptable bid amount and several other parties filed requests for rehearing of certain findingsa formula that reduces CMC prices by an energy price index, the base residual auction capacity price in the order. On July 15, 2021, FERCComEd zone of PJM, and the monetized value of any federal tax credit or other subsidy if applicable. The consumer protection measures contained in CEJA will result in net payments to ComEd ratepayers if the energy index, the capacity price and applicable federal tax credits or subsidy exceed the CMC contract price. ComEd began issuing credits to its retail customers under its new CMC rider in the June 2022 billing period and recorded a regulatory asset of $255 million as of June 30, 2022 for the difference between customer credits issued an order establishingand the ROEcredit to be used inreceived from the cost of service agreement for Mystic 8 and 9 at 9.33%. On August 16, 2021, Exelon and several other parties filed requests for rehearing of certain aspects of the July 15, 2021 order. These requests were denied by operation of law; however, FERC indicated it would address the issues raised in the request in a future order.
On July 17, 2020, FERC issued three orders, which together affirmed the recovery of key elements of Mystic's cost of service compensation, including recovery of costs associated with the operation of the Everett Marine Terminal. FERC directed a downward adjustment to the rate base for Mystic Units 8 and 9, the effect of which will be partially offset by elimination of a crediting mechanism for third party gas sales during the term of the cost of service agreement. In addition, several parties filed protests to a compliance filing by Generation on September 15, 2020, taking issue with how gross plant in-service was calculated, and Generation filed an answer to the protests on October 21, 2020. On December 21, 2020, FERC issued an order on rehearing of the three July 17, 2020 orders, clarifying several cost of service provisions. Several parties appealed the December 21, 2020 order to the U.S. Court of Appeals for the D.C. Circuit and that appeal was consolidated with appeals of orders issued December 20, 2018 and July 17, 2020 in the Mystic proceeding. Briefs in support of their petitions for review were filed by Exelon and several other parties on September 7, 2021. Briefing is expected to conclude in February 2022.
On February 25, 2021, Mystic made its filing to comply with the December 21, 2020 order. On April 26, 2021, FERC rejected Mystic’s language and directed another compliance filing relating to the claw back provision language, which only applies if Mystic 8 and 9 were to continue operation after the conclusion of the cost-of-service period. FERC’s April 26, 2021 order also accepted in part and rejected in part Mystic’s September 15, 2020 compliance filing. It directed a further compliance filing in 60 days consistent with the information providedparticipating nuclear plants.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 3 — Regulatory Matters
Excess Deferred Income Taxes
The ICC initiated a docket to accelerate and fully credit to customers TCJA unprotected property-related EDIT no later than December 31, 2025. On July 7, 2022, the ICC issued a final order on the schedule for the acceleration of EDIT amortization, adopting the proposal as submitted by several parties, including ComEd, ICC Staff, the Illinois Attorney General's Office, and the Citizens Utility Board. EDIT amortization will be credited to customers through a new rider from January 1, 2023 through December 31, 2025.
Beneficial Electrification Plan
On July 1, 2022, ComEd filed a proposed plan to promote beneficial electrification efforts in Mystic’s October 21, 2020 answer to protests, which Mystic filed on June 2, 2021 and FERC accepted on July 29, 2021. On August 16, 2021, Mystic made a compliance filing, reflecting changes to the cost ofits Northern Illinois service agreement to complyarea with the July 15, 2021 order on ROE.
On August 25, 2020,ICC as required by CEJA. ComEd's plan is designed to meaningfully reduce barriers to beneficial electrification, including those related to electric vehicles, such as upfront technology adoption costs, charging costs, and charging availability; promote equity and environmental justice; reduce carbon emissions and surface-level pollutants; and support customer education and awareness of electrification options. As proposed, ComEd could expend approximately $300 million over the three-year period 2023 through 2025. The beneficial electrification plan requests recovery of all those costs through a group of New England generators filed a complaint against Generation seeking to extend the scoperider mechanism, under which certain of the claw back provision incosts would be amortized over ten years with a return on the cost-of-service agreement, whereby Generation would refund certain amounts recovered duringunrecovered balance. An order is expected to be issued by the termICC no later than the first quarter of 2023. At this time, ComEd cannot predict the costoutcome of service if it returns to market afterwards. On April 15, 2021 FERC dismissed the complaint.
On February 16, 2021, Generation filed an unopposed motion to voluntarily dismiss an appeal filed with the U.S. Court of Appeals for the D.C. Circuit stemming from a June 2020 complaint filed with FERC against ISO-NE over failures to follow its tariff in evaluating Mystic for transmission security for the 2024 to 2025 Capacity Commitment Period, which was granted on February 18, 2021.these proceedings.
See Note 73 — Early Plant RetirementsRegulatory Matters of the 2021 Recast Form 10-K for additional information on CEJA (referred to as Clean Energy Law).
Energy Efficiency Formula Rate (Exelon and ComEd). ComEd filed its annual energy efficiency formula rate update with the impacts of Generation’s August 2020 decisionICC on May 25, 2022. The filing establishes the revenue requirement used to retire Mystic Units 8set the rates that will take effect in January 2023 after the ICC's review and 9 upon expirationapproval. The requested revenue requirement update is based on a reconciliation of the cost2021 actual costs plus projected 2023 expenditures.
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Initial Revenue Requirement Increase | | Annual Reconciliation Decrease | | Total Revenue Requirement Increase | | Requested Return on Rate Base(a) | | Requested ROE |
| $ | 66 | | | $ | (16) | | | $ | 50 | | | 5.94 | % | | 7.85 | % |
__________
(a)The requested revenue requirement increase provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of service agreement.5.94% inclusive of an allowed ROE of 7.85%, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points. For the 2021 reconciliation year, the requested revenue requirement provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 5.52% inclusive of an allowed ROE of 6.99%, which includes a downward performance adjustment that decreased the ROE. The performance adjustment can either increase or decrease the ROE based upon the achievement of energy efficiency savings goals.
FederalNew Jersey Regulatory Matters
PJMTermination of Energy Procurement Provisions of PPAs (Exelon, PHI, and NYISO MOPR Proceedings. PJM and NYISO capacity markets include a MOPR. If a resource is subjected to a MOPR, its offer is adjusted to effectively remove the revenues it receives through a state government-provided financial support program - resulting in a higher offer that may not clear the capacity market. Prior to December 19, 2019, the MOPR in PJM applied only to certain new gas-fired resources. Currently, the MOPR in NYISO applies only to certain resources in downstate New York.
For Generation’s nuclear facilities in PJM and NYISO that are currently receiving state-supported compensation for carbon-free attributes, an expanded MOPR would require exclusion of such compensation when bidding into future capacity auctions, resulting in an increased risk of these facilities not receiving capacity revenues in future auctions.ACE).
On December 19, 2019, FERC required PJM22, 2021, ACE filed with the NJBPU a petition to broadly applyterminate the MOPRprovisions in the PPAs to all new and existing resources including nuclear, renewables, demand response, energy efficiency, storage, and all resources ownedpurchase electricity from two coal-powered generation facilities located in the state of New Jersey. The petition was approved by vertically-integrated utilities. This greatly expanded the breadth and scopeNJBPU on March 23, 2022. Upon closing of PJM’s MOPR, which became effective asthe transaction on March 31, 2022, ACE recognized a liability of PJM’s capacity auction$203 million for the 2022-23 planning year. While FERC included some limited exemptions, no exemptions were availablecontract termination fee, which is to state-supported nuclear resources.be paid by the end of 2024, and recognized a corresponding regulatory asset of $203 million.
FERC provided no new mechanism for accommodating state-supported resources other thanAs of June 30, 2022, the existing FRR mechanism (under which an entire utility zone would be removed from PJM’s capacity auction along with sufficient resources to support the load in such zone). In response to FERC’s order, PJM submitted a compliance filing on March 18, 2020 wherein PJM proposed tariff language interpreting and implementing FERC's directives, and proposed a schedule for resuming capacity auctions that is contingent on the timing of FERC's action on the compliance filing.
On April 16, 2020, FERC issued an order largely denying most requests for rehearing of FERC's December 2019 order but granting a few clarifications that required an additional PJM compliance filing which PJM submitted on June 1, 2020.
A number of parties, including Exelon, have filed petitions for review of FERC's orders in this proceeding, which remain pending before the Court of Appeals$180 million liability for the Districtcontract termination fee consists of Columbia Circuit.
As a result,$87 million and $93 million included in Other current liabilities and Other deferred credits and other liabilities, respectively, in Exelon's Consolidated Balance Sheet. The current and noncurrent liability is included in PPA termination obligation and Other deferred credits and other liabilities, respectively, in PHI's and ACE's Consolidated Balance Sheets. For the MOPR applied in the capacity auction for the 2022-23 planning year to Generation's owned or jointly owned nuclear plants in those states receiving a benefit under the Illinois ZES and the New Jersey ZEC program. The MOPR prevented Quad Cities from clearing in that capacity auction.
At the directionsix months ended June 30, 2022, ACE has paid $23 million of the PJM Boardliability, which is recorded in Changes in Other assets and liabilities in Exelon's, PHI's, and ACE's Consolidated Statements of Managers, PJM and its stakeholders developed further MOPR reforms to ensure that the capacity market rules respect and accommodate state resource preferences such as the ZEC programs. PJM filed related tariff revisions at FERC on July 30, 2021 and, on September 29, 2021, PJM's proposed MOPR reforms became effective by operation of law. Under the new tariff provisions, the MOPR will no longer apply to any of Generation’s owned or jointly owned nuclear plants. A request for rehearing of FERC’sCash Flows.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 3 — Regulatory Matters
notice establishing the effective date for PJM’s proposed market reforms was filed on October 5,Regulatory Assets and Liabilities
The Utility Registrants' regulatory assets and liabilities have not changed materially since December 31, 2021, and remains pending.
On February 20, 2020, FERC issued an order rejecting requests to expand NYISO’s versionunless noted below. See Note 3 — Regulatory Matters of the MOPR (referred2021 Recast Form 10-K for additional information on the specific regulatory assets and liabilities.
ComEd. Regulatory assets increased $254 million primarily due to as buyer-side mitigation rules) beyond its current limited applicability to certain resources in downstate. However, on October 14, 2020, two natural gas-fired generators in New York filed a complaint at FERC seeking to expand the MOPR in NYISO to apply to all resources, new and existing, across the entire NYISO market. Exelon is strenuously opposing expansionan increase of FERC’s MOPR policies$255 million in the NYISO market. While it is too earlyCMC regulatory asset, as discussed in CEJA above, $89 million in the proceeding to predict its outcomeElectric Distribution Formula Rate Annual Reconciliations regulatory asset, and there are significant differences between the NYISO and PJM markets that would justify a different result, if FERC applies the MOPR in NYISO broadly as requested$29 million in the complaint, Generation’s facilitiesEnergy Efficiency Costs regulatory asset partially offset by a decrease of $116 million in NYISOthe Renewable Energy regulatory asset. Regulatory liabilities decreased $617 million primarily due to a decrease of $788 million in the Decommissioning the Regulatory Agreement Units regulatory liability and $45 million in the Deferred Income Taxes regulatory liability partially offset by an increase of $162 million in the Renewable Portfolio Standards Costs regulatory liability and $33 million in the Removal Costs regulatory liability.
PECO. Regulatory assets increased $103 million primarily due to an increase of $99 million in the Deferred Income Taxes regulatory asset. Regulatory liabilities decreased $325 million primarily due to a decrease of $305 million in the Decommissioning the Regulatory Agreement Units regulatory liability and $12 million in the Electric Energy and Natural Gas Costs regulatory liability.
BGE. Regulatory assets decreased $49 million primarily due to a decrease of $20 million in the Under-recovered revenue decoupling regulatory asset, $14 million in the Electric Energy and Natural Gas Costs regulatory asset, and $13 million in the Energy Efficiency and Demand Response Programs regulatory asset.
Pepco. Regulatory assets decreased $47 million primarily due to a decrease of $20 million in the Under-recovered revenue decoupling regulatory asset, $17 million in the DC PLUG Charge regulatory asset, and $10 million in the Energy Efficiency and Demand Response Programs regulatory asset. Regulatory liabilities decreased $44 million primarily due to a decrease of $46 million in the Deferred Income Taxes regulatory liability.
ACE. Regulatory assets increased $179 million primarily due to an increase in the Electric Energy Costs regulatory asset as a result of the PPA termination. Regulatory liabilities decreased $16 million primarily due to a decrease of $13 million in the Deferred Income Taxes regulatory liability.
Capitalized Ratemaking Amounts Not Recognized
The following table presents authorized amounts capitalized for ratemaking purposes related to earnings on shareholders' investment that are receiving ZEC compensation maynot recognized for financial reporting purposes in the Registrants' Consolidated Balance Sheets. These amounts will be at increased riskrecognized as revenues in the related Consolidated Statements of not clearingOperations and Comprehensive Income in the capacity auction.
If Generation’s state-supported nuclear plants in PJM or NYISOperiods they are subjectedbillable to the MOPR or equivalent without compensation under an FRR or similar program, it could have a material adverse impactUtility Registrants' customers.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Exelon | | ComEd(a) | | PECO | | BGE(b) | | PHI | | Pepco(c) | | DPL(c) | | ACE |
| June 30, 2022 | $ | 49 | | | $ | 4 | | | $ | — | | | $ | 32 | | | $ | 13 | | | $ | 11 | | | $ | 2 | | | $ | — | |
| | | | | | | | | | | | | | | |
| December 31, 2021 | 43 | | | 1 | | | — | | | 37 | | | 5 | | | 3 | | | 2 | | | — | |
__________
(a)Reflects ComEd's unrecognized equity returns earned for ratemaking purposes on Exelon'sits energy efficiency and Generation's financial statements, which Exelonelectric distribution formula rate regulatory assets.
(b)BGE's authorized amounts capitalized for ratemaking purposes primarily relate to earnings on shareholder's investment on its AMI programs.
(c)Pepco's and Generation cannot reasonably estimate at this time.
Operating License Renewals
Conowingo Hydroelectric Project. On August 29, 2012, Generation submitted an applicationDPL's authorized amounts capitalized for ratemaking purposes relate to FERCearnings on shareholder's investment on their respective AMI Programs and Energy Efficiency and Demand Response Programs, and for a new license for the Conowingo Hydroelectric Project (Conowingo). In connection with Generation’s efforts to obtain a water quality certification pursuant to Section 401Pepco District of the Clean Water Act (401 Certification) from MDE for Conowingo, Generation had been working with MDEColumbia revenue decoupling program. The earnings on energy efficiency are on Pepco District of Columbia and other stakeholders to resolve water quality licensing issues, including: (1) water quality, (2) fish habitat, and (3) sediment.DPL Delaware programs only.
On April 27, 2018, MDE issued its 401 Certification for Conowingo. On October 29, 2019, Generation and MDE filed with FERC a Joint Offer of Settlement (Offer of Settlement) that would resolve all outstanding issues relating to the 401 Certification. Pursuant to the Offer of Settlement, the parties submitted Proposed License Articles to FERC to be incorporated by FERC into the new license in accordance with FERC’s discretionary authority under the Federal Power Act.
On March 19, 2021, FERC issued a new 50-year license for Conowingo, effective March 1, 2021. FERC adopted the Proposed License Articles into the new license only making modifications it deemed necessary to allow FERC to enforce the Proposed License Articles. Consistent with the Offer of Settlement, FERC found that MDE waived its 401 Certification. On April 19, 2021, a few environmental groups filed with FERC a petition for rehearing requesting that FERC reconsider the issuance of the new Conowingo license, which was denied by operation of law on May 20, 2021. On June 17, 2021, the petitioners appealed FERC’s ruling to the United States Court of Appeals. On July 15, 2021, FERC issued an order addressing the arguments raised on rehearing, affirming the determinations of its March 19, 2021 order. Generation cannot predict the outcome of this proceeding.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 4 — Revenue from Contracts with Customers
4. Revenue from Contracts with Customers (All Registrants)
The Registrants recognize revenue from contracts with customers to depict the transfer of goods or services to customers at an amount that the entities expect to be entitled to in exchange for those goods or services. Generation’s primary sources of revenue include competitive sales of power, natural gas, and other energy-related products and services. The Utility Registrants’ primary sources of revenue include regulated electric and gas tariff sales, distribution, and transmission services.
See Note 4 — Revenue from Contracts with Customers of the Exelon 20202021 Recast Form 10-K for additional information regarding the primary sources of revenue for the Registrants.
Contract Balances (All Registrants)
Contract Assets
Generation records contract assets for the revenue recognized on the construction and installation of energy efficiency assets and new power generating facilities before Generation has an unconditional right to bill for and
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)
Note 4 — Revenue from Contracts with Customers
receive the consideration from the customer. These contract assets are subsequently reclassified to receivables when the right to payment becomes unconditional. Generation records contract assets and contract receivables in Other current assets and Customer accounts receivable, net, respectively, in Exelon’s and Generation’s Consolidated Balance Sheets.
The following table provides a rollforward of the contract assets reflected in Exelon's and Generation's Consolidated Balance Sheets for the three and nine months ended September 30, 2021 and 2020. The Utility Registrants do not have any contract assets.
| | | | | | | | | | | | | | | | | | |
| | | | |
| | Exelon | | Generation | | | | |
| Balance as of December 31, 2020 | | $ | 144 | | | $ | 144 | | | | | |
| Amounts reclassified to receivables | | (16) | | | (16) | | | | | |
| Revenues recognized | | 13 | | | 13 | | | | | |
| Amounts previously held-for-sale | | 12 | | | 12 | | | | | |
| Balance as of March 31, 2021 | | 153 | | | 153 | | | | | |
| Amounts reclassified to receivables | | (12) | | | (12) | | | | | |
| Revenues recognized | | 9 | | | 9 | | | | | |
| Balance as of June 30, 2021 | | 150 | | | 150 | | | | | |
| Amounts reclassified to receivables | | (15) | | | (15) | | | | | |
| Revenues recognized | | 14 | | | 14 | | | | | |
| | | | | | | | |
| Balance as of September 30, 2021 | | $ | 149 | | | $ | 149 | | | | | |
| | | | | | | | |
| | | | | | | | |
| | Exelon | | Generation | | | | |
| Balance as of December 31, 2019 | | $ | 174 | | | $ | 174 | | | | | |
| Amounts reclassified to receivables | | (19) | | | (19) | | | | | |
| Revenues recognized | | 17 | | | 17 | | | | | |
| | | | | | | | |
| Balance as of March 31, 2020 | | 172 | | | 172 | | | | | |
| Amounts reclassified to receivables | | (26) | | | (26) | | | | | |
| Revenues recognized | | 13 | | | 13 | | | | | |
| Balance as of June 30, 2020 | | 159 | | | 159 | | | | | |
| Amounts reclassified to receivables | | (18) | | | (18) | | | | | |
| Revenues recognized | | 19 | | | 19 | | | | | |
| Balance as of September 30, 2020 | | $ | 160 | | | $ | 160 | | | | | |
Contract Liabilities
The Registrants record contract liabilities when consideration is received or due prior to the satisfaction of the performance obligations. The Registrants record contract liabilities in Other current liabilities and Other noncurrent liabilities in the Registrants'their Consolidated Balance Sheets.
For Generation, these contract liabilities primarily relate to upfront consideration received or due for equipment service plans and the Illinois ZEC program that introduces a cap on the total consideration to be received by Generation.
For PHI, Pepco, DPL, and ACE these contract liabilities primarily relate to upfront consideration received in the third quarter of 2020 for a collaborative arrangement with an unrelated owner and manager of communication infrastructure. The revenue attributable to this arrangement will be recognized as operating revenue over the 35 years under the collaborative arrangement.
The following table provides a rollforward of the contract liabilities reflected in Exelon's, Generation's, PHI's, Pepco's, DPL's, and ACE's Consolidated Balance Sheets for the three and ninesix months ended SeptemberJune 30, 20212022 and 2020.2021. As of SeptemberJune 30, 20212022 and December 31, 2020,2021, ComEd's, PECO's, and BGE's contract liabilities were immaterial.
70
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | |
| | Exelon(a) | | PHI(a) | | Pepco(a) | | DPL | | ACE(a) |
| Balance as of December 31, 2021 | | $ | 109 | | | $ | 109 | | | $ | 87 | | | $ | 11 | | | $ | 11 | |
| Revenues recognized | | (2) | | | (2) | | | (2) | | | — | | | — | |
| Balance as of March 31, 2022 | | 107 | | | 107 | | | 85 | | | 11 | | | 11 | |
| Revenues recognized | | (2) | | | (2) | | | (1) | | | — | | | (1) | |
| Balance as of June 30, 2022 | | $ | 105 | | | $ | 105 | | | $ | 84 | | | $ | 11 | | | $ | 10 | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | Exelon(a) | | PHI(a) | | Pepco(a) | | DPL(a) | | ACE(a) |
| Balance as of December 31, 2020 | | $ | 118 | | | $ | 118 | | | $ | 94 | | | $ | 12 | | | $ | 12 | |
| Revenues recognized | | (2) | | | (2) | | | (2) | | | — | | | — | |
| Balance as of March 31, 2021 | | 116 | | | 116 | | | 92 | | | 12 | | | 12 | |
| Revenues recognized | | (3) | | | (3) | | | (1) | | | (1) | | | (1) | |
| Balance as of June 30, 2021 | | $ | 113 | | | $ | 113 | | | $ | 91 | | | $ | 11 | | | $ | 11 | |
| | | | | | | | | | |
| | | | | | | | | | |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)
Note 4 — Revenue from Contracts with Customers
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | |
| | Exelon | | Generation | | PHI | | Pepco | | DPL | | ACE |
| Balance as of December 31, 2020 | | $ | 151 | | | $ | 84 | | | $ | 118 | | | $ | 94 | | | $ | 12 | | | $ | 12 | |
| Consideration received or due | | 20 | | | 31 | | | — | | | — | | | — | | | — | |
| Revenues recognized | | (27) | | | (64) | | | (2) | | | (2) | | | — | | | — | |
| Amounts previously held-for-sale | | 3 | | | 3 | | | — | | | — | | | — | | | — | |
| Balance as of March 31, 2021 | | 147 | | | 54 | | | 116 | | | 92 | | | 12 | | | 12 | |
| Consideration received or due | | 17 | | | 39 | | | — | | | — | | | — | | | — | |
| Revenues recognized | | (32) | | | (68) | | | (3) | | | (1) | | | (1) | | | (1) | |
| | | | | | | | | | | | |
| Balance as of June 30, 2021 | | 132 | | | 25 | | | 113 | | | 91 | | | 11 | | | 11 | |
| Consideration received or due | | 31 | | | 93 | | | — | | | — | | | — | | | — | |
| Revenues recognized | | (26) | | | (65) | | | (2) | | | (2) | | | — | | | — | |
| Balance as of September 30, 2021 | | $ | 137 | | | $ | 53 | | | $ | 111 | | | $ | 89 | | | $ | 11 | | | $ | 11 | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | Exelon | | Generation | | PHI | | Pepco | | DPL | | ACE |
| Balance as of December 31, 2019 | | $ | 33 | | | $ | 71 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
| Consideration received or due | | 20 | | | 55 | | | — | | | — | | | — | | | — | |
| Revenues recognized | | (24) | | | (70) | | | — | | | — | | | — | | | — | |
| Balance as of March 31, 2020 | | 29 | | | 56 | | | — | | | — | | | — | | | — | |
| Consideration received or due | | 13 | | | 34 | | | — | | | — | | | — | | | — | |
| Revenues recognized | | (22) | | | (63) | | | — | | | — | | | — | | | — | |
| Balance as of June 30, 2020 | | 20 | | | 27 | | | — | | | — | | | — | | | — | |
| Consideration received or due | | 154 | | | 94 | | | 124 | | | 98 | | | 13 | | | 13 | |
| Revenues recognized | | (25) | | | (65) | | | (2) | | | (2) | | | — | | | — | |
| Balance as of September 30, 2020 | | $ | 149 | | | $ | 56 | | | $ | 122 | | | $ | 96 | | | $ | 13 | | | $ | 13 | |
The following table reflects revenuesRevenues recognized in the three and ninesix months ended SeptemberJune 30, 20212022 and 2020, which2021, were included in the contract liabilities at December 31, 2021 and 2020, and 2019, respectively:
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2021 | | 2020 | | 2021 | | 2020 |
| Exelon | $ | 4 | | | $ | 2 | | | $ | 38 | | | $ | 25 | |
| Generation | 2 | | | 2 | | | 81 | | | 63 | |
| PHI | 2 | | | — | | | 7 | | | — | |
| Pepco | 2 | | | — | | | 5 | | | — | |
| DPL | — | | | — | | | 1 | | | — | |
| ACE | — | | | — | | | 1 | | | — | |
Transaction Price Allocated to Remaining Performance Obligations (All Registrants)
The following table shows the amounts of future revenues expected to be recorded in each year for performance obligations that are unsatisfied or partially unsatisfied as of SeptemberJune 30, 2021.2022. This disclosure only includes contracts for which the total consideration is fixed and determinable at contract inception. The average contract term varies by customer type and commodity but ranges from one month to several years.
This disclosure excludes Generation's power and gas sales contracts as they contain variable volumes and/or variable pricing. This disclosure also excludes the Utility Registrants' gas and electric tariff sales contracts and transmission revenue contracts as they generally have an original expected duration of one year or less and, therefore, do not contain any future, unsatisfied performance obligations to be included in this disclosure.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 4 — Revenue from Contracts with Customers
| | | 2021 | | 2022 | | 2023 | | 2024 | | 2025 and thereafter | | Total | | 2022 | | 2023 | | 2024 | | 2025 | | 2026 and thereafter | | Total |
| Exelon | Exelon | $ | 82 | | | $ | 125 | | | $ | 50 | | | $ | 35 | | | $ | 184 | | | $ | 476 | | Exelon | $ | 4 | | | $ | 8 | | | $ | 6 | | | $ | 5 | | | $ | 82 | | | $ | 105 | |
| Generation | 168 | | | 281 | | | 92 | | | 41 | | | 97 | | | 679 | | |
| PHI | PHI | 2 | | | 8 | | | 8 | | | 6 | | | 87 | | | 111 | | PHI | 4 | | | 8 | | | 6 | | | 5 | | | 82 | | | 105 | |
| Pepco | Pepco | 2 | | | 6 | | | 6 | | | 5 | | | 70 | | | 89 | | Pepco | 3 | | | 6 | | | 5 | | | 5 | | | 65 | | | 84 | |
| DPL | DPL | — | | | 1 | | | 1 | | | — | | | 9 | | | 11 | | DPL | 1 | | | 1 | | | — | | | — | | | 9 | | | 11 | |
| ACE | ACE | — | | | 1 | | | 1 | | | 1 | | | 8 | | | 11 | | ACE | — | | | 1 | | | 1 | | | — | | | 8 | | | 10 | |
Revenue Disaggregation (All Registrants)
The Registrants disaggregate revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. See Note 5 — Segment Information for the presentation of the Registrant's revenue disaggregation.
5. Segment Information (All Registrants)
Operating segments for each of the Registrants are determined based on information used by the CODMCODMs in deciding how to evaluate performance and allocate resources at each of the Registrants.
Exelon has 116 reportable segments, which include Generation's 5 reportable segments consisting of the Mid-Atlantic, Midwest, New York, ERCOT, and all other power regions referred to collectively as “Other Power Regions” and ComEd, PECO, BGE, and PHI's 3 reportable segments consisting of Pepco, DPL, and ACE. ComEd, PECO, BGE, Pepco, DPL, and ACE each represent a single reportable segment, and as such, no separate segment information is provided for these Registrants. Exelon, ComEd, PECO, BGE, Pepco, DPL, and ACE's CODMs evaluate the performance of and allocate resources to ComEd, PECO, BGE, Pepco, DPL, and ACE based on net income.
The basis for Generation's reportable segments is the integrated management of its electricity business that is located in different geographic regions, and largely representative of the footprints of ISO/RTO and/or NERC regions, which utilize multiple supply sources to provide electricity through various distribution channels (wholesale and retail). Generation's hedging strategies and risk metrics are also aligned to these same geographic regions. Descriptions of each of Generation’s 5 reportable segments are as follows:
•Mid-Atlantic represents operations in the eastern half of PJM, which includes New Jersey, Maryland, Virginia, West Virginia, Delaware, the District of Columbia, and parts of Pennsylvania and North Carolina.
•Midwest represents operations in the western half of PJM and the United States footprint of MISO, excluding MISO’s Southern Region.
•New York represents operations within NYISO.
•ERCOT represents operations within Electric Reliability Council of Texas.
•Other Power Regions:
•New England represents the operations within ISO-NE.
•South represents operations in the FRCC, MISO’s Southern Region, and the remaining portions of the SERC not included within MISO or PJM.
•West represents operations in the WECC, which includes CAISO.
•Canada represents operations across the entire country of Canada and includes AESO, OIESO, and the Canadian portion of MISO.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)
Note 5 — Segment Information
The CODMs for Exelon and Generation evaluate the performance of Generation’s electric business activities and allocate resources based on Revenues Net of Purchased Power and Fuel Expense (RNF). Generation believes that RNF is a useful measurement of operational performance. RNF is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report. Generation’s operating revenues include all sales to third parties and affiliated sales to the Utility Registrants. Purchased power costs include all costs associated with the procurement and supply of electricity including capacity, energy, and ancillary services. Fuel expense includes the fuel costs for Generation’s owned generation and fuel costs associated with tolling agreements. The results of Generation's other business activities are not regularly reviewed by the CODM and are therefore not classified as operating segments or included in the regional reportable segment amounts. These activities include natural gas, as well as other miscellaneous business activities that are not significant to Generation's overall operating revenues or results of operations. Further, Generation’s unrealized mark-to-market gains and losses on economic hedging activities and its amortization of certain intangible assets and liabilities relating to commodity contracts recorded at fair value from mergers and acquisitions are also excluded from the regional reportable segment amounts. Exelon and Generation do not use a measure of total assets in making decisions regarding allocating resources to or assessing the performance of these reportable segments.
An analysis and reconciliation of the Registrants’ reportable segment information to the respective information in the consolidated financial statements for the three and ninesix months ended SeptemberJune 30, 20212022 and 20202021 is as follows:
Three Months Ended September 30, 2021 and 2020
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Generation | | ComEd | | PECO | | BGE | | PHI | | Other(a) | | Intersegment
Eliminations | | Exelon |
Operating revenues(b): |
| 2021 | | | | | | | | | | | | | | | |
| Competitive businesses electric revenues | $ | 4,330 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | (319) | | | $ | 4,011 | |
| Competitive businesses natural gas revenues | 575 | | | — | | | — | | | — | | | — | | | — | | | — | | | 575 | |
| Competitive businesses other revenues | (499) | | | — | | | — | | | — | | | — | | | — | | | (3) | | | (502) | |
| Rate-regulated electric revenues | — | | | 1,789 | | | 762 | | | 677 | | | 1,444 | | | — | | | (15) | | | 4,657 | |
| Rate-regulated natural gas revenues | — | | | — | | | 56 | | | 93 | | | 23 | | | — | | | (3) | | | 169 | |
| Shared service and other revenues | — | | | — | | | — | | | — | | | 3 | | | 534 | | | (537) | | | — | |
| Total operating revenues | $ | 4,406 | | | $ | 1,789 | | | $ | 818 | | | $ | 770 | | | $ | 1,470 | | | $ | 534 | | | $ | (877) | | | $ | 8,910 | |
| 2020 | | | | | | | | | | | | | | | |
| Competitive businesses electric revenues | $ | 4,201 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | (326) | | | $ | 3,875 | |
| Competitive businesses natural gas revenues | 323 | | | — | | | — | | | — | | | — | | | — | | | — | | | 323 | |
| Competitive businesses other revenues | 135 | | | — | | | — | | | — | | | — | | | — | | | (3) | | | 132 | |
| Rate-regulated electric revenues | — | | | 1,643 | | | 759 | | | 646 | | | 1,339 | | | — | | | (22) | | | 4,365 | |
| Rate-regulated natural gas revenues | — | | | — | | | 54 | | | 85 | | | 23 | | | — | | | (3) | | | 159 | |
| Shared service and other revenues | — | | | — | | | — | | | — | | | 6 | | | 484 | | | (491) | | | (1) | |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 5 — Segment Information
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Total operating revenues | $ | 4,659 | | | $ | 1,643 | | | $ | 813 | | | $ | 731 | | | $ | 1,368 | | | $ | 484 | | | $ | (845) | | | $ | 8,853 | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Generation | | ComEd | | PECO | | BGE | | PHI | | Other(a) | | Intersegment
Eliminations | | Exelon |
Intersegment revenues(c): | | | | | | | | | | | | | | | |
| 2021 | $ | 324 | | | $ | 9 | | | $ | 2 | | | $ | 7 | | | $ | 3 | | | $ | 531 | | | $ | (876) | | | $ | — | |
| 2020 | 331 | | | 15 | | | 3 | | | 6 | | | 6 | | | 485 | | | (845) | | | 1 | |
| Depreciation and amortization: | | | | | | | | | | | | | | | |
| 2021 | $ | 866 | | | $ | 304 | | | $ | 86 | | | $ | 142 | | | $ | 210 | | | $ | 16 | | | $ | — | | | $ | 1,624 | |
| 2020 | 558 | | | 294 | | | 85 | | | 133 | | | 200 | | | 19 | | | — | | | 1,289 | |
| Operating expenses: | | | | | | | | | | | | | | | |
| 2021 | $ | 3,465 | | | $ | 1,428 | | | $ | 677 | | | $ | 709 | | | $ | 1,155 | | | $ | 541 | | | $ | (858) | | | $ | 7,117 | |
| 2020 | 4,727 | | | 1,302 | | | 658 | | | 642 | | | 1,102 | | | 489 | | | (833) | | | 8,087 | |
| Interest expense, net: | | | | | | | | | | | | | | | |
| 2021 | $ | 77 | | | $ | 98 | | | $ | 40 | | | $ | 36 | | | $ | 67 | | | $ | 79 | | | $ | — | | | $ | 397 | |
| 2020 | 80 | | | 95 | | | 39 | | | 34 | | | 67 | | | 89 | | | — | | | 404 | |
| Income (loss) before income taxes: | | | | | | | | | | | | | | | |
| 2021 | $ | 814 | | | $ | 276 | | | $ | 108 | | | $ | 32 | | | $ | 264 | | | $ | (88) | | | $ | — | | | $ | 1,406 | |
| 2020 | 219 | | | 256 | | | 122 | | | 61 | | | 215 | | | (87) | | | — | | | 786 | |
| Income Taxes: | | | | | | | | | | | | | | | |
| 2021 | $ | 177 | | | $ | 56 | | | $ | (3) | | | $ | (4) | | | $ | (2) | | | $ | (50) | | | $ | — | | | $ | 174 | |
| 2020 | 100 | | | 60 | | | (16) | | | 8 | | | (1) | | | 65 | | | — | | | 216 | |
| Net income (loss): | | | | | | | | | | | | | | | |
| 2021 | $ | 633 | | | $ | 220 | | | $ | 111 | | | $ | 36 | | | $ | 266 | | | $ | (37) | | | $ | — | | | $ | 1,229 | |
| 2020 | 117 | | | 196 | | | 138 | | | 53 | | | 216 | | | (151) | | | — | | | 569 | |
| Capital Expenditures: | | | | | | | | | | | | | | | |
| 2021 | $ | 367 | | | $ | 561 | | | $ | 301 | | | $ | 287 | | | $ | 410 | | | $ | 4 | | | $ | — | | | $ | 1,930 | |
| 2020 | 282 | | | 554 | | | 312 | | | 290 | | | 386 | | | 9 | | | — | | | 1,833 | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| ComEd | | PECO | | BGE | | PHI | | Other(a) | | Intersegment
Eliminations | | Exelon |
Operating revenues(b): | | | | | | | | | | | | | |
| 2022 | | | | | | | | | | | | | |
| Electric revenues | $ | 1,425 | | | $ | 708 | | | $ | 629 | | | $ | 1,182 | | | $ | — | | | $ | (6) | | | $ | 3,938 | |
| Natural gas revenues | — | | | 108 | | | 157 | | | 37 | | | — | | | (1) | | | 301 | |
| Shared service and other revenues | — | | | — | | | — | | | 2 | | | 384 | | | (386) | | | — | |
| Total operating revenues | $ | 1,425 | | | $ | 816 | | | $ | 786 | | | $ | 1,221 | | | $ | 384 | | | $ | (393) | | | $ | 4,239 | |
| 2021 | | | | | | | | | | | | | |
| Electric revenues | $ | 1,517 | | | $ | 610 | | | $ | 558 | | | $ | 1,113 | | | $ | — | | | $ | (9) | | | $ | 3,789 | |
| Natural gas revenues | — | | | 83 | | | 124 | | | 24 | | | — | | | — | | | 231 | |
| Shared service and other revenues | — | | | — | | | — | | | 3 | | | 524 | | | (527) | | | — | |
| Total operating revenues | $ | 1,517 | | | $ | 693 | | | $ | 682 | | | $ | 1,140 | | | $ | 524 | | | $ | (536) | | | $ | 4,020 | |
| | | | | | | | | | | | | |
Intersegment revenues(c): | | | | | | | | | | | | | |
| 2022 | $ | 3 | | | $ | 1 | | | $ | 3 | | | $ | 2 | | | $ | 384 | | | $ | (393) | | | $ | — | |
| 2021 | 5 | | | 2 | | | 7 | | | 4 | | | 522 | | | (535) | | | 5 | |
| Depreciation and amortization: | | | | | | | | | | | | | |
| 2022 | $ | 328 | | | $ | 93 | | | $ | 152 | | | $ | 240 | | | $ | 16 | | | $ | 1 | | | $ | 830 | |
| 2021 | 296 | | | 87 | | | 141 | | | 194 | | | 18 | | | — | | | 736 | |
| Operating expenses: | | | | | | | | | | | | | |
| 2022 | $ | 1,039 | | | $ | 639 | | | $ | 717 | | | $ | 1,066 | | | $ | 460 | | | $ | (378) | | | $ | 3,543 | |
| 2021 | 1,196 | | | 552 | | | 620 | | | 955 | | | 495 | | | (374) | | | 3,444 | |
| Interest expense, net: | | | | | | | | | | | | | |
| 2022 | $ | 104 | | | $ | 43 | | | $ | 36 | | | $ | 73 | | | $ | 101 | | | $ | 1 | | | $ | 358 | |
| 2021 | 98 | | | 42 | | | 34 | | | 67 | | | 83 | | | — | | | 324 | |
| Income (loss) from continuing operations before income taxes: | | | | | | | | | | | | | |
| 2022 | $ | 293 | | | $ | 142 | | | $ | 38 | | | $ | 101 | | | $ | (62) | | | $ | (1) | | | $ | 511 | |
| 2021 | 238 | | | 106 | | | 37 | | | 138 | | | (46) | | | (144) | | | 329 | |
| Income Taxes: | | | | | | | | | | | | | |
| 2022 | $ | 66 | | | $ | 9 | | | $ | 1 | | | $ | 1 | | | $ | (31) | | | $ | — | | | $ | 46 | |
| 2021 | 46 | | | 2 | | | (8) | | | (3) | | | (27) | | | (7) | | | 3 | |
| Net income (loss) from continuing operations: | | | | | | | | | | | | | |
| 2022 | $ | 227 | | | $ | 133 | | | $ | 37 | | | $ | 100 | | | $ | (31) | | | $ | (1) | | | $ | 465 | |
| 2021 | 192 | | | 104 | | | 45 | | | 141 | | | (19) | | | (137) | | | 326 | |
| Capital Expenditures: | | | | | | | | | | | | | |
| 2022 | $ | 591 | | | $ | 314 | | | $ | 275 | | | $ | 367 | | | $ | 38 | | | $ | — | | | $ | 1,585 | |
| 2021 | 549 | | | 282 | | | 284 | | | 433 | | | 15 | | | — | | | 1,563 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
__________(a)Other primarily includes Exelon’s corporate operations, shared service entities, and other financing and investment activities.
(b)Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 1814 — Supplemental Financial Information for additional information on total utility taxes.
(c)Intersegment revenues exclude sales to unconsolidated affiliates. The intersegment profit associated with Generation’s sale of certain products and services by and between Exelon’s segments is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. For Exelon, these amounts are included in Operating revenues in the Consolidated Statements of Operations and Comprehensive Income. See Note 19—15 — Related Party Transactions for additional information on intersegment revenues.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 5 — Segment Information
PHI:
| | | | Pepco | | DPL | | ACE | | Other(a) | | Intersegment
Eliminations | | PHI | | Pepco | | DPL | | ACE | | Other(a) | | Intersegment
Eliminations | | PHI |
Operating revenues(b): | Operating revenues(b): | | | | | | | | | | | | Operating revenues(b): | | | | | | | | | | | |
| 2021 | | |
| Rate-regulated electric revenues | $ | 660 | | | $ | 337 | | | $ | 451 | | | $ | — | | | $ | (4) | | | $ | 1,444 | | |
| Rate-regulated natural gas revenues | — | | | 23 | | | — | | | — | | | — | | | 23 | | |
| 2022 | | 2022 | |
| Electric revenues | | Electric revenues | $ | 581 | | | $ | 295 | | | $ | 309 | | | $ | — | | | $ | (3) | | | $ | 1,182 | |
| Natural gas revenues | | Natural gas revenues | — | | | 37 | | | — | | | — | | | — | | | 37 | |
| Shared service and other revenues | Shared service and other revenues | — | | | — | | | — | | | 92 | | | (89) | | | 3 | | Shared service and other revenues | — | | | — | | | — | | | 98 | | | (96) | | | 2 | |
| Total operating revenues | Total operating revenues | $ | 660 | | | $ | 360 | | | $ | 451 | | | $ | 92 | | | $ | (93) | | | $ | 1,470 | | Total operating revenues | $ | 581 | | | $ | 332 | | | $ | 309 | | | $ | 98 | | | $ | (99) | | | $ | 1,221 | |
| 2020 | | | | | | | | | | | | |
| Rate-regulated electric revenues | $ | 611 | | | $ | 314 | | | $ | 420 | | | $ | — | | | $ | (6) | | | $ | 1,339 | | |
| Rate-regulated natural gas revenues | — | | | 23 | | | — | | | — | | | — | | | 23 | | |
| 2021 | | 2021 | | | | | | | | | | | |
| Electric revenues | | Electric revenues | $ | 523 | | | $ | 274 | | | $ | 319 | | | $ | — | | | $ | (3) | | | $ | 1,113 | |
| Natural gas revenues | | Natural gas revenues | — | | | 24 | | | — | | | — | | | — | | | 24 | |
| Shared service and other revenues | Shared service and other revenues | — | | | — | | | — | | | 91 | | | (85) | | | 6 | | Shared service and other revenues | — | | | — | | | — | | | 95 | | | (92) | | | 3 | |
| Total operating revenues | Total operating revenues | $ | 611 | | | $ | 337 | | | $ | 420 | | | $ | 91 | | | $ | (91) | | | $ | 1,368 | | Total operating revenues | $ | 523 | | | $ | 298 | | | $ | 319 | | | $ | 95 | | | $ | (95) | | | $ | 1,140 | |
Intersegment revenues(c): | Intersegment revenues(c): | | | | | | | | | | | | Intersegment revenues(c): | | | | | | | | | | | |
| 2022 | | 2022 | $ | 2 | | | $ | 2 | | | $ | 1 | | | $ | 98 | | | $ | (101) | | | $ | 2 | |
| 2021 | 2021 | $ | 2 | | | $ | 2 | | | $ | 1 | | | $ | 91 | | | $ | (93) | | | $ | 3 | | 2021 | 1 | | | 2 | | | 1 | | | 95 | | | (95) | | | 4 | |
| 2020 | 3 | | | 3 | | | 1 | | | 90 | | | (91) | | | 6 | | |
| Depreciation and amortization: | Depreciation and amortization: | | Depreciation and amortization: | |
| 2022 | | 2022 | $ | 105 | | | $ | 56 | | | $ | 72 | | | $ | 7 | | | $ | — | | | $ | 240 | |
| 2021 | 2021 | $ | 104 | | | $ | 53 | | | $ | 46 | | | $ | 7 | | | $ | — | | | $ | 210 | | 2021 | 96 | | | 51 | | | 40 | | | 7 | | | — | | | 194 | |
| 2020 | 96 | | | 48 | | | 48 | | | 8 | | | — | | | 200 | | |
| Operating expenses: | Operating expenses: | | Operating expenses: | |
| 2022 | | 2022 | $ | 487 | | | $ | 296 | | | $ | 283 | | | $ | 99 | | | $ | (99) | | | $ | 1,066 | |
| 2021 | 2021 | $ | 501 | | | $ | 295 | | | $ | 359 | | | $ | 93 | | | $ | (93) | | | $ | 1,155 | | 2021 | 429 | | | 255 | | | 269 | | | 97 | | | (95) | | | 955 | |
| 2020 | 465 | | | 296 | | | 338 | | | 94 | | | (91) | | | 1,102 | | |
| Interest expense, net: | Interest expense, net: | | Interest expense, net: | |
| 2022 | | 2022 | $ | 38 | | | $ | 17 | | | $ | 17 | | | $ | 1 | | | $ | — | | | $ | 73 | |
| 2021 | 2021 | $ | 35 | | | $ | 15 | | | $ | 14 | | | $ | 3 | | | $ | — | | | $ | 67 | | 2021 | 35 | | | 16 | | | 14 | | | 2 | | | — | | | 67 | |
| 2020 | 35 | | | 15 | | | 15 | | | 2 | | | — | | | 67 | | |
| Income (loss) before income taxes: | Income (loss) before income taxes: | | Income (loss) before income taxes: | |
| 2022 | | 2022 | $ | 69 | | | $ | 23 | | | $ | 11 | | | $ | (2) | | | $ | — | | | $ | 101 | |
| 2021 | 2021 | $ | 136 | | | $ | 53 | | | $ | 79 | | | $ | (4) | | | $ | — | | | $ | 264 | | 2021 | 72 | | | 31 | | | 36 | | | (1) | | | — | | | 138 | |
| 2020 | 121 | | | 28 | | | 68 | | | (2) | | | — | | | 215 | | |
| Income Taxes: | Income Taxes: | | Income Taxes: | |
| 2022 | | 2022 | $ | (1) | | | $ | 2 | | | $ | — | | | $ | — | | | $ | — | | | $ | 1 | |
| 2021 | 2021 | $ | 6 | | | $ | 3 | | | $ | (11) | | | $ | — | | | $ | — | | | $ | (2) | | 2021 | (3) | | | 1 | | | (1) | | | — | | | — | | | (3) | |
| 2020 | 3 | | | 1 | | | (7) | | | 2 | | | — | | | (1) | | |
| Net income (loss): | Net income (loss): | | Net income (loss): | |
| 2022 | | 2022 | $ | 70 | | | $ | 21 | | | $ | 11 | | | $ | (2) | | | $ | — | | | $ | 100 | |
| 2021 | 2021 | $ | 130 | | | $ | 50 | | | $ | 90 | | | $ | (4) | | | $ | — | | | $ | 266 | | 2021 | 75 | | | 30 | | | 37 | | | (1) | | | — | | | 141 | |
| 2020 | 118 | | | 27 | | | 75 | | | (4) | | | — | | | 216 | | |
| Capital Expenditures: | Capital Expenditures: | | Capital Expenditures: | |
| 2022 | | 2022 | $ | 184 | | | $ | 91 | | | $ | 92 | | | $ | — | | | $ | — | | | $ | 367 | |
| 2021 | 2021 | $ | 202 | | | $ | 109 | | | $ | 97 | | | $ | 2 | | | $ | — | | | $ | 410 | | 2021 | 219 | | | 99 | | | 116 | | | (1) | | | — | | | 433 | |
| 2020 | 188 | | | 94 | | | 103 | | | 1 | | | — | | | 386 | | |
|
__________
(a)Other primarily includes PHI’s corporate operations, shared service entities, and other financing and investment activities.
(b)Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 1814 — Supplemental Financial Information for additional information on total utility taxes.
(c)Includes intersegment revenues with ComEd, BGE, and PECO, which are eliminated at Exelon.
The following tables disaggregate the Registrants' revenuerevenues recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. For Generation, the disaggregation of revenues reflects Generation’s two primary products of power sales and natural gas sales, with further disaggregation of power sales provided by geographic region. For the Utility Registrants, the disaggregation of revenues reflects the two primary utility services of rate-regulated
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)
Note 5 — Segment Information
electric sales and rate-regulated natural gas sales (where applicable), with further disaggregation of these tariff sales provided by major customer groups. Exelon’s disaggregated revenues are consistent with Generation and the Utility Registrants, but exclude any intercompany revenues.
Competitive Business Revenues (Generation):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, 2021 |
| Revenues from external customers(a) | | Intersegment
Revenues | | Total
Revenues |
| Contracts with customers | | Other(b) | | Total | | |
| Mid-Atlantic | $ | 1,145 | | | $ | 123 | | | $ | 1,268 | | | $ | 4 | | | $ | 1,272 | |
| Midwest | 1,084 | | | (99) | | | 985 | | | — | | | 985 | |
| New York | 445 | | | 10 | | | 455 | | | — | | | 455 | |
| ERCOT | 191 | | | 165 | | | 356 | | | 2 | | | 358 | |
| Other Power Regions | 948 | | | 318 | | | 1,266 | | | (6) | | | 1,260 | |
| Total Competitive Businesses Electric Revenues | 3,813 | | | 517 | | | 4,330 | | | — | | | 4,330 | |
| Competitive Businesses Natural Gas Revenues | 266 | | | 309 | | | 575 | | | — | | | 575 | |
Competitive Businesses Other Revenues(c) | 95 | | | (594) | | | (499) | | | — | | | (499) | |
| Total Generation Consolidated Operating Revenues | $ | 4,174 | | | $ | 232 | | | $ | 4,406 | | | $ | — | | | $ | 4,406 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, 2020 |
| Revenues from external customers(a) | | Intersegment
revenues | | Total
Revenues |
| Contracts with customers | | Other(b) | | Total | | |
| Mid-Atlantic | $ | 1,327 | | | $ | (20) | | | $ | 1,307 | | | $ | 6 | | | $ | 1,313 | |
| Midwest | 974 | | | 68 | | | 1,042 | | | 1 | | | 1,043 | |
| New York | 401 | | | 5 | | | 406 | | | — | | | 406 | |
| ERCOT | 249 | | | 74 | | | 323 | | | 7 | | | 330 | |
| Other Power Regions | 937 | | | 186 | | | 1,123 | | | (14) | | | 1,109 | |
| Total Competitive Businesses Electric Revenues | 3,888 | | | 313 | | | 4,201 | | | — | | | 4,201 | |
| Competitive Businesses Natural Gas Revenues | 169 | | | 154 | | | 323 | | | — | | | 323 | |
Competitive Businesses Other Revenues(c) | 85 | | | 50 | | | 135 | | | — | | | 135 | |
| Total Generation Consolidated Operating Revenues | $ | 4,142 | | | $ | 517 | | | $ | 4,659 | | | $ | — | | | $ | 4,659 | |
__________
(a)Includes all wholesale and retail electric sales to third parties and affiliated sales to the Utility Registrants.
(b)Includes revenues from derivatives and leases.
(c)Other represents activities not allocated to a region. See text above for a description of included activities. Includes unrealized mark-to-market losses of $635 million and gains of $37 million in 2021 and 2020, respectively, and elimination of intersegment revenues.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 5 — Segment Information
Revenues net of purchased power and fuel expense (Generation):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, 2021 | | Three Months Ended September 30, 2020 |
| RNF from external customers(a) | | Intersegment
RNF | | Total RNF | | RNF from external customers(a) | | Intersegment
RNF | | Total RNF |
| Mid-Atlantic | $ | 567 | | | $ | 3 | | | $ | 570 | | | $ | 586 | | | $ | 5 | | | $ | 591 | |
| Midwest | 655 | | | — | | | 655 | | | 748 | | | 2 | | | 750 | |
| New York | 343 | | | 3 | | | 346 | | | 281 | | | 4 | | | 285 | |
| ERCOT | 181 | | | (2) | | | 179 | | | 141 | | | 6 | | | 147 | |
| Other Power Regions | 233 | | | (22) | | | 211 | | | 253 | | | (28) | | | 225 | |
| Total RNF for Reportable Segments | 1,979 | | | (18) | | | 1,961 | | | 2,009 | | | (11) | | | 1,998 | |
Other(b) | 881 | | | 18 | | | 899 | | | 336 | | | 11 | | | 347 | |
| Total Generation RNF | $ | 2,860 | | | $ | — | | | $ | 2,860 | | | $ | 2,345 | | | $ | — | | | $ | 2,345 | |
__________
(a)Includes purchases and sales from/to third parties and affiliated sales to the Utility Registrants.
(b)Other represents activities not allocated to a region. See text above for a description of included activities. includes:
•unrealized mark-to-market gains of $754 million and gains of $255 million in 2021 and 2020, respectively;
•accelerated nuclear fuel amortization associated with announced early plant retirements as discussed in Note 7 — Early Plant Retirements of $42 million and $24 million in 2021 and 2020 respectively; and
•the elimination of intersegment RNF.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| Three Months Ended June 30, 2022 |
| Revenues from contracts with customers | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Electric revenues | | | | | | | | | | | | | |
| Residential | $ | 819 | | | $ | 431 | | | $ | 334 | | | $ | 548 | | | $ | 234 | | | $ | 155 | | | $ | 159 | |
| Small commercial & industrial | 312 | | | 126 | | | 70 | | | 140 | | | 35 | | | 51 | | | 54 | |
| Large commercial & industrial | 11 | | | 72 | | | 129 | | | 332 | | | 250 | | | 30 | | | 52 | |
| Public authorities & electric railroads | 5 | | | 7 | | | 7 | | | 15 | | | 8 | | | 3 | | | 4 | |
Other(a) | 234 | | | 68 | | | 99 | | | 164 | | | 54 | | | 57 | | | 55 | |
Total electric revenues(b) | $ | 1,381 | | | $ | 704 | | | $ | 639 | | | $ | 1,199 | | | $ | 581 | | | $ | 296 | | | $ | 324 | |
| Natural gas revenues | | | | | | | | | | | | | |
| Residential | $ | — | | | $ | 71 | | | $ | 96 | | | $ | 17 | | | $ | — | | | $ | 17 | | | $ | — | |
| Small commercial & industrial | — | | | 29 | | | 18 | | | 8 | | | — | | | 8 | | | — | |
| Large commercial & industrial | — | | | — | | | 35 | | | 3 | | | — | | | 3 | | | — | |
| Transportation | — | | | 6 | | | — | | | 3 | | | — | | | 3 | | | — | |
Other(c) | — | | | 2 | | | 12 | | | 6 | | | — | | | 6 | | | — | |
Total Natural gas revenues(d) | $ | — | | | $ | 108 | | | $ | 161 | | | $ | 37 | | | $ | — | | | $ | 37 | | | $ | — | |
| Total revenues from contracts with customers | $ | 1,381 | | | $ | 812 | | | $ | 800 | | | $ | 1,236 | | | $ | 581 | | | $ | 333 | | | $ | 324 | |
| | | | | | | | | | | | | |
| Other revenues | | | | | | | | | | | | | |
| Revenues from alternative revenue programs | $ | 35 | | | $ | — | | | $ | (20) | | | $ | (17) | | | $ | (1) | | | $ | (2) | | | $ | (15) | |
Other electric revenues(e) | 9 | | | 4 | | | 4 | | | 2 | | | 1 | | | 1 | | | — | |
Other natural gas revenues(e) | — | | | — | | | 2 | | | — | | | — | | | — | | | — | |
| | | | | | | | | | | | | |
| Total other revenues | $ | 44 | | | $ | 4 | | | $ | (14) | | | $ | (15) | | | $ | — | | | $ | (1) | | | $ | (15) | |
| Total revenues for reportable segments | $ | 1,425 | | | $ | 816 | | | $ | 786 | | | $ | 1,221 | | | $ | 581 | | | $ | 332 | | | $ | 309 | |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 5 — Segment Information
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| Three Months Ended June 30, 2021 |
| Revenues from contracts with customers | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Electric revenues | | | | | | | | | | | | | |
| Residential | $ | 759 | | | $ | 383 | | | $ | 299 | | | $ | 537 | | | $ | 223 | | | $ | 147 | | | $ | 167 | |
| Small commercial & industrial | 377 | | | 99 | | | 60 | | | 124 | | | 32 | | | 46 | | | 46 | |
| Large commercial & industrial | 138 | | | 59 | | | 108 | | | 257 | | | 188 | | | 22 | | | 47 | |
| Public authorities & electric railroads | 11 | | | 8 | | | 7 | | | 17 | | | 10 | | | 3 | | | 4 | |
Other(a) | 214 | | | 54 | | | 87 | | | 139 | | | 50 | | | 46 | | | 43 | |
Total electric revenues(b) | $ | 1,499 | | | $ | 603 | | | $ | 561 | | | $ | 1,074 | | | $ | 503 | | | $ | 264 | | | $ | 307 | |
| Natural gas revenues | | | | | | | | | | | | | |
| Residential | $ | — | | | $ | 55 | | | $ | 81 | | | $ | 12 | | | $ | — | | | $ | 12 | | | $ | — | |
| Small commercial & industrial | — | | | 22 | | | 13 | | | 6 | | | — | | | 6 | | | — | |
| Large commercial & industrial | — | | | — | | | 27 | | | 1 | | | — | | | 1 | | | — | |
| Transportation | — | | | 5 | | | — | | | 3 | | | — | | | 3 | | | — | |
Other(c) | — | | | 1 | | | 6 | | | 2 | | | — | | | 2 | | | — | |
Total natural gas revenues(d) | $ | — | | | $ | 83 | | | $ | 127 | | | $ | 24 | | | $ | — | | | $ | 24 | | | $ | — | |
| Total revenues from contracts with customers | $ | 1,499 | | | $ | 686 | | | $ | 688 | | | $ | 1,098 | | | $ | 503 | | | $ | 288 | | | $ | 307 | |
| | | | | | | | | | | | | |
| Other revenues | | | | | | | | | | | | | |
| Revenues from alternative revenue programs | $ | 9 | | | $ | 7 | | | $ | (10) | | | $ | 41 | | | $ | 19 | | | $ | 10 | | | $ | 12 | |
Other electric revenues(e) | 9 | | | — | | | 3 | | | 1 | | | 1 | | | — | | | — | |
Other natural gas revenues(e) | — | | | — | | | 1 | | | — | | | — | | | — | | | — | |
| | | | | | | | | | | | | |
| Total other revenues | $ | 18 | | | $ | 7 | | | $ | (6) | | | $ | 42 | | | $ | 20 | | | $ | 10 | | | $ | 12 | |
| Total revenues for reportable segments | $ | 1,517 | | | $ | 693 | | | $ | 682 | | | $ | 1,140 | | | $ | 523 | | | $ | 298 | | | $ | 319 | |
Electric and Gas Revenue by Customer Class (Utility Registrants):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, 2021 |
| Revenues from contracts with customers | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Rate-regulated electric revenues | | | | | | | | | | | | | |
| Residential | $ | 978 | | | $ | 509 | | | $ | 383 | | | $ | 782 | | | $ | 309 | | | $ | 198 | | | $ | 275 | |
| Small commercial & industrial | 433 | | | 113 | | | 73 | | | 150 | | | 36 | | | 53 | | | 61 | |
| Large commercial & industrial | 148 | | | 67 | | | 128 | | | 320 | | | 244 | | | 27 | | | 49 | |
| Public authorities & electric railroads | 11 | | | 7 | | | 7 | | | 15 | | | 8 | | | 4 | | | 3 | |
Other(a) | 245 | | | 61 | | | 104 | | | 172 | | | 53 | | | 56 | | | 63 | |
Total rate-regulated electric revenues(b) | $ | 1,815 | | | $ | 757 | | | $ | 695 | | | $ | 1,439 | | | $ | 650 | | | $ | 338 | | | $ | 451 | |
| Rate-regulated natural gas revenues | | | | | | | | | | | | | |
| Residential | $ | — | | | $ | 36 | | | $ | 57 | | | $ | 10 | | | $ | — | | | $ | 10 | | | $ | — | |
| Small commercial & industrial | — | | | 13 | | | 10 | | | 5 | | | — | | | 5 | | | — | |
| Large commercial & industrial | — | | | — | | | 22 | | | 2 | | | — | | | 2 | | | — | |
| Transportation | — | | | 5 | | | — | | | 3 | | | — | | | 3 | | | — | |
Other(c) | — | | | 2 | | | 6 | | | 3 | | | — | | | 3 | | | — | |
Total rate-regulated natural gas revenues(d) | $ | — | | | $ | 56 | | | $ | 95 | | | $ | 23 | | | $ | — | | | $ | 23 | | | $ | — | |
| Total rate-regulated revenues from contracts with customers | $ | 1,815 | | | $ | 813 | | | $ | 790 | | | $ | 1,462 | | | $ | 650 | | | $ | 361 | | | $ | 451 | |
| | | | | | | | | | | | | |
| Other revenues | | | | | | | | | | | | | |
| Revenues from alternative revenue programs | $ | (32) | | | $ | 3 | | | $ | (24) | | | $ | 6 | | | $ | 9 | | | $ | (2) | | | $ | — | |
Other rate-regulated electric revenues(e) | 6 | | | 2 | | | 3 | | | 2 | | | 1 | | | 1 | | | — | |
Other rate-regulated natural gas revenues(e) | — | | | — | | | 1 | | | — | | | — | | | — | | | — | |
| | | | | | | | | | | | | |
| Total other revenues | $ | (26) | | | $ | 5 | | | $ | (20) | | | $ | 8 | | | $ | 10 | | | $ | (1) | | | $ | — | |
| Total rate-regulated revenues for reportable segments | $ | 1,789 | | | $ | 818 | | | $ | 770 | | | $ | 1,470 | | | $ | 660 | | | $ | 360 | | | $ | 451 | |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)
Note 5 — Segment Information
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, 2020 |
| Revenues from contracts with customers | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Rate-regulated electric revenues | | | | | | | | | | | | | |
| Residential | $ | 920 | | | $ | 518 | | | $ | 389 | | | $ | 763 | | | $ | 307 | | | $ | 193 | | | $ | 263 | |
| Small commercial & industrial | 379 | | | 104 | | | 65 | | | 134 | | | 36 | | | 45 | | | 53 | |
| Large commercial & industrial | 135 | | | 66 | | | 113 | | | 262 | | | 195 | | | 21 | | | 46 | |
| Public authorities & electric railroads | 10 | | | 7 | | | 7 | | | 14 | | | 8 | | | 3 | | | 3 | |
Other(a) | 234 | | | 58 | | | 78 | | | 141 | | | 47 | | | 44 | | | 50 | |
Total rate-regulated electric revenues(b) | $ | 1,678 | | | $ | 753 | | | $ | 652 | | | $ | 1,314 | | | $ | 593 | | | $ | 306 | | | $ | 415 | |
| Rate-regulated natural gas revenues | | | | | | | | | | | | | |
| Residential | $ | — | | | $ | 32 | | | $ | 55 | | | $ | 11 | | | $ | — | | | $ | 11 | | | $ | — | |
| Small commercial & industrial | — | | | 16 | | | 9 | | | 6 | | | — | | | 6 | | | — | |
| Large commercial & industrial | — | | | — | | | 21 | | | 1 | | | — | | | 1 | | | — | |
| Transportation | — | | | 6 | | | — | | | 3 | | | — | | | 3 | | | — | |
Other(c) | — | | | 1 | | | 3 | | | 2 | | | — | | | 2 | | | — | |
Total rate-regulated natural gas revenues(d) | $ | — | | | $ | 55 | | | $ | 88 | | | $ | 23 | | | $ | — | | | $ | 23 | | | $ | — | |
| Total rate-regulated revenues from contracts with customers | $ | 1,678 | | | $ | 808 | | | $ | 740 | | | $ | 1,337 | | | $ | 593 | | | $ | 329 | | | $ | 415 | |
| | | | | | | | | | | | | |
| Other revenues | | | | | | | | | | | | | |
| Revenues from alternative revenue programs | $ | (38) | | | $ | 5 | | | $ | (9) | | | $ | 31 | | | $ | 18 | | | $ | 8 | | | $ | 5 | |
Other rate-regulated electric revenues(e) | 3 | | | — | | | — | | | — | | | — | | | — | | | — | |
Other rate-regulated natural gas revenues(e) | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| | | | | | | | | | | | | |
| Total other revenues | $ | (35) | | | $ | 5 | | | $ | (9) | | | $ | 31 | | | $ | 18 | | | $ | 8 | | | $ | 5 | |
| Total rate-regulated revenues for reportable segments | $ | 1,643 | | | $ | 813 | | | $ | 731 | | | $ | 1,368 | | | $ | 611 | | | $ | 337 | | | $ | 420 | |
(a)Includes revenues from transmission revenue from PJM, wholesale electric revenue and mutual assistance revenue.
(b)Includes operating revenues from affiliates in 20212022 and 20202021 respectively of:
•$93 million, $15$5 million at ComEd
•$21 million, $3$1 million at PECO
•$42 million, $3$4 million at BGE
•$32 million, $6$4 million at PHI
•$2 million, $3$1 million at Pepco
•$2 million, $3$2 million at DPL
•$1 million, $1 million at ACE
(c)Includes revenues from off-system natural gas sales.
(d)Includes operating revenues from affiliates in 20212022 and 20202021 respectively of:
•less than $1 million, less than $1 million at PECO both 2021 and 2020
•$31 million, $3 million at BGE
(e)Includes late payment charge revenues.
Nine Months Ended September 30, 2021 and 2020
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Generation | | ComEd | | PECO | | BGE | | PHI | | Other(a) | | Intersegment
Eliminations | | Exelon |
Operating revenues(b): |
| 2021 | | | | | | | | | | | | | | | |
| Competitive businesses electric revenues | $ | 12,264 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | (860) | | | $ | 11,404 | |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 5 — Segment Information
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Generation | | ComEd | | PECO | | BGE | | PHI | | Other(a) | | Intersegment
Eliminations | | Exelon |
| Competitive businesses natural gas revenues | 2,408 | | | — | | | — | | | — | | | — | | | — | | | — | | | 2,408 | |
| Competitive businesses other revenues | (555) | | | — | | | — | | | — | | | — | | | — | | | (9) | | | (564) | |
| Rate-regulated electric revenues | — | | | 4,840 | | | 2,033 | | | 1,866 | | | 3,726 | | | — | | | (33) | | | 12,432 | |
| Rate-regulated natural gas revenues | — | | | — | | | 366 | | | 560 | | | 118 | | | — | | | (9) | | | 1,035 | |
| Shared service and other revenues | — | | | — | | | — | | | — | | | 10 | | | 1,549 | | | (1,559) | | | — | |
| Total operating revenues | $ | 14,117 | | | $ | 4,840 | | | $ | 2,399 | | | $ | 2,426 | | | $ | 3,854 | | | $ | 1,549 | | | $ | (2,470) | | | $ | 26,715 | |
| 2020 | | | | | | | | | | | | | | | |
| Competitive businesses electric revenues | $ | 11,367 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | (920) | | | $ | 10,447 | |
| Competitive businesses natural gas revenues | 1,348 | | | — | | | — | | | — | | | — | | | — | | | (3) | | | 1,345 | |
| Competitive businesses other revenues | 557 | | | — | | | — | | | — | | | — | | | — | | | (5) | | | 552 | |
| Rate-regulated electric revenues | — | | | 4,499 | | | 1,948 | | | 1,763 | | | 3,425 | | | — | | | (50) | | | 11,585 | |
| Rate-regulated natural gas revenues | — | | | — | | | 358 | | | 521 | | | 116 | | | — | | | (5) | | | 990 | |
| Shared service and other revenues | — | | | — | | | — | | | — | | | 13 | | | 1,440 | | | (1,447) | | | 6 | |
| Total operating revenues | $ | 13,272 | | | $ | 4,499 | | | $ | 2,306 | | | $ | 2,284 | | | $ | 3,554 | | | $ | 1,440 | | | $ | (2,430) | | | $ | 24,925 | |
| | | | | | | | | | | | | | | |
Intersegment revenues(c): | | | | | | | | | | | | | | | |
| 2021 | $ | 872 | | | $ | 19 | | | $ | 6 | | | $ | 20 | | | $ | 10 | | | $ | 1,542 | | | $ | (2,469) | | | $ | — | |
| 2020 | 932 | | | 31 | | | 7 | | | 16 | | | 13 | | | 1,435 | | | (2,430) | | | 4 | |
| Depreciation and amortization: | | | | | | | | | | | | | | | |
| 2021 | $ | 2,735 | | | $ | 893 | | | $ | 259 | | | $ | 434 | | | $ | 614 | | | $ | 52 | | | $ | 1 | | | $ | 4,988 | |
| 2020 | 1,161 | | | 841 | | | 259 | | | 405 | | | 585 | | | 61 | | | — | | | 3,312 | |
| Operating expenses: | | | | | | | | | | | | | | | |
| 2021 | $ | 14,605 | | | $ | 3,833 | | | $ | 1,908 | | | $ | 2,080 | | | $ | 3,167 | | | $ | 1,572 | | | $ | (2,407) | | | $ | 24,758 | |
| 2020 | 12,674 | | | 3,798 | | | 1,900 | | | 1,903 | | | 3,057 | | | 1,452 | | | (2,397) | | | 22,387 | |
| Interest expense, net: | | | | | | | | | | | | | | | |
| 2021 | $ | 225 | | | $ | 292 | | | $ | 119 | | | $ | 103 | | | $ | 201 | | | $ | 241 | | | $ | (1) | | | $ | 1,180 | |
| 2020 | 277 | | | 287 | | | 108 | | | 99 | | | 201 | | | 269 | | | — | | | 1,241 | |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)
Note 5 — Segment Information
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Generation | | ComEd | | PECO | | BGE | | PHI | | Other(a) | | Intersegment
Eliminations | | Exelon |
| Income (loss) before income taxes: | | | | | | | | | | | | | | | |
| 2021 | $ | (8) | | | $ | 750 | | | $ | 392 | | | $ | 266 | | | $ | 538 | | | $ | (264) | | | $ | 1 | | | $ | 1,675 | |
| 2020 | 532 | | | 446 | | | 310 | | | 299 | | | 340 | | | (262) | | | — | | | 1,665 | |
| Income Taxes: | | | | | | | | | | | | | | | |
| 2021 | $ | 108 | | | $ | 141 | | | $ | 9 | | | $ | (24) | | | $ | 3 | | | $ | (8) | | | $ | — | | | $ | 229 | |
| 2020 | 41 | | | 142 | | | (7) | | | 26 | | | (77) | | | 16 | | | — | | | 141 | |
| Net income (loss): | | | | | | | | | | | | | | | |
| 2021 | $ | (122) | | | $ | 609 | | | $ | 383 | | | $ | 290 | | | $ | 535 | | | $ | (255) | | | $ | 1 | | | $ | 1,441 | |
| 2020 | 485 | | | 304 | | | 317 | | | 273 | | | 418 | | | (278) | | | — | | | 1,519 | |
| Capital Expenditures: | | | | | | | | | | | | | | | |
| 2021 | $ | 1,086 | | | $ | 1,723 | | | $ | 878 | | | $ | 907 | | | $ | 1,299 | | | $ | 77 | | | $ | — | | | $ | 5,970 | |
| 2020 | 1,212 | | | 1,583 | | | 824 | | | 838 | | | 1,072 | | | 77 | | | — | | | 5,606 | |
| Total assets: | | | | | | | | | | | | | | | |
| September 30, 2021 | $ | 48,010 | | | $ | 36,002 | | | $ | 13,733 | | | $ | 12,197 | | | $ | 24,502 | | | $ | 8,387 | | | $ | (10,210) | | | $ | 132,621 | |
| December 31, 2020 | 48,094 | | | 34,466 | | | 12,531 | | | 11,650 | | | 23,736 | | | 9,005 | | | (10,165) | | | 129,317 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| ComEd | | PECO | | BGE | | PHI | | Other(a) | | Intersegment
Eliminations | | Exelon |
Operating revenues(b): | | | | | | | | | | | | | |
| 2022 | | | | | | | | | | | | | |
| Electric revenues | $ | 3,158 | | | $ | 1,449 | | | $ | 1,366 | | | $ | 2,501 | | | $ | — | | | $ | (14) | | | $ | 8,460 | |
| Natural gas revenues | — | | | 414 | | | 574 | | | 120 | | | — | | | (2) | | | 1,106 | |
| Shared service and other revenues | — | | | — | | | — | | | 5 | | | 961 | | | (966) | | | — | |
| Total operating revenues | $ | 3,158 | | | $ | 1,863 | | | $ | 1,940 | | | $ | 2,626 | | | $ | 961 | | | $ | (982) | | | $ | 9,566 | |
| 2021 | | | | | | | | | | | | | |
| Electric revenues | $ | 3,052 | | | $ | 1,271 | | | $ | 1,190 | | | $ | 2,283 | | | $ | — | | | $ | (16) | | | $ | 7,780 | |
| Natural gas revenues | — | | | 311 | | | 466 | | | 95 | | | — | | | — | | | 872 | |
| Shared service and other revenues | — | | | — | | | — | | | 6 | | | 1,013 | | | (1,019) | | | — | |
| Total operating revenues | $ | 3,052 | | | $ | 1,582 | | | $ | 1,656 | | | $ | 2,384 | | | $ | 1,013 | | | $ | (1,035) | | | $ | 8,652 | |
| | | | | | | | | | | | | |
Intersegment revenues(c): | | | | | | | | | | | | | |
| 2022 | $ | 8 | | | $ | 2 | | | $ | 10 | | | $ | 6 | | | $ | 961 | | | $ | (981) | | | $ | 6 | |
| 2021 | 11 | | | 4 | | | 13 | | | 7 | | | 1,010 | | | (1,033) | | | 12 | |
| Depreciation and amortization: | | | | | | | | | | | | | |
| 2022 | $ | 649 | | | $ | 185 | | | $ | 322 | | | $ | 459 | | | $ | 32 | | | $ | — | | | $ | 1,647 | |
| 2021 | 589 | | | 173 | | | 293 | | | 404 | | | 35 | | | — | | | 1,494 | |
| Operating expenses: | | | | | | | | | | | | | |
| 2022 | $ | 2,444 | | | $ | 1,432 | | | $ | 1,636 | | | $ | 2,282 | | | $ | 1,086 | | | $ | (909) | | | $ | 7,971 | |
| 2021 | 2,406 | | | 1,231 | | | 1,372 | | | 2,013 | | | 943 | | | (713) | | | 7,252 | |
| Interest expense, net: | | | | | | | | | | | | | |
| 2022 | $ | 204 | | | $ | 84 | | | $ | 71 | | | $ | 143 | | | $ | 195 | | | $ | — | | | $ | 697 | |
| 2021 | 193 | | | 80 | | | 67 | | | 134 | | | 169 | | | — | | | 643 | |
| Income (loss) from continuing operations before income taxes: | | | | | | | | | | | | | |
| 2022 | $ | 534 | | | $ | 363 | | | $ | 244 | | | $ | 238 | | | $ | (125) | | | $ | (45) | | | $ | 1,209 | |
| 2021 | 475 | | | 283 | | | 233 | | | 273 | | | (80) | | | (292) | | | 892 | |
| Income Taxes: | | | | | | | | | | | | | |
| 2022 | $ | 119 | | | $ | 24 | | | $ | 10 | | | $ | 8 | | | $ | 114 | | | $ | (12) | | | $ | 263 | |
| 2021 | 85 | | | 12 | | | (21) | | | 5 | | | (19) | | | (20) | | | 42 | |
| Net income (loss) from continuing operations: | | | | | | | | | | | | | |
| 2022 | $ | 415 | | | $ | 339 | | | $ | 234 | | | $ | 230 | | | $ | (239) | | | $ | (33) | | | $ | 946 | |
| 2021 | 390 | | | 271 | | | 254 | | | 269 | | | (61) | | | (272) | | | 851 | |
| Capital Expenditures: | | | | | | | | | | | | | |
| 2022 | $ | 1,208 | | | $ | 658 | | | $ | 578 | | | $ | 776 | | | $ | 60 | | | $ | — | | | $ | 3,280 | |
| 2021 | 1,162 | | | 577 | | | 620 | | | 889 | | | 61 | | | — | | | 3,309 | |
| Total assets: | | | | | | | | | | | | | |
| June 30, 2022 | $ | 37,194 | | | $ | 14,216 | | | $ | 13,093 | | | $ | 25,592 | | | $ | 6,345 | | | $ | (4,145) | | | $ | 92,295 | |
| December 31, 2021 | 36,470 | | | 13,824 | | | 12,324 | | | 24,744 | | | 7,626 | | | (8,319) | | | 86,669 | |
__________
(a)Other primarily includes Exelon’s corporate operations, shared service entities, and other financing and investment activities.
(b)Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 1814 — Supplemental Financial Information for additional information on total utility taxes.
(c)Intersegment revenues exclude sales to unconsolidated affiliates. The intersegment profit associated with Generation’s sale of certain products and services by and between Exelon’s segments is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. For Exelon, these amounts are included in Operating revenues in the Consolidated Statements of Operations and Comprehensive Income. See Note 19 — Related Party Transactions for additional information on intersegment revenues.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 5 — Segment Information
(c)See Note 15 — Related Party Transactions for additional information on intersegment revenues.
PHI:
| | | Pepco | | DPL | | ACE | | Other(a) | | Intersegment
Eliminations | | PHI | | Pepco | | DPL | | ACE | | Other(a) | | Intersegment
Eliminations | | PHI |
Operating revenues(b): | Operating revenues(b): | | | | | | | | | | | | Operating revenues(b): | | | | | | | | | | | |
| 2021 | | |
| Rate-regulated electric revenues | $ | 1,736 | | | $ | 922 | | | $ | 1,080 | | | $ | — | | | $ | (12) | | | $ | 3,726 | | |
| Rate-regulated natural gas revenues | — | | | 118 | | | — | | | — | | | — | | | 118 | | |
| 2022 | | 2022 | |
| Electric revenues | | Electric revenues | $ | 1,195 | | | $ | 643 | | | $ | 658 | | | $ | — | | | $ | 5 | | | $ | 2,501 | |
| Natural gas revenues | | Natural gas revenues | — | | | 120 | | | — | | | — | | | — | | | 120 | |
| Shared service and other revenues | Shared service and other revenues | — | | | — | | | — | | | 281 | | | (271) | | | 10 | | Shared service and other revenues | — | | | — | | | — | | | 205 | | | (200) | | | 5 | |
| Total operating revenues | Total operating revenues | $ | 1,736 | | | $ | 1,040 | | | $ | 1,080 | | | $ | 281 | | | $ | (283) | | | $ | 3,854 | | Total operating revenues | $ | 1,195 | | | $ | 763 | | | $ | 658 | | | $ | 205 | | | $ | (195) | | | $ | 2,626 | |
| 2020 | | | | | | | | | | | | |
| Rate-regulated electric revenues | $ | 1,650 | | | $ | 838 | | | $ | 952 | | | $ | — | | | $ | (15) | | | $ | 3,425 | | |
| Rate-regulated natural gas revenues | — | | | 116 | | | — | | | — | | | — | | | 116 | | |
| 2021 | | 2021 | | | | | | | | | | | |
| Electric revenues | | Electric revenues | $ | 1,076 | | | $ | 585 | | | $ | 629 | | | $ | — | | | $ | (7) | | | $ | 2,283 | |
| Natural gas revenues | | Natural gas revenues | — | | | 95 | | | — | | | — | | | — | | | 95 | |
| Shared service and other revenues | Shared service and other revenues | — | | | — | | | — | | | 279 | | | (266) | | | 13 | | Shared service and other revenues | — | | | — | | | — | | | 189 | | | (183) | | | 6 | |
| Total operating revenues | Total operating revenues | $ | 1,650 | | | $ | 954 | | | $ | 952 | | | $ | 279 | | | $ | (281) | | | $ | 3,554 | | Total operating revenues | $ | 1,076 | | | $ | 680 | | | $ | 629 | | | $ | 189 | | | $ | (190) | | | $ | 2,384 | |
Intersegment revenues(c): | Intersegment revenues(c): | | | | | | | | | | | | Intersegment revenues(c): | | | | | | | | | | | |
| 2022 | | 2022 | $ | 2 | | | $ | 3 | | | $ | 2 | | | $ | 195 | | | $ | (196) | | | $ | 6 | |
| 2021 | 2021 | $ | 4 | | | $ | 6 | | | $ | 2 | | | $ | 281 | | | $ | (283) | | | $ | 10 | | 2021 | 3 | | | 4 | | | 1 | | | 189 | | | (190) | | | 7 | |
| 2020 | 6 | | | 7 | | | 3 | | | 278 | | | (281) | | | 13 | | |
| Depreciation and amortization: | Depreciation and amortization: | | Depreciation and amortization: | |
| 2022 | | 2022 | $ | 213 | | | $ | 113 | | | $ | 118 | | | $ | 15 | | | $ | — | | | $ | 459 | |
| 2021 | 2021 | $ | 302 | | | $ | 157 | | | $ | 133 | | | $ | 22 | | | $ | — | | | $ | 614 | | 2021 | 199 | | | 104 | | | 87 | | | 14 | | | — | | | 404 | |
| 2020 | 282 | | | 143 | | | 134 | | | 26 | | | — | | | 585 | | |
| Operating expenses: | Operating expenses: | | Operating expenses: | |
| 2022 | | 2022 | $ | 1,034 | | | $ | 653 | | | $ | 593 | | | $ | 197 | | | $ | (195) | | | $ | 2,282 | |
| 2021 | 2021 | $ | 1,396 | | | $ | 858 | | | $ | 911 | | | $ | 285 | | | $ | (283) | | | $ | 3,167 | | 2021 | 895 | | | 564 | | | 552 | | | 192 | | | (190) | | | 2,013 | |
| 2020 | 1,364 | | | 843 | | | 847 | | | 284 | | | (281) | | | 3,057 | | |
| Interest expense, net: | Interest expense, net: | | Interest expense, net: | |
| 2022 | | 2022 | $ | 74 | | | $ | 33 | | | $ | 32 | | | $ | 5 | | | $ | (1) | | | $ | 143 | |
| 2021 | 2021 | $ | 104 | | | $ | 47 | | | $ | 43 | | | $ | 7 | | | $ | — | | | $ | 201 | | 2021 | 69 | | | 30 | | | 29 | | | 6 | | | — | | | 134 | |
| 2020 | 103 | | | 47 | | | 45 | | | 6 | | | — | | | 201 | | |
| Income (loss) before income taxes: | Income (loss) before income taxes: | | Income (loss) before income taxes: | |
| 2022 | | 2022 | $ | 113 | | | $ | 83 | | | $ | 38 | | | $ | 4 | | | $ | — | | | $ | 238 | |
| 2021 | 2021 | $ | 273 | | | $ | 144 | | | $ | 129 | | | $ | (8) | | | $ | — | | | $ | 538 | | 2021 | 137 | | | 92 | | | 50 | | | (6) | | | — | | | 273 | |
| 2020 | 211 | | | 71 | | | 67 | | | (9) | | | — | | | 340 | | |
| Income Taxes: | Income Taxes: | | Income Taxes: | |
| 2022 | | 2022 | $ | (3) | | | $ | 6 | | | $ | 1 | | | $ | 4 | | | $ | — | | | $ | 8 | |
| 2021 | 2021 | $ | 9 | | | $ | 9 | | | $ | (12) | | | $ | (3) | | | $ | — | | | $ | 3 | | 2021 | 3 | | | 6 | | | (1) | | | (3) | | | — | | | 5 | |
| 2020 | (16) | | | (20) | | | (39) | | | (2) | | | — | | | (77) | | |
| Net income (loss): | Net income (loss): | | Net income (loss): | |
| 2022 | | 2022 | $ | 116 | | | $ | 77 | | | $ | 37 | | | $ | — | | | $ | — | | | $ | 230 | |
| 2021 | 2021 | $ | 264 | | | $ | 135 | | | $ | 141 | | | $ | (5) | | | $ | — | | | $ | 535 | | 2021 | 134 | | | 86 | | | 51 | | | (2) | | | — | | | 269 | |
| 2020 | 227 | | | 91 | | | 106 | | | (6) | | | — | | | 418 | | |
| Capital Expenditures: | Capital Expenditures: | | Capital Expenditures: | |
| 2022 | | 2022 | $ | 402 | | | $ | 194 | | | $ | 179 | | | $ | 1 | | | $ | — | | | $ | 776 | |
| 2021 | 2021 | $ | 641 | | | $ | 320 | | | $ | 336 | | | $ | 2 | | | $ | — | | | $ | 1,299 | | 2021 | 439 | | | 211 | | | 239 | | | — | | | — | | | 889 | |
| 2020 | 512 | | | 278 | | | 281 | | | 1 | | | — | | | 1,072 | | |
| Total assets: | Total assets: | | Total assets: | |
| September 30, 2021 | $ | 9,748 | | | $ | 5,295 | | | $ | 4,532 | | | $ | 4,977 | | | $ | (50) | | | $ | 24,502 | | |
| December 31, 2020 | 9,264 | | | 5,140 | | | 4,286 | | | 5,079 | | | (33) | | | 23,736 | | |
| June 30, 2022 | | June 30, 2022 | $ | 10,226 | | | $ | 5,742 | | | $ | 5,052 | | | $ | 4,775 | | | $ | (203) | | | $ | 25,592 | |
| December 31, 2021 | | December 31, 2021 | 9,903 | | | 5,412 | | | 4,556 | | | 4,933 | | | (60) | | | 24,744 | |
__________
(a)Other primarily includes PHI’s corporate operations, shared service entities, and other financing and investment activities.
(b)Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 1814 — Supplemental Financial Information for additional information on total utility taxes.
(c)Includes intersegment revenues with ComEd, BGE, and PECO, which are eliminated at Exelon.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 5 — Segment Information
The following tables disaggregate the Registrants' revenuerevenues recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. For Generation, the disaggregation of revenues reflects Generation’s two primary products of power sales and natural gas sales, with further disaggregation of power sales provided by geographic region. For the Utility Registrants, the disaggregation of revenues reflects the two primary utility services of rate-regulated
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)
Note 5 — Segment Information
electric sales and rate-regulated natural gas sales (where applicable), with further disaggregation of these tariff sales provided by major customer groups. Exelon’s disaggregated revenues are consistent with Generation and the Utility Registrants, but exclude any intercompany revenues.
Competitive Business Revenues (Generation):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | |
| Nine Months Ended September 30, 2021 |
| Revenues from external customers(a) | | Intersegment
Revenues | | Total
Revenues |
| Contracts with customers | | Other(b) | | Total | | |
| Mid-Atlantic | $ | 3,377 | | | $ | 134 | | | $ | 3,511 | | | $ | 16 | | | $ | 3,527 | |
| Midwest | 3,067 | | | (123) | | | 2,944 | | | 1 | | | 2,945 | |
| New York | 1,204 | | | (30) | | | 1,174 | | | (1) | | | 1,173 | |
| ERCOT | 724 | | | 155 | | | 879 | | | 11 | | | 890 | |
| Other Power Regions | 3,043 | | | 713 | | | 3,756 | | | (27) | | | 3,729 | |
| Total Competitive Businesses Electric Revenues | 11,415 | | | 849 | | | 12,264 | | | — | | | 12,264 | |
| Competitive Businesses Natural Gas Revenues | 1,384 | | | 1,024 | | | 2,408 | | | — | | | 2,408 | |
Competitive Businesses Other Revenues(c) | 291 | | | (846) | | | (555) | | | — | | | (555) | |
| Total Generation Consolidated Operating Revenues | $ | 13,090 | | | $ | 1,027 | | | $ | 14,117 | | | $ | — | | | $ | 14,117 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | |
| Nine Months Ended September 30, 2020 |
| Revenues from external customers(a) | | Intersegment
revenues | | Total
Revenues |
| Contracts with customers | | Other(b) | | Total | | |
| Mid-Atlantic | $ | 3,692 | | | $ | (152) | | | $ | 3,540 | | | $ | 21 | | | $ | 3,561 | |
| Midwest | 2,773 | | | 240 | | | 3,013 | | | (6) | | | 3,007 | |
| New York | 1,074 | | | (12) | | | 1,062 | | | (1) | | | 1,061 | |
| ERCOT | 579 | | | 155 | | | 734 | | | 20 | | | 754 | |
| Other Power Regions | 2,718 | | | 300 | | | 3,018 | | | (34) | | | 2,984 | |
| Total Competitive Businesses Electric Revenues | 10,836 | | | 531 | | | 11,367 | | | — | | | 11,367 | |
| Competitive Businesses Natural Gas Revenues | 881 | | | 467 | | | 1,348 | | | — | | | 1,348 | |
Competitive Businesses Other Revenues(c) | 268 | | | 289 | | | 557 | | | — | | | 557 | |
| Total Generation Consolidated Operating Revenues | $ | 11,985 | | | $ | 1,287 | | | $ | 13,272 | | | $ | — | | | $ | 13,272 | |
__________
(a)Includes all wholesale and retail electric sales to third parties and affiliated sales to the Utility Registrants.
(b)Includes revenues from derivatives and leases.
(c)Other represents activities not allocated to a region. See text above for a description of included activities. Includes unrealized mark-to-market losses of $958 million and gains of $238 million in 2021 and 2020, respectively, and elimination of intersegment revenues.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| Six Months Ended June 30, 2022 |
| Revenues from contracts with customers | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Electric revenues | | | | | | | | | | | | | |
| Residential | $ | 1,675 | | | $ | 918 | | | $ | 752 | | | $ | 1,200 | | | $ | 509 | | | $ | 362 | | | $ | 329 | |
| Small commercial & industrial | 736 | | | 237 | | | 151 | | | 281 | | | 73 | | | 107 | | | 101 | |
| Large commercial & industrial | 165 | | | 136 | | | 260 | | | 655 | | | 503 | | | 56 | | | 96 | |
| Public authorities & electric railroads | 20 | | | 15 | | | 14 | | | 31 | | | 16 | | | 7 | | | 8 | |
Other(a) | 472 | | | 130 | | | 196 | | | 359 | | | 100 | | | 113 | | | 136 | |
Total electric revenues(b) | $ | 3,068 | | | $ | 1,436 | | | $ | 1,373 | | | $ | 2,526 | | | $ | 1,201 | | | $ | 645 | | | $ | 670 | |
| Natural gas revenues | | | | | | | | | | | | | |
| Residential | $ | — | | | $ | 289 | | | $ | 378 | | | $ | 68 | | | $ | — | | | $ | 68 | | | $ | — | |
| Small commercial & industrial | — | | | 105 | | | 63 | | | 29 | | | — | | | 29 | | | — | |
| Large commercial & industrial | — | | | — | | | 100 | | | 6 | | | — | | | 6 | | | — | |
| Transportation | — | | | 14 | | | — | | | 7 | | | — | | | 7 | | | — | |
Other(c) | — | | | 5 | | | 47 | | | 10 | | | — | | | 10 | | | — | |
Total natural gas revenues(d) | $ | — | | | $ | 413 | | | $ | 588 | | | $ | 120 | | | $ | — | | | $ | 120 | | | $ | — | |
| Total revenues from contracts with customers | $ | 3,068 | | | $ | 1,849 | | | $ | 1,961 | | | $ | 2,646 | | | $ | 1,201 | | | $ | 765 | | | $ | 670 | |
| | | | | | | | | | | | | |
| Other revenues | | | | | | | | | | | | | |
| Revenues from alternative revenue programs | $ | 75 | | | $ | 6 | | | $ | (32) | | | $ | (22) | | | $ | (7) | | | $ | (3) | | | $ | (12) | |
Other electric revenues(e) | 15 | | | 7 | | | 8 | | | 2 | | | 1 | | | 1 | | | — | |
Other natural gas revenues(e) | — | | | 1 | | | 3 | | | — | | | — | | | — | | | — | |
| | | | | | | | | | | | | |
| Total other revenues | $ | 90 | | | $ | 14 | | | $ | (21) | | | $ | (20) | | | $ | (6) | | | $ | (2) | | | $ | (12) | |
| Total revenues for reportable segments | $ | 3,158 | | | $ | 1,863 | | | $ | 1,940 | | | $ | 2,626 | | | $ | 1,195 | | | $ | 763 | | | $ | 658 | |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 5 — Segment Information
Revenues net of purchased power and fuel expense (Generation):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| Nine Months Ended September 30, 2021 | | Nine Months Ended September 30, 2020 |
| RNF from external customers(a) | | Intersegment
RNF | | Total RNF | | RNF from external customers(a) | | Intersegment
RNF | | Total RNF |
| Mid-Atlantic | $ | 1,698 | | | $ | 14 | | | $ | 1,712 | | | $ | 1,660 | | | $ | 23 | | | $ | 1,683 | |
| Midwest | 2,014 | | | 1 | | | 2,015 | | | 2,180 | | | (2) | | | 2,178 | |
| New York | 873 | | | 7 | | | 880 | | | 714 | | | 11 | | | 725 | |
| ERCOT | (775) | | | (147) | | | (922) | | | 311 | | | 14 | | | 325 | |
| Other Power Regions | 641 | | | (77) | | | 564 | | | 608 | | | (70) | | | 538 | |
| Total RNF for Reportable Segments | 4,451 | | | (202) | | | 4,249 | | | 5,473 | | | (24) | | | 5,449 | |
Other(b) | 1,563 | | | 202 | | | 1,765 | | | 838 | | | 24 | | | 862 | |
| Total Generation RNF | $ | 6,014 | | | $ | — | | | $ | 6,014 | | | $ | 6,311 | | | $ | — | | | $ | 6,311 | |
__________
(a)Includes purchases and sales from/to third parties and affiliated sales to the Utility Registrants.
(b)Other represents activities not allocated to a region. See text above for a description of included activities. Primarily includes:
•unrealized mark-to-market gains of $1,242 million and gains of $472 million in 2021 and 2020, respectively;
•accelerated nuclear fuel amortization associated with announced early plant retirements as discussed in Note 7 — Early Plant Retirements of $148 million and $24 million in 2021 and 2020 respectively; and
• the elimination of intersegment RNF.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)
Note 5 — Segment Information
Electric and Gas Revenue by Customer Class (Utility Registrants):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
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| Nine Months Ended September 30, 2021 |
| Revenues from contracts with customers | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Rate-regulated electric revenues | | | | | | | | | | | | | |
| Residential | $ | 2,479 | | | $ | 1,325 | | | $ | 1,044 | | | $ | 1,924 | | | $ | 785 | | | $ | 535 | | | $ | 604 | |
| Small commercial & industrial | 1,176 | | | 312 | | | 202 | | | 392 | | | 101 | | | 145 | | | 146 | |
| Large commercial & industrial | 420 | | | 183 | | | 342 | | | 825 | | | 616 | | | 70 | | | 139 | |
| Public authorities & electric railroads | 33 | | | 24 | | | 20 | | | 45 | | | 24 | | | 11 | | | 10 | |
Other(a) | 676 | | | 167 | | | 269 | | | 453 | | | 154 | | | 143 | | | 158 | |
Total rate-regulated electric revenues(b) | $ | 4,784 | | | $ | 2,011 | | | $ | 1,877 | | | $ | 3,639 | | | $ | 1,680 | | | $ | 904 | | | $ | 1,057 | |
| Rate-regulated natural gas revenues | | | | | | | | | | | | | |
| Residential | $ | — | | | $ | 251 | | | $ | 354 | | | $ | 67 | | | $ | — | | | $ | 67 | | | $ | — | |
| Small commercial & industrial | — | | | 94 | | | 59 | | | 29 | | | — | | | 29 | | | — | |
| Large commercial & industrial | — | | | — | | | 103 | | | 5 | | | — | | | 5 | | | — | |
| Transportation | — | | | 17 | | | — | | | 11 | | | — | | | 11 | | | — | |
Other(c) | — | | | 4 | | | 41 | | | 6 | | | — | | | 6 | | | — | |
Total rate-regulated natural gas revenues(d) | $ | — | | | $ | 366 | | | $ | 557 | | | $ | 118 | | | $ | — | | | $ | 118 | | | $ | — | |
| Total rate-regulated revenues from contracts with customers | $ | 4,784 | | | $ | 2,377 | | | $ | 2,434 | | | $ | 3,757 | | | $ | 1,680 | | | $ | 1,022 | | | $ | 1,057 | |
| | | | | | | | | | | | | |
| Other revenues | | | | | | | | | | | | | |
| Revenues from alternative revenue programs | $ | 32 | | | $ | 20 | | | $ | (17) | | | $ | 94 | | | $ | 54 | | | $ | 17 | | | $ | 23 | |
Other rate-regulated electric revenues(e) | 24 | | | 2 | | | 7 | | | 3 | | | 2 | | | 1 | | | — | |
Other rate-regulated natural gas revenues(e) | — | | | — | | | 2 | | | — | | | — | | | — | | | — | |
| | | | | | | | | | | | | |
| Total other revenues | $ | 56 | | | $ | 22 | | | $ | (8) | | | $ | 97 | | | $ | 56 | | | $ | 18 | | | $ | 23 | |
| Total rate-regulated revenues for reportable segments | $ | 4,840 | | | $ | 2,399 | | | $ | 2,426 | | | $ | 3,854 | | | $ | 1,736 | | | $ | 1,040 | | | $ | 1,080 | |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)
Note 5 — Segment Information
| | | | Nine Months Ended September 30, 2020 | | Six Months Ended June 30, 2021 |
| Revenues from contracts with customers | Revenues from contracts with customers | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Revenues from contracts with customers | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Rate-regulated electric revenues | | | | | | | | | | | | | | |
| Electric revenues | | Electric revenues | | | | | | | | | | | | | |
| Residential | Residential | $ | 2,389 | | | $ | 1,277 | | | $ | 1,034 | | | $ | 1,825 | | | $ | 779 | | | $ | 501 | | | $ | 545 | | Residential | $ | 1,502 | | | $ | 816 | | | $ | 662 | | | $ | 1,142 | | | $ | 476 | | | $ | 337 | | | $ | 329 | |
| Small commercial & industrial | Small commercial & industrial | 1,067 | | | 291 | | | 183 | | | 355 | | | 101 | | | 127 | | | 127 | | Small commercial & industrial | 744 | | | 199 | | | 129 | | | 242 | | | 65 | | | 92 | | | 85 | |
| Large commercial & industrial | Large commercial & industrial | 388 | | | 174 | | | 311 | | | 755 | | | 558 | | | 66 | | | 131 | | Large commercial & industrial | 271 | | | 116 | | | 213 | | | 505 | | | 372 | | | 43 | | | 90 | |
| Public authorities & electric railroads | Public authorities & electric railroads | 33 | | | 21 | | | 20 | | | 45 | | | 25 | | | 10 | | | 10 | | Public authorities & electric railroads | 22 | | | 17 | | | 13 | | | 30 | | | 16 | | | 7 | | | 7 | |
Other(a) | Other(a) | 663 | | | 171 | | | 233 | | | 471 | | | 166 | | | 148 | | | 159 | | Other(a) | 433 | | | 106 | | | 165 | | | 283 | | | 101 | | | 87 | | | 95 | |
Total rate-regulated electric revenues(b) | $ | 4,540 | | | $ | 1,934 | | | $ | 1,781 | | | $ | 3,451 | | | $ | 1,629 | | | $ | 852 | | | $ | 972 | | |
| Rate-regulated natural gas revenues | | |
Total electric revenues(b) | | Total electric revenues(b) | $ | 2,972 | | | $ | 1,254 | | | $ | 1,182 | | | $ | 2,202 | | | $ | 1,030 | | | $ | 566 | | | $ | 606 | |
| Natural gas revenues | | Natural gas revenues | |
| Residential | Residential | $ | — | | | $ | 252 | | | $ | 342 | | | $ | 68 | | | $ | — | | | $ | 68 | | | $ | — | | Residential | $ | — | | | $ | 215 | | | $ | 297 | | | $ | 57 | | | $ | — | | | $ | 57 | | | $ | — | |
| Small commercial & industrial | Small commercial & industrial | — | | | 86 | | | 55 | | | 30 | | | — | | | 30 | | | — | | Small commercial & industrial | — | | | 81 | | | 48 | | | 24 | | | — | | | 24 | | | — | |
| Large commercial & industrial | Large commercial & industrial | — | | | — | | | 96 | | | 3 | | | — | | | 3 | | | — | | Large commercial & industrial | — | | | — | | | 81 | | | 3 | | | — | | | 3 | | | — | |
| Transportation | Transportation | — | | | 18 | | | — | | | 10 | | | — | | | 10 | | | — | | Transportation | — | | | 12 | | | — | | | 8 | | | — | | | 8 | | | — | |
Other(c) | Other(c) | — | | | 3 | | | 16 | | | 5 | | | — | | | 5 | | | — | | Other(c) | — | | | 3 | | | 36 | | | 2 | | | — | | | 3 | | | — | |
Total rate-regulated natural gas revenues(d) | $ | — | | | $ | 359 | | | $ | 509 | | | $ | 116 | | | $ | — | | | $ | 116 | | | $ | — | | |
| Total rate-regulated revenues from contracts with customers | $ | 4,540 | | | $ | 2,293 | | | $ | 2,290 | | | $ | 3,567 | | | $ | 1,629 | | | $ | 968 | | | $ | 972 | | |
Total natural gas revenues(d) | | Total natural gas revenues(d) | $ | — | | | $ | 311 | | | $ | 462 | | | $ | 94 | | | $ | — | | | $ | 95 | | | $ | — | |
| Total revenues from contracts with customers | | Total revenues from contracts with customers | $ | 2,972 | | | $ | 1,565 | | | $ | 1,644 | | | $ | 2,296 | | | $ | 1,030 | | | $ | 661 | | | $ | 606 | |
| | Other revenues | Other revenues | | Other revenues | |
| Revenues from alternative revenue programs | Revenues from alternative revenue programs | $ | (51) | | | $ | 10 | | | $ | (10) | | | $ | (15) | | | $ | 20 | | | $ | (15) | | | $ | (20) | | Revenues from alternative revenue programs | $ | 64 | | | $ | 17 | | | $ | 8 | | | $ | 88 | | | $ | 46 | | | $ | 19 | | | $ | 23 | |
Other rate-regulated electric revenues(e) | 10 | | | 3 | | | 3 | | | 2 | | | 1 | | | 1 | | | — | | |
Other rate-regulated natural gas revenues(e) | — | | | — | | | 1 | | | — | | | — | | | — | | | — | | |
Other electric revenues(e) | | Other electric revenues(e) | 16 | | | — | | | 3 | | | — | | | — | | | — | | | — | |
Other natural gas revenues(e) | | Other natural gas revenues(e) | — | | | — | | | 1 | | | — | | | — | | | — | | | — | |
| | Total other revenues | Total other revenues | $ | (41) | | | $ | 13 | | | $ | (6) | | | $ | (13) | | | $ | 21 | | | $ | (14) | | | $ | (20) | | Total other revenues | $ | 80 | | | $ | 17 | | | $ | 12 | | | $ | 88 | | | $ | 46 | | | $ | 19 | | | $ | 23 | |
| Total rate-regulated revenues for reportable segments | $ | 4,499 | | | $ | 2,306 | | | $ | 2,284 | | | $ | 3,554 | | | $ | 1,650 | | | $ | 954 | | | $ | 952 | | |
| Total revenues for reportable segments | | Total revenues for reportable segments | $ | 3,052 | | | $ | 1,582 | | | $ | 1,656 | | | $ | 2,384 | | | $ | 1,076 | | | $ | 680 | | | $ | 629 | |
__________
(a)Includes revenues from transmission revenue from PJM, wholesale electric revenue and mutual assistance revenue.
(b)Includes operating revenues from affiliates in 20212022 and 20202021 respectively of:
•$198 million, $31$11 million at ComEd
•$52 million, $6$3 million at PECO
•$103 million, $9$5 million at BGE
•$10 million, $13 million at PHI
•$4 million, $6 million at Pepco
•$6 million, $7 million at PHI
•$2 million, $3 million at Pepco
•$3 million, $4 million at DPL
•$2 million, $3$1 million at ACE
(c)Includes revenues from off-system natural gas sales.
(d)Includes operating revenues from affiliates in 20212022 and 20202021 respectively of:
•$1less than $1 million, $1 million at PECO
•$107 million, $7 million at BGE
(e)Includes late payment charge revenues.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 6 — Accounts Receivable
6. Accounts Receivable (All Registrants)
Allowance for Credit Losses on Accounts Receivable (All Registrants)
The following tables present the rollforward of Allowance for Credit Losses on Customer Accounts Receivable.
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| Three Months Ended September 30, 2021 |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Balance as of June 30, 2021 | $ | 395 | | | $ | 75 | | | $ | 89 | | | $ | 111 | | | $ | 27 | | | $ | 93 | | | $ | 38 | | | $ | 19 | | | $ | 36 | |
Plus: Current period provision for expected credit losses(a) | 47 | | | 10 | | | 11 | | | 1 | | | 7 | | | 18 | | | 5 | | | 3 | | | 10 | |
Less: Write-offs, net of recoveries(b) | 33 | | | 1 | | | 12 | | | 11 | | | 3 | | | 6 | | | 2 | | | 4 | | | — | |
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| Balance as of September 30, 2021 | $ | 409 | | | $ | 84 | | | $ | 88 | | | $ | 101 | | | $ | 31 | | | $ | 105 | | | $ | 41 | | | $ | 18 | | | $ | 46 | |
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| Three Months Ended September 30, 2020 |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Balance as of June 30, 2020 | $ | 261 | | | $ | 33 | | | $ | 72 | | | $ | 71 | | | $ | 23 | | | $ | 62 | | | $ | 24 | | | $ | 18 | | | $ | 20 | |
Plus: Current period provision for expected credit losses(c) | 114 | | | 1 | | | 37 | | | 27 | | | 14 | | | 35 | | | 11 | | | 7 | | | 17 | |
Less: Write-offs, net of recoveries(b) | 17 | | | 1 | | | 4 | | | 2 | | | 2 | | | 8 | | | — | | | 3 | | | 5 | |
| | | | | | | | | | | | | | | | | |
| Balance as of September 30, 2020 | $ | 358 | | | $ | 33 | | | $ | 105 | | | $ | 96 | | | $ | 35 | | | $ | 89 | | | $ | 35 | | | $ | 22 | | | $ | 32 | |
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| Three Months Ended June 30, 2022 |
| Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Balance as of March 31, 2022 | $ | 389 | | | $ | 92 | | | $ | 125 | | | $ | 59 | | | $ | 113 | | | $ | 40 | | | $ | 24 | | | $ | 49 | |
| Plus: Current period (benefit) provision for expected credit losses | (9) | | | (5) | | | (10) | | | 2 | | | 4 | | | 5 | | | — | | | (1) | |
Less: Write-offs, net of recoveries(a) | 26 | | | 6 | | | 8 | | | 4 | | | 8 | | | 3 | | | 2 | | | 3 | |
| Balance as of June 30, 2022 | $ | 354 | | | $ | 81 | | | $ | 107 | | | $ | 57 | | | $ | 109 | | | $ | 42 | | | $ | 22 | | | $ | 45 | |
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| Three Months Ended June 30, 2021 |
| Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Balance as of March 31, 2021 | $ | 377 | | | $ | 103 | | | $ | 130 | | | $ | 43 | | | $ | 101 | | | $ | 41 | | | $ | 25 | | | $ | 35 | |
| Plus: Current period (benefit) provision for expected credit losses | (42) | | | (9) | | | (14) | | | (14) | | | (5) | | | (1) | | | (5) | | | 1 | |
Less: Write-offs, net of recoveries(a) | 15 | | | 5 | | | 5 | | | 2 | | | 3 | | | 2 | | | 1 | | | — | |
| Balance as of June 30, 2021 | $ | 320 | | | $ | 89 | | | $ | 111 | | | $ | 27 | | | $ | 93 | | | $ | 38 | | | $ | 19 | | | $ | 36 | |
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| Six Months Ended June 30, 2022 |
| Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Balance as of December 31, 2021 | $ | 320 | | | $ | 73 | | | $ | 105 | | | $ | 38 | | | $ | 104 | | | $ | 37 | | | $ | 18 | | | $ | 49 | |
Plus: Current period provision for expected credit losses(b) | 101 | | | 21 | | | 21 | | | 28 | | | 31 | | | 16 | | | 7 | | | 8 | |
Less: Write-offs, net of recoveries(a)(c) | 67 | | | 13 | | | 19 | | | 9 | | | 26 | | | 11 | | | 3 | | | 12 | |
| Balance as of June 30, 2022 | $ | 354 | | | $ | 81 | | | $ | 107 | | | $ | 57 | | | $ | 109 | | | $ | 42 | | | $ | 22 | | | $ | 45 | |
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| Six Months Ended June 30, 2021 |
| Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Balance as of December 31, 2020 | $ | 334 | | | $ | 97 | | | $ | 116 | | | $ | 35 | | | $ | 86 | | | $ | 32 | | | $ | 22 | | | $ | 32 | |
| Plus: Current period provision (benefit) for expected credit losses | 28 | | | 12 | | | 6 | | | (5) | | | 15 | | | 10 | | | 1 | | | 4 | |
Less: Write-offs, net of recoveries(a) | 42 | | | 20 | | | 11 | | | 3 | | | 8 | | | 4 | | | 4 | | | — | |
| Balance as of June 30, 2021 | $ | 320 | | | $ | 89 | | | $ | 111 | | | $ | 27 | | | $ | 93 | | | $ | 38 | | | $ | 19 | | | $ | 36 | |
__________
(a)Recoveries were not material to the Registrants.
(b)For BGE, Pepco, and ACE, the increase is primarily as a result of increased receivable balances due to the increased aging of receivables.
(c)For ACE, the increase in 2022 is primarily related to the termination of the moratorium, which beginning in March 2020, prevented customer disconnections for non-payment. With disconnection activities restarting in January 2022, write-offs of aging accounts receivable increased throughout the year.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)
Note 6 — Accounts Receivable
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| Nine Months Ended September 30, 2021 |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Balance as of December 31, 2020 | $ | 366 | | | $ | 32 | | | $ | 97 | | | $ | 116 | | | $ | 35 | | | $ | 86 | | | $ | 32 | | | $ | 22 | | | $ | 32 | |
Plus: Current period provision for expected credit losses(d) | 122 | | | 57 | | | 23 | | | 7 | | | 2 | | | 33 | | | 15 | | | 4 | | | 14 | |
Less: Write-offs, net of recoveries(b) | 79 | | | 5 | | | 32 | | | 22 | | | 6 | | | 14 | | | 6 | | | 8 | | | — | |
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| Balance as of September 30, 2021 | $ | 409 | | | $ | 84 | | | $ | 88 | | | $ | 101 | | | $ | 31 | | | $ | 105 | | | $ | 41 | | | $ | 18 | | | $ | 46 | |
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| Nine Months Ended September 30, 2020 |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Balance as of December 31, 2019 | $ | 243 | | | $ | 80 | | | $ | 59 | | | $ | 55 | | | $ | 12 | | | $ | 37 | | | $ | 13 | | | $ | 11 | | | $ | 13 | |
Plus: Current period provision for expected credit losses(c) | 222 | | | 13 | | | 62 | | | 56 | | | 28 | | | 63 | | | 24 | | | 14 | | | 25 | |
Less: Write-offs, net of recoveries(b) | 51 | | | 4 | | | 16 | | | 15 | | | 5 | | | 11 | | | 2 | | | 3 | | | 6 | |
Less: Sale of customer accounts receivable(e) | 56 | | | 56 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Balance as of September 30, 2020 | $ | 358 | | | $ | 33 | | | $ | 105 | | | $ | 96 | | | $ | 35 | | | $ | 89 | | | $ | 35 | | | $ | 22 | | | $ | 32 | |
__________
(a)For ACE, the increase is primarily a result of increased aging of receivables and a slight decrease in the expected recovery rate.
(b)—Recoveries were not material to the Registrants. (Continued)
(c)For the Utility Registrants, the increase is primarily as a result of increased aging of receivables, the temporary suspension of customer disconnections for non-payment, temporary cessation of new late payment fees, and reconnections of service to customers previously disconnected due to COVID-19.
(d)For Generation, primarily relates to the impacts of the February 2021 extreme cold weather event. See Note 3 — Regulatory Matters for additional information. For PHI, Pepco, and ACE, the increase is primarily a result of increased aging of receivables and a slight decrease in the expected recovery rate.
(e)See below for additional information on the sale of customer accounts receivable at Generation in the second quarter of 2020.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)
Note 6 — Accounts Receivable
The following tables present the rollforward of Allowance for Credit Losses on Other Accounts Receivable.
| | | Three Months Ended September 30, 2021 | | Three Months Ended June 30, 2022 |
| | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Balance as of June 30, 2021 | $ | 72 | | | $ | 1 | | | $ | 18 | | | $ | 7 | | | $ | 8 | | | $ | 38 | | | $ | 16 | | | $ | 9 | | | $ | 13 | | |
| Plus: Current period provision for expected credit losses | 9 | | | 3 | | | 2 | | | 1 | | | 1 | | | 2 | | | 1 | | | (1) | | | 2 | | |
| Balance as of March 31, 2022 | | Balance as of March 31, 2022 | $ | 81 | | | $ | 20 | | | $ | 9 | | | $ | 11 | | | $ | 41 | | | $ | 18 | | | $ | 9 | | | $ | 14 | |
| Plus: Current period provision (benefit) for expected credit losses | | Plus: Current period provision (benefit) for expected credit losses | 2 | | | (2) | | | 2 | | | 1 | | | 1 | | | 2 | | | (1) | | | — | |
Less: Write-offs, net of recoveries(a) | Less: Write-offs, net of recoveries(a) | 4 | | | — | | | 1 | | | 1 | | | 1 | | | — | | | — | | | — | | | — | | Less: Write-offs, net of recoveries(a) | 2 | | | — | | | 1 | | | 1 | | | — | | | — | | | — | | | — | |
| Balance as of September 30, 2021 | $ | 77 | | | $ | 4 | | | $ | 19 | | | $ | 7 | | | $ | 8 | | | $ | 40 | | | $ | 17 | | | $ | 8 | | | $ | 15 | | |
| Balance as of June 30, 2022 | | Balance as of June 30, 2022 | $ | 81 | | | $ | 18 | | | $ | 10 | | | $ | 11 | | | $ | 42 | | | $ | 20 | | | $ | 8 | | | $ | 14 | |
| | | Three Months Ended September 30, 2020 | | Three Months Ended June 30, 2021 |
| | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Balance as of June 30, 2020 | $ | 61 | | | $ | — | | | $ | 22 | | | $ | 7 | | | $ | 6 | | | $ | 26 | | | $ | 11 | | | $ | 7 | | | $ | 8 | | |
| Balance as of March 31, 2021 | | Balance as of March 31, 2021 | $ | 79 | | | $ | 22 | | | $ | 11 | | | $ | 9 | | | $ | 37 | | | $ | 15 | | | $ | 10 | | | $ | 12 | |
| Plus: Current period (benefit) provision for expected credit losses | | Plus: Current period (benefit) provision for expected credit losses | (5) | | | (3) | | | (3) | | | — | | | 1 | | | 1 | | | (1) | | | 1 | |
Less: Write-offs, net of recoveries(a) | | Less: Write-offs, net of recoveries(a) | 3 | | | 1 | | | 1 | | | 1 | | | — | | | — | | | — | | | — | |
| Balance as of June 30, 2021 | | Balance as of June 30, 2021 | $ | 71 | | | $ | 18 | | | $ | 7 | | | $ | 8 | | | $ | 38 | | | $ | 16 | | | $ | 9 | | | $ | 13 | |
| | | | Six Months Ended June 30, 2022 |
| | | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Balance as of December 31, 2021 | | Balance as of December 31, 2021 | $ | 72 | | | $ | 17 | | | $ | 7 | | | $ | 9 | | | $ | 39 | | | $ | 16 | | | $ | 8 | | | $ | 15 | |
| Plus: Current period provision for expected credit losses | Plus: Current period provision for expected credit losses | 15 | | | — | | | 5 | | | 1 | | | 3 | | | 6 | | | 2 | | | 1 | | | 3 | | Plus: Current period provision for expected credit losses | 15 | | | 2 | | | 4 | | | 4 | | | 5 | | | 4 | | | — | | | 1 | |
Less: Write-offs, net of recoveries(a) | Less: Write-offs, net of recoveries(a) | 1 | | | — | | | — | | | 1 | | | — | | | — | | | — | | | — | | | — | | Less: Write-offs, net of recoveries(a) | 6 | | | 1 | | | 1 | | | 2 | | | 2 | | | — | | | — | | | 2 | |
| Balance as of September 30, 2020 | $ | 75 | | | $ | — | | | $ | 27 | | | $ | 7 | | | $ | 9 | | | $ | 32 | | | $ | 13 | | | $ | 8 | | | $ | 11 | | |
| Balance as of June 30, 2022 | | Balance as of June 30, 2022 | $ | 81 | | | $ | 18 | | | $ | 10 | | | $ | 11 | | | $ | 42 | | | $ | 20 | | | $ | 8 | | | $ | 14 | |
| | | Nine Months Ended September 30, 2021 | | Six Months Ended June 30, 2021 |
| | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Balance as of December 31, 2020 | Balance as of December 31, 2020 | $ | 71 | | | $ | — | | | $ | 21 | | | $ | 8 | | | $ | 9 | | | $ | 33 | | | $ | 13 | | | $ | 9 | | | $ | 11 | | Balance as of December 31, 2020 | $ | 71 | | | $ | 21 | | | $ | 8 | | | $ | 9 | | | $ | 33 | | | $ | 13 | | | $ | 9 | | | $ | 11 | |
| Plus: Current period provision for expected credit losses | 15 | | | 4 | | | — | | | 2 | | | 2 | | | 7 | | | 4 | | | (1) | | | 4 | | |
| Plus: Current period provision (benefit) for expected credit losses | | Plus: Current period provision (benefit) for expected credit losses | 5 | | | (2) | | | 1 | | | 1 | | | 5 | | | 3 | | | — | | | 2 | |
Less: Write-offs, net of recoveries(a) | Less: Write-offs, net of recoveries(a) | 9 | | | — | | | 2 | | | 3 | | | 3 | | | — | | | — | | | — | | | — | | Less: Write-offs, net of recoveries(a) | 5 | | | 1 | | | 2 | | | 2 | | | — | | | — | | | — | | | — | |
| Balance as of September 30, 2021 | $ | 77 | | | $ | 4 | | | $ | 19 | | | $ | 7 | | | $ | 8 | | | $ | 40 | | | $ | 17 | | | $ | 8 | | | $ | 15 | | |
| | Nine Months Ended September 30, 2020 | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | |
| Balance as of December 31, 2019 | $ | 48 | | | $ | — | | | $ | 20 | | | $ | 7 | | | $ | 5 | | | $ | 16 | | | $ | 7 | | | $ | 4 | | | $ | 5 | | |
| Plus: Current period provision for expected credit losses | 36 | | | — | | | 9 | | | 3 | | | 7 | | | 17 | | | 6 | | | 4 | | | 7 | | |
Less: Write-offs, net of recoveries(a) | 9 | | | — | | | 2 | | | 3 | | | 3 | | | 1 | | | — | | | — | | | 1 | | |
| Balance as of September 30, 2020 | $ | 75 | | | $ | — | | | $ | 27 | | | $ | 7 | | | $ | 9 | | | $ | 32 | | | $ | 13 | | | $ | 8 | | | $ | 11 | | |
| Balance as of June 30, 2021 | | Balance as of June 30, 2021 | $ | 71 | | | $ | 18 | | | $ | 7 | | | $ | 8 | | | $ | 38 | | | $ | 16 | | | $ | 9 | | | $ | 13 | |
__________
(a)Recoveries were not material to the Registrants.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)
Note 6 — Accounts Receivable
Unbilled Customer Revenue (All Registrants)
The following table provides additional information about unbilled customer revenues recorded in the Registrants' Consolidated Balance Sheets as of SeptemberJune 30, 20212022 and December 31, 2020.2021.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Unbilled customer revenues(a) |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| September 30, 2021 | $ | 941 | | | $ | 359 | | | $ | 224 | | | $ | 113 | | | $ | 98 | | | $ | 147 | | | $ | 70 | | | $ | 34 | | | $ | 43 | |
| December 31, 2020 | 998 | | | 258 | | | 218 | | | 147 | | | 197 | | | 178 | | | 87 | | | 62 | | | 29 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Unbilled customer revenues(a) |
| Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| June 30, 2022 | $ | 636 | | | $ | 191 | | | $ | 138 | | | $ | 123 | | | $ | 184 | | | $ | 94 | | | $ | 41 | | | $ | 49 | |
| December 31, 2021 | 747 | | | 240 | | | 161 | | | 171 | | | 175 | | | 82 | | | 53 | | | 40 | |
__________
(a)Unbilled customer revenues are classified in Customer accounts receivables, net in the Registrants' Consolidated Balance Sheets.
Sales of Customer Accounts Receivable (Exelon and Generation)
On April 8, 2020, NER, a bankruptcy remote, special purpose entity, which is wholly-owned by Generation, entered into a revolving accounts receivable financing arrangement with a number of financial institutions and a commercial paper conduit (the Purchasers) to sell certain customer accounts receivable (the Facility). The Facility had a maximum funding limit of $750 million and was scheduled to expire on April 7, 2021, unless renewed by the mutual consent of the parties in accordance with its terms. The Facility was renewed on March 29, 2021. The Facility term was extended through March 29, 2024, unless further renewed by the mutual consent of the parties, and the maximum funding limit was increased to $900 million.Under the Facility, NER may sell eligible short-term customer accounts receivable to the Purchasers in exchange for cash and subordinated interest. The transfers are reported as sales of receivables in Exelon’s and Generation’s consolidated financial statements. The subordinated interest in collections upon the receivables sold to the Purchasers is referred to as the DPP, which is reflected in Other current assets in Exelon’s and Generation’s Consolidated Balance Sheets.
The Facility requires the balance of eligible receivables to be maintained at or above the balance of cash proceeds received from the Purchasers. To the extent the eligible receivables decrease below such balance, Generation is required to repay cash to the Purchasers. When eligible receivables exceed cash proceeds, Generation has the ability to increase the cash received up to the maximum funding limit. These cash inflows and outflows impact the DPP.
On April 8, 2020, Generation derecognized and transferred approximately $1.2 billion of receivables at fair value to the Purchasers in exchange for approximately $500 million in cash purchase price and $650 million of DPP.
During the first quarter of 2021, Generation received additional cash of $250 million from the Purchasers for the remaining available funding in the Facility.
Additionally, during the first quarter of 2021, Generation received cash of approximately $150 million from the Purchasers in connection with the increased funding limit at the time of the Facility renewal.
During the second quarter of 2021, Generation returned cash of $50 million to the Purchasers due to the eligible receivables decreasing temporarily. Subsequently, in the second quarter, Generation received cash of $50 million from the Purchasers as a result of an increase in the eligible receivable balance. The $50 million cash outflow and inflow is included in the Collection of DPP line within Cash flows from investing activities in Exelon’s and Generation’s Consolidated Statements of Cash Flows.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)
Note 6 — Accounts Receivable
The following table summarizes the impact of the sale of certain receivables:
| | | | | | | | | | | |
| September 30, 2021 | | December 31, 2020 |
| Derecognized receivables transferred at fair value | $ | 1,401 | | | $ | 1,139 | |
| Cash proceeds received | 900 | | | 500 | |
| DPP | 501 | | | 639 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | 2021 | | 2020 | | 2021 | | 2020 |
Loss on sale of receivables(a) | | $ | 1 | | | $ | 8 | | | $ | 26 | | | $ | 23 | |
__________
(a)Reflected in Operating and maintenance expense in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income.
| | | | | | | | | | | |
| Nine Months Ended September 30, |
| 2021 | | 2020 |
Proceeds from new transfers(a) | $ | 4,440 | | | $ | 1,889 | |
Cash collections received on DPP and reinvested in the Facility(b) | 2,652 | | | 2,518 | |
| Cash collections reinvested in the Facility | 7,092 | | | 4,407 | |
__________
(a)Customer accounts receivable sold into the Facility were— $7,373 million (Continued)and $4,515 million for the nine months ended September 30, 2021 and September 30, 2020, respectively.
(b)Does not include the $400 million in cash proceeds received from the Purchasers in the first quarter of 2021.
Generation’s risk of loss following the transfer of accounts receivable is limited to the DPP outstanding. Payment of DPP is not subject to significant risks other than delinquencies and credit losses on accounts receivable transferred, which have historically been and are expected to be immaterial. Generation continues to service the receivables sold in exchange for a servicing fee. Generation did not record a servicing asset or liability as the servicing fees were immaterial.
Generation recognizes the cash proceeds received upon sale in Net cash provided by operating activities in the Consolidated Statements of Cash Flows. The collection and reinvestment of DPP is recognized in Net cash provided by investing activities in the Consolidated Statements of Cash Flows.
See Note 14 — Fair Value of Financial Assets and Liabilities and Note 17 — Variable Interest Entities for additional information.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)
Note 6 — Accounts Receivable
Other Purchases and Sales of Customer and Other Accounts Receivables (All Registrants)
Generation is required, under supplier tariffs in ISO-NE, MISO, NYISO, and PJM, to sell customer and other receivables to utility companies, which include the Utility Registrants. The Utility Registrants are required, under separate legislation and regulations in Illinois, Pennsylvania, Maryland, District of Columbia, Delaware, and New Jersey, to purchase certain receivables from alternative retail electric and, as applicable, natural gas suppliers that participate in the utilities' consolidated billing. The following tables presenttable presents the total receivables purchased and sold.purchased.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2021 |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Total receivables purchased | $ | 2,945 | | | $ | — | | | $ | 810 | | | $ | 795 | | | $ | 531 | | | $ | 826 | | | $ | 504 | | | $ | 166 | | | $ | 156 | |
| Total receivables sold | 100 | | | 117 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| | | | | | | | | | | | | | | | | |
| Related party transactions: | | | | | | | | | | | | | | | | | |
| Receivables purchased from Generation | — | | | — | | | — | | | — | | | 17 | | | — | | | — | | | — | | | — | |
| Receivables sold to the Utility Registrants | — | | | 17 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2020 |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Total receivables purchased | $ | 2,698 | | | $ | — | | | $ | 865 | | | $ | 786 | | | $ | 508 | | | $ | 787 | | | $ | 484 | | | $ | 160 | | | $ | 143 | |
| Total receivables sold | 542 | | | 790 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| | | | | | | | | | | | | | | | | |
| Related party transactions: | | | | | | | | | | | | | | | | | |
| Receivables purchased from Generation | — | | | — | | | 34 | | | 67 | | | 75 | | | 72 | | | 51 | | | 13 | | | 8 | |
| Receivables sold to the Utility Registrants | — | | | 248 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Total receivables purchased |
| Exelon(a) | | ComEd | | PECO | | BGE(a) | | PHI | | Pepco | | DPL | | ACE |
| Six months ended June 30, 2022 | $ | 1,911 | | | $ | 456 | | | $ | 518 | | | $ | 391 | | | $ | 546 | | | $ | 342 | | | $ | 104 | | | $ | 100 | |
| Six months ended June 30, 2021 | 1,838 | | | 485 | | | 507 | | | 343 | | | 503 | | | 310 | | | 103 | | | 90 | |
__________
7. Early Plant Retirements (Exelon and Generation)
Exelon and Generation continuously evaluate factors that affect the current and expected economic valueIncludes $4 million of Generation’s plants, including, but not limited to: market power prices, results of capacity auctions, potential legislative and regulatory solutions to ensure plants are fairly compensated for benefits they provide through their carbon-free emissions, reliability, or fuel security, and the impact of potential rulesreceivables purchased from the EPA requiring reduction of carbon and other emissions and the efforts of states to implement those final rules. The precise timing of an early retirement date for any plant, and the resulting financial statement impacts, may be affected by many factors, including the status of potential regulatory or legislative solutions, results of any transmission system reliability study assessments, the nature of any co-owner requirements and stipulations, and NDT fund requirements for nuclear plants, among other factors. However, the earliest retirement date for any plant would usually be the first year in which the unit does not have capacity or other obligations, and where applicable, justGeneration prior to its next scheduled nuclear refueling outage.
Nuclearthe separation on February 1, 2022 for the six months ended June 30, 2022 and $15 million of receivables purchased from Generation for the six months ended June 30, 2021.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 7 — Early Plant Retirements
On August 27, 2020, Generation announced that it intended to permanently cease generation operations at Byron in September 2021 and at Dresden in November 2021. Neither of these nuclear plants cleared in PJM’s capacity auction for the 2022-2023 planning year held in May 2021. Generation’s Braidwood and LaSalle nuclear plants in Illinois did clear in the capacity auction, but were also showing increased signs of economic distress.
On September 15, 2021, the Illinois Public Act 102-0662 was signed into law by the Governor of Illinois (“Clean Energy Law”). The Clean Energy Law is designed to achieve 100% carbon-free power by 2045 to enable the state’s transition to a clean energy economy. Among other things, the Clean Energy Law authorizes the IPA to procure up to 54.5 million CMCs from qualifying nuclear plants for a five-year period beginning on June 1, 2022 through May 31, 2027. CMCs are credits for the carbon-free attributes of eligible nuclear power plants in PJM. The Byron, Dresden, and Braidwood nuclear plants located in Illinois will be eligible to participate in the CMC procurement process and, if awarded contracts, would be committed to operate through May 31, 2027. See Note 3 — Regulatory Matters for additional information. Following enactment of the legislation, Generation announced on September 15, 2021, that it has reversed its previous decision to retire Byron and Dresden given the opportunity for additional revenue under the Clean Energy Law. In addition, Generation no longer considers the Braidwood or LaSalle nuclear plants to be at risk for premature retirement.
As a result of the decision to early retire Byron and Dresden, Exelon and Generation recognized certain one-time charges in the third and fourth quarters of 2020 related to materials and supplies inventory reserve adjustments, employee-related costs including severance benefit costs, and construction work-in-progress impairments, among other items. In addition, there were ongoing annual financial impacts stemming from shortening the expected economic useful lives of these nuclear plants primarily related to accelerated depreciation of plant assets (including any ARC), accelerated amortization of nuclear fuel, and changes in ARO accretion expense associated with the changes in decommissioning timing and cost assumptions to reflect an earlier retirement date.
In the third quarter of 2021, Exelon and Generation reversed $81 million of severance benefit costs and $13 million of other one-time charges initially recorded in Operating and maintenance expense in the third and fourth quarters of 2020 associated with the early retirements. In addition, Generation updated the expected economic useful life for both facilities to 2044 and 2046 for Byron Units 1 and 2, respectively, and to 2029 and 2031 for Dresden Units 2 and 3, respectively, the end of the respective NRC operating license for each unit. Depreciation was therefore adjusted beginning September 15, 2021, to reflect these extended useful life estimates. See Note 8 — Nuclear Decommissioning for additional detail on changes to the nuclear decommissioning ARO balances resulting from the initial decision and subsequent reversal of the decision to early retire Byron and Dresden.
The total impact for the three and nine months ended September 30, 2021 and 2020 in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income resulting from the initial decision and subsequent reversal of the decision to early retire Byron and Dresden is summarized in the table below.
| | | | | | | | | | | | | | | | | | | | |
| Income statement expense (pre-tax) | | Three Months Ended September 30, 2021 | | Nine Months Ended September 30, 2021 | | Three and Nine Months Ended September 30, 2020 |
| Depreciation and amortization | | | | | | |
Accelerated depreciation(a) | | $ | 574 | | | $ | 1,805 | | | $ | 254 | |
| Accelerated nuclear fuel amortization | | 42 | | | 148 | | | 14 | |
| Operating and maintenance | | | | | | |
| One-time charges | | (94) | | | (94) | | | 220 | |
| Other charges | | 4 | | | 8 | | | 34 | |
Contractual offset(b) | | (60) | | | (451) | | | (129) | |
| Total | | $ | 466 | | | $ | 1,416 | | | $ | 393 | |
| | | | | | |
_________
(a)Includes the accelerated depreciation of plant assets including any ARC.
(b)Reflects contractual offset for ARO accretion and ARC depreciation and excludes any changes in earnings in the NDT funds. Decommissioning-related impacts were not offset for the Byron units starting in the second quarter of 2021 due to the inability to recognize a regulatory asset at ComEd. With Generation’s September 15, 2021 reversal of the previous decision to retire Byron, Generation resumed contractual offset for Byron as of that date. Based on the regulatory agreement with the ICC, decommissioning-related activities are offset in Exelon's and Generation's Consolidated
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)
Note 7 — Early Plant Retirements
Statements of Operations and Comprehensive Income as long as the net cumulative decommissioning-related activities result in a regulatory liability at ComEd. The offset resulted in an equal adjustment to the noncurrent payables to ComEd at Generation and an adjustment to the regulatory liabilities at ComEd. See Note 8 — Nuclear Decommissioning for additional information.
Generation remains committed to continued operations for its other nuclear plants receiving state-supported payments under the Illinois ZES (Clinton and Quad Cities), New Jersey ZEC program (Salem), and the New York CES (FitzPatrick, Ginna, and Nine Mile Point) assuming the continued effectiveness of such programs. To the extent such programs do not operate as expected over their full terms, each of these plants would be at heightened risk for early retirement, which could have a material impact on Exelon’s and Generation’s future financial statements. See Note 3 — Regulatory Matters for additional information on the New Jersey ZEC program and Note 3 — Regulatory Matters of the 2020 Form 10-K for additional information on the Illinois ZES and New York CES.
Exelon continues to work with stakeholders on state policy solutions to support continued operation of our nuclear fleet, while also advocating for broader market reforms at the regional and federal level. The absence of such solutions or reforms could have a material unfavorable impact on Exelon's and Generation's future results of operations.
Other Generation
In March 2018, Generation notified ISO-NE of its plans to early retire, among other assets, the Mystic Generating Station's units 8 and 9 (Mystic 8 and 9) absent regulatory reforms to properly value reliability and regional fuel security. Thereafter, ISO-NE identified Mystic 8 and 9 as being needed to ensure fuel security for the region and entered into a cost of service agreement with these two units for the period between June 1, 2022 - May 31, 2024. The agreement was approved by FERC in December 2018.
On June 10, 2020, Generation filed a complaint with FERC against ISO-NE stating that ISO-NE failed to follow its tariff with respect to its evaluation of Mystic 8 and 9 for transmission security for the 2024 to 2025 Capacity Commitment Period and that the modifications that ISO-NE made to its unfiled planning procedures to avoid retaining Mystic 8 and 9 should have been filed with FERC for approval. On August 17, 2020, FERC issued an order denying the complaint. As a result, on August 20, 2020, Exelon determined that Generation will permanently cease generation operations at Mystic 8 and 9 at the expiration of the cost of service commitment in May 2024. See Note 3 — Regulatory Matters for additional discussion of Mystic’s cost of service agreement.
As a result of the decision to early retire Mystic 8 and 9, Exelon and Generation recognized $43 million in the third quarter of 2020 of one-time charges related to an expected long-term contract termination and materials and supplies reserve adjustments, among other items. In addition, there are financial impacts stemming from shortening the expected economic useful life of Mystic 8 and 9 primarily related to accelerated depreciation of plant assets. Exelon and Generation recorded an immaterial amount of incremental Depreciation and amortization expense for the three months ended September 30, 2021 and $41 million for the nine months ended September 30, 2021. Exelon and Generation recorded incremental Depreciation and amortization expense of $6 million for the three and nine months ended September 30, 2020.
8. Nuclear Decommissioning (Exelon and Generation)
Nuclear Decommissioning Asset Retirement Obligations
Generation has a legal obligation to decommission its nuclear power plants following the expiration of their operating licenses. To estimate its decommissioning obligation related to its nuclear generating stations for financial accounting and reporting purposes, Generation uses a probability-weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on decommissioning cost studies, cost escalation rates, probabilistic cash flow models, and discount rates. Generation updates its ARO annually, unless circumstances warrant more frequent
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)
Note 8 — Nuclear Decommissioning
updates, based on its review of updated cost studies and its annual evaluation of cost escalation factors and probabilities assigned to various scenarios.
The financial statement impact for changes in the ARO, on an individual unit basis, due to the changes in and timing of estimated cash flows generally result in a corresponding change in the unit’s ARC in Property, plant, and equipment in Exelon’s and Generation’s Consolidated Balance Sheets. If the ARO decreases for a Non-Regulatory Agreement unit without any remaining ARC, the corresponding change is recorded as decrease in Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.
The following table provides a rollforward of the nuclear decommissioning ARO reflected in Exelon’s and Generation’s Consolidated Balance Sheets from December 31, 2020 to September 30, 2021:
| | | | | |
Nuclear decommissioning ARO at December 31, 2020(a)
| $ | 11,922 | |
Accretion expense | 375 | |
Net increase due to changes in, and timing of, estimated future cash flows | 256 | |
Costs incurred related to decommissioning plants | (57) | |
Nuclear decommissioning ARO at September 30, 2021(a)
| $ | 12,496 | |
_________
(a)Includes $74 million and $80 million as the current portion of the ARO at September 30, 2021 and December 31, 2020, which is included in Other current liabilities in Exelon’s and Generation’s Consolidated Balance Sheets.
During the nine months ended September 30, 2021, the net $256 million increase in the ARO for the changes in the amounts and timing of estimated decommissioning cash flows was driven by multiple adjustments. These adjustments primarily include:
•An increase of approximately $510 million for updated cost escalation rates, primarily for labor and energy, and a decrease in discount rates.
•A net decrease of approximately $170 million was driven by updates to Byron and Dresden reflecting changes in assumed retirement dates and assumed methods of decommissioning as a result of the reversal of the decision to early retire the plants. See Note 7 — Early Plant Retirements for additional information.
•A net decrease of approximately $110 million due to lower estimated costs to decommission Byron, Braidwood, Dresden, LaSalle, and Zion nuclear units resulting from the completion of updated cost studies.
The 2021 ARO updates resulted in a decrease of $51 million in Operating and maintenance expense for the three and nine months ended September 30, 2021 in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income.
NDT Funds
Exelon and Generation had NDT funds totaling $15,602 million and $14,599 million at September 30, 2021 and December 31, 2020, respectively. The NDT funds also include $198 million and $134 million for the current portion of the NDT funds at September 30, 2021 and December 31, 2020, respectively, which are included in Other current assets in Exelon's and Generation's Consolidated Balance Sheets. See Note 18 — Supplemental Financial Information for additional information on activities of the NDT funds.
Accounting Implications of the Regulatory Agreements with ComEd and PECO
Based on the regulatory agreements with the ICC and PAPUC that dictate Generation’s obligations related to the shortfall or excess of NDT funds necessary for decommissioning the former ComEd units on a unit-by-unit basis and the former PECO units in total, decommissioning-related activities net of applicable taxes, including realized and unrealized gains and losses on the NDT funds, depreciation of the ARC, and accretion of the decommissioning obligation, are generally offset in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income and are recorded by Generation and the corresponding regulated utility as a component of the intercompany and regulatory balances in the balance sheet. For the purposes of making
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)
Note 8 — Nuclear Decommissioning
this determination, the decommissioning obligation referred to is different from the calculation used in the NRC minimum funding obligation filings based on NRC guidelines.
For the former ComEd units, given no further recovery from ComEd customers is permitted and Generation retains an obligation to ultimately return any unused NDTs to ComEd customers (on a unit-by-unit basis), to the extent the related NDT investment balances are expected to exceed the total estimated decommissioning obligation for each unit, decommissioning-related activities are offset in the Consolidated Statements of Operations and Comprehensive Income which results with Generation recognizing an intercompany payable to ComEd while ComEd records an intercompany receivable from Generation with a corresponding regulatory liability. However, given the asymmetric settlement provision that does not allow for continued recovery from ComEd customers in the event of a shortfall, recognition of a regulatory asset at ComEd is not permissible and accounting for decommissioning-related activities at Generation for that unit would not be offset, and the impact to Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income could be material during such periods. During the second and third quarter of 2021, a pre-tax charge of $53 million and $140 million, respectively, was recorded in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income for decommissioning-related activities that were not offset for the Byron units due to contractual offset being temporarily suspended. With Generation’s September 15, 2021 reversal of the previous decision to retire Byron and the corresponding adjustment to the ARO for Byron discussed previously, Generation resumed contractual offset for Byron as of that date.
As of September 30, 2021, decommissioning-related activities for all of the former ComEd units, except for Zion, are currently offset in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.
The decommissioning-related activities related to the Non-Regulatory Agreement Units are reflected in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.
See Note 10 — Asset Retirement Obligations of the Exelon 2020 Form 10-K for additional information.
NRC Minimum Funding Requirements
NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in specified minimum amounts to decommission the facility at the end of its life.
Generation filed its biennial decommissioning funding status report with the NRC on February 24, 2021 for all units, including its shutdown units, except for Zion Station which is included in a separate report to the NRC submitted by ZionSolutions, LLC. The status report demonstrated adequate decommissioning funding assurance as of December 31, 2020 for all units except for Byron Units 1 and 2. Generation filed an updated decommissioning funding status report for Byron Units 1 and 2 and Dresden Units 2 and 3 on September 28, 2021 based on their current license expiration dates consistent with Generation’s announcements regarding the continued operations of these units. This report demonstrated adequate decommissioning funding assurance as of December 31, 2020 for Byron Units 1 and 2 and Dresden Units 2 and 3.
Generation will file its next decommissioning funding status report with the NRC by March 31, 2022. This report will reflect the status of decommissioning funding assurance as of December 31, 2021 for shutdown units.
9. Asset Impairments (Exelon and Generation)
The Registrants evaluate the carrying value of long-lived assets or asset groups for recoverability whenever events or changes in circumstances indicate that the carrying value of those assets may not be recoverable. Indicators of impairment may include a deteriorating business climate, including, but not limited to, declines in energy prices, condition of the asset, specific regulatory disallowance, or plans to dispose of a long-lived asset significantly before the end of its useful life. The Registrants determine if long-lived assets or asset groups are impaired by comparing the undiscounted expected future cash flows to the carrying value. When the undiscounted cash flow analysis indicates a long-lived asset or asset group is not recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset or asset group over its fair value. The fair value analysis is primarily based on the income approach using significant unobservable inputs (Level 3) including revenue and generation forecasts, projected capital and maintenance expenditures, and discount rates. A variation in the assumptions used could lead to a different conclusion
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)
Note 9 — Asset Impairments
regarding the recoverability of an asset or asset group and, thus, could potentially result in material future impairments of the Registrant's long-lived assets.
New England Asset Group
In the third quarter of 2020, in conjunction with the retirement announcement of Mystic Units 8 and 9, Generation completed a comprehensive review of the estimated undiscounted future cash flows of the New England asset group and concluded that the estimated undiscounted future cash flows and fair value of the New England asset group were less than their carrying values. As a result, a pre-tax impairment charge of $500 million was recorded in the third quarter of 2020 in Operating and maintenance expense in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. See Note 7 — Early Plant Retirements for additional information.
In the second quarter of 2021, an overall decline in the asset group's portfolio value suggested that the carrying value of the New England asset group may be impaired. Generation completed a comprehensive review of the estimated undiscounted future cash flows of the New England asset group and concluded that the carrying value was not recoverable and that its fair value was less than its carrying value. As a result, a pre-tax impairment charge of $350 million was recorded in the second quarter of 2021 in Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.
Contracted Wind Project
In the third quarter of 2021, significant long-term operational issues anticipated for a specific wind turbine technology suggested that the carrying value of a contracted wind asset, located in Maryland and part of the EGRP joint venture, may be impaired. Generation completed a comprehensive review of the estimated undiscounted future cash flows and concluded that the carrying value of this contracted wind project was not recoverable and that its fair value was less than its carrying value. As a result, in the third quarter of 2021, a pre-tax impairment charge of $45 million was recorded in Operating and maintenance expense, $21 million of which was offset in Net income attributable to noncontrolling interests in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)
Note 10 — Income Taxes
10.7. Income Taxes (All Registrants)
Rate Reconciliation
The effective income tax rate from continuing operations varies from the U.S. federal statutory rate principally due to the following:
| | | Three Months Ended September 30, 2021 | | | |
| | | Three Months Ended June 30, 2022(a) | |
| | Exelon(a) | | Generation(a) | | ComEd(a) | | PECO(a)(b) | | BGE(a)(b) | | PHI(a) | | Pepco(a) | | DPL(a) | | ACE(a)(b) | | | Exelon | | ComEd | | PECO(b) | | BGE(b) | | PHI | | Pepco(b) | | DPL | | ACE(b) | |
| U.S. Federal statutory rate | U.S. Federal statutory rate | 21.0% | | 21.0% | | 21.0% | | 21.0% | | 21.0% | | 21.0% | | 21.0% | | 21.0% | | 21.0% | | U.S. Federal statutory rate | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | |
| Increase (decrease) due to: | Increase (decrease) due to: | | | Increase (decrease) due to: | | |
State income taxes, net of Federal income tax benefit | State income taxes, net of Federal income tax benefit | 6.0 | | 4.4 | | 8.0 | | (4.1) | | (13.0) | | 5.0 | | 3.4 | | 6.4 | | 7.0 | | State income taxes, net of Federal income tax benefit | (5.4) | | | 7.9 | | | (0.6) | | | 2.1 | | | 1.5 | | | (3.4) | | | 7.2 | | | 6.7 | | |
| Qualified NDT fund income | 0.5 | | 0.9 | | — | | — | | — | | — | | — | | — | | — | | |
| | Plant basis differences | | Plant basis differences | (3.3) | | | (0.5) | | | (11.0) | | | (1.3) | | | (1.7) | | | (2.4) | | | (0.7) | | | (1.0) | | |
| Excess deferred tax amortization | | Excess deferred tax amortization | (10.5) | | | (5.5) | | | (3.1) | | | (19.0) | | | (19.2) | | | (15.7) | | | (20.0) | | | (24.5) | | |
| Amortization of investment tax credit, including deferred taxes on basis difference | Amortization of investment tax credit, including deferred taxes on basis difference | (0.4) | | (0.7) | | (0.1) | | — | | (0.1) | | (0.1) | | — | | (0.2) | | (0.2) | | Amortization of investment tax credit, including deferred taxes on basis difference | (0.1) | | | (0.1) | | | — | | | (0.1) | | | (0.1) | | | — | | | (0.2) | | | (0.2) | | |
| Plant basis differences | (1.7) | | — | | (0.8) | | (16.2) | | (1.4) | | (1.3) | | (2.0) | | (0.6) | | (0.6) | | |
| Production tax credits and other credits | (1.0) | | (1.4) | | (0.5) | | — | | (0.9) | | (0.5) | | (0.5) | | (0.4) | | (0.5) | | |
| Noncontrolling interests | (0.4) | | (0.6) | | — | | — | | — | | — | | — | | — | | — | | |
| Excess deferred tax amortization | (6.8) | | — | | (7.6) | | (3.4) | | (17.3) | | (24.9) | | (17.6) | | (19.9) | | (41.4) | | |
| Other(c) | (4.8) | | (1.9) | | 0.3 | | (0.1) | | (0.8) | | — | | 0.1 | | (0.6) | | 0.8 | | |
| Tax credits | | Tax credits | (0.4) | | | (0.3) | | | — | | | (1.5) | | | (0.4) | | | (0.4) | | | (0.4) | | | (0.4) | | |
Other(d) | | Other(d) | 7.7 | | | — | | | — | | | 1.4 | | | (0.1) | | | (0.5) | | | 1.8 | | | (1.6) | | |
| Effective income tax rate | Effective income tax rate | 12.4% | | 21.7% | | 20.3% | | (2.8)% | | (12.5)% | | (0.8)% | | 4.4% | | 5.7% | | (13.9)% | | Effective income tax rate | 9.0 | % | | 22.5 | % | | 6.3 | % | | 2.6 | % | | 1.0 | % | | (1.4) | % | | 8.7 | % | | — | % | |
| | | | Three Months Ended September 30, 2020 | | Three Months Ended June 30, 2021(a) |
| | Exelon(a) | | Generation(a) | | ComEd(a) | | PECO(a)(d) | | BGE(a)(d) | | PHI(a)(d) | | Pepco(a)(d) | | DPL(a)(d) | | ACE(a)(d) | | Exelon | | ComEd | | PECO(e) | | BGE(e) | | PHI | | Pepco(e) | | DPL | | ACE(e) |
| U.S. Federal statutory rate | U.S. Federal statutory rate | 21.0% | | 21.0% | | 21.0% | | 21.0% | | 21.0% | | 21.0% | | 21.0% | | 21.0% | | 21.0% | U.S. Federal statutory rate | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % |
| Increase (decrease) due to: | Increase (decrease) due to: | | Increase (decrease) due to: | |
| State income taxes, net of Federal income tax benefit | State income taxes, net of Federal income tax benefit | 12.3 | | (10.3) | | 8.1 | | (6.2) | | 5.1 | | 5.5 | | 4.6 | | 6.6 | | 6.9 | State income taxes, net of Federal income tax benefit | 1.1 | | | 8.0 | | | (2.9) | | | (12.5) | | | 2.4 | | | (2.1) | | | 7.0 | | | 8.1 | |
| Qualified NDT fund income | 13.2 | | 47.4 | | — | | — | | — | | — | | — | | — | | — | |
| | Plant basis differences | | Plant basis differences | (4.0) | | | (0.7) | | | (12.5) | | | (2.3) | | | (1.1) | | | (1.5) | | | (0.7) | | | (0.6) | |
| Excess deferred tax amortization | | Excess deferred tax amortization | (13.4) | | | (7.0) | | | (3.3) | | | (17.5) | | | (22.3) | | | (19.0) | | | (21.9) | | | (28.2) | |
| Amortization of investment tax credit, including deferred taxes on basis difference | Amortization of investment tax credit, including deferred taxes on basis difference | (1.4) | | (4.5) | | (0.2) | | — | | (0.1) | | (0.2) | | (0.1) | | (0.2) | | (0.3) | Amortization of investment tax credit, including deferred taxes on basis difference | (0.1) | | | (0.1) | | | — | | | (0.1) | | | (0.1) | | | — | | | (0.2) | | | (0.2) | |
| Plant basis differences | (4.3) | | — | | (0.6) | | (23.3) | | (1.2) | | (1.5) | | (2.1) | | (0.4) | | (1.3) | |
| Production tax credits and other credits | (3.0) | | (9.2) | | (0.4) | | — | | (0.8) | | (0.5) | | (0.5) | | (0.5) | | (0.4) | |
| Noncontrolling interests | 0.8 | | 2.9 | | — | | — | | — | | — | | — | | — | | — | |
| Excess deferred tax amortization | (10.1) | | — | | (5.6) | | (3.8) | | (10.6) | | (24.9) | | (20.0) | | (23.6) | | (36.8) | |
| Tax Settlements | (0.2) | | (0.7) | | — | | — | | — | | — | | — | | — | | — | |
| Tax credits | | Tax credits | (1.0) | | | (0.8) | | | — | | | (3.6) | | | (0.8) | | | (0.7) | | | (0.9) | | | (0.6) | |
| Other | Other | (0.8) | | (0.9) | | 1.1 | | (0.8) | | (0.3) | | 0.1 | | (0.4) | | 0.7 | | 0.6 | Other | (2.7) | | | (1.1) | | | (0.4) | | | (6.6) | | | (1.3) | | | (1.9) | | | (1.1) | | | (2.3) | |
| Effective income tax rate | Effective income tax rate | 27.5% | | 45.7% | | 23.4% | | (13.1)% | | 13.1% | | (0.5)% | | 2.5% | | 3.6% | | (10.3)% | Effective income tax rate | 0.9 | % | | 19.3 | % | | 1.9 | % | | (21.6) | % | | (2.2) | % | | (4.2) | % | | 3.2 | % | | (2.8) | % |
__________
(a)Positive percentages represent income tax expense. Negative percentages represent income tax benefit.
(b)For PECO, the incomelower effective tax benefitrate is primarily duerelated to plant basis differences attributable to tax repair deductions. For BGE,
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)
Note 10 — Income Taxes
the incomelower effective tax benefitrate is primarily due to the Maryland multi-year plan which resulted in the acceleration of certain income tax benefits. For ACE,Pepco, the income tax benefit is primarily due to a distribution rate case settlementthe Maryland and Washington, D.C. multi-year plans which allows ACE to retainresulted in the acceleration of certain tax benefits.
(c)For Exelon, "Other" is primarily driven by the reversal of the consolidating income tax adjustment recorded at Exelon Corporate in the first quarter of 2021 that was required pursuant to GAAP interim reporting guidance.
(d)At PECO, the lower effective tax rate is primarily related to an increase in plant basis differences attributable to storm tax repair deductions. At BGE, PHI, Pepco, DPL andbenefits. For ACE, the lower effective tax rate is primarily attributabledue to accelerated amortizationthe acceleration of transmission related deferredcertain income tax regulatory liabilitiesbenefits due to distribution rate case settlements.
(c)For Exelon, the lower state income taxes, net of federal income tax benefit, is primarily related to a one-time impact associated with a state tax benefit of $43 million and indemnification adjustments pursuant to the Tax Matters Agreement of $5 million as a result of regulatory settlements.the separation.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2021 | |
| Exelon(a) | | Generation(b) | | ComEd(a) | | PECO(a)(c) | | BGE(a)(c) | | PHI(a) | | Pepco(a) | | DPL(a) | | ACE(a)(c) | |
| U.S. Federal statutory rate | 21.0% | | 21.0% | | 21.0% | | 21.0% | | 21.0% | | 21.0% | | 21.0% | | 21.0% | | 21.0% | |
| Increase (decrease) due to: | | | | | | | | | | | | | | | | | | |
| State income taxes, net of Federal income tax benefit | 3.0 | | 90.2 | | 7.6 | | (2.6) | | (10.8) | | 4.6 | | 2.5 | | 6.5 | | 7.3 | |
| Qualified NDT fund income | 9.4 | | (1,932.6) | | — | | — | | — | | — | | — | | — | | — | |
| | | | | | | | | | | | | | | | | | |
| Amortization of investment tax credit, including deferred taxes on basis difference | (0.8) | | 130.6 | | (0.1) | | — | | (0.1) | | (0.1) | | — | | (0.2) | | (0.2) | |
| Plant basis differences | (3.9) | | — | | (0.7) | | (12.6) | | (1.5) | | (1.3) | | (1.9) | | (0.7) | | (0.6) | |
| Production tax credits and other credits | (2.6) | | 425.1 | | (0.5) | | — | | (0.9) | | (0.5) | | (0.5) | | (0.4) | | (0.5) | |
| Noncontrolling interests | (0.7) | | 145.2 | | — | | — | | — | | — | | — | | — | | — | |
| Excess deferred tax amortization | (13.9) | | — | | (7.2) | | (3.3) | | (16.0) | | (22.8) | | (17.4) | | (19.7) | | (36.3) | |
| | | | | | | | | | | | | | | | | | |
Other(d) | 2.2 | | (229.5) | | (1.3) | | (0.2) | | (0.7) | | (0.3) | | (0.4) | | (0.2) | | — | |
| Effective income tax rate | 13.7% | | (1,350.0)% | | 18.8% | | 2.3% | | (9.0)% | | 0.6% | | 3.3% | | 6.3% | | (9.3)% | |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)
Note 10 — Income Taxes
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2020 |
| Exelon(a) | | Generation(a) | | ComEd(a)(e) | | PECO(a)(e) | | BGE(a)(e) | | PHI(a)(e) | | Pepco(a)(e) | | DPL(a)(e) | | ACE(a)(e) |
| U.S. Federal statutory rate | 21.0% | | 21.0% | | 21.0% | | 21.0% | | 21.0% | | 21.0% | | 21.0% | | 21.0% | | 21.0% |
| Increase (decrease) due to: | | | | | | | | | | | | | | | | | |
| State income taxes, net of Federal income tax benefit | 9.3 | | — | | 12.7 | | (3.4) | | 5.5 | | 5.0 | | 4.2 | | 6.5 | | 6.8 |
| Qualified NDT fund income | 3.2 | | 10.0 | | — | | — | | — | | — | | — | | — | | — |
| Deferred Prosecution Agreement payments | 2.5 | | — | | 9.4 | | — | | — | | — | | — | | — | | — |
| Amortization of investment tax credit, including deferred taxes on basis difference | (1.2) | | (3.2) | | (0.3) | | — | | (0.1) | | (0.2) | | (0.1) | | (0.3) | | (0.5) |
| Plant basis differences | (4.0) | | — | | (0.9) | | (15.9) | | (1.8) | | (2.2) | | (2.4) | | (0.5) | | (3.7) |
| Production tax credits and other credits | (2.6) | | (7.0) | | (0.4) | | — | | (0.4) | | (0.3) | | (0.3) | | (0.2) | | (0.4) |
| Noncontrolling interests | 1.0 | | 3.1 | | — | | — | | — | | — | | — | | — | | — |
| Excess deferred tax amortization | (15.8) | | — | | (11.8) | | (3.5) | | (15.0) | | (45.3) | | (29.2) | | (53.6) | | (81.4) |
Tax Settlements(f) | (5.0) | | (15.7) | | — | | — | | — | | — | | — | | — | | — |
| Other | 0.1 | | (0.5) | | 2.1 | | (0.5) | | (0.5) | | (0.6) | | (0.8) | | (1.1) | | — |
| Effective income tax rate | 8.5% | | 7.7% | | 31.8% | | (2.3)% | | 8.7% | | (22.6)% | | (7.6)% | | (28.2)% | | (58.2)% |
__________
(a)Positive percentages represent income tax expense. Negative percentages represent income tax benefit.
(b)Generation recognized a loss before income taxes for the nine months ended September 30, 2021. As a result, a negative percentage represents an income tax expense for the period presented.
(c)(e)For PECO, the lower effective tax rate is primarily related to an increase in plant basis differences attributable to tax repair deductions. For BGE, the income tax benefit is primarily due to the Maryland multi-year plan which resulted in the acceleration of certain income tax benefits. For ACE,Pepco, the income tax benefit is primarily due to athe Maryland multi-year plan which resulted in the acceleration of certain income tax benefits. For ACE, the lower effective tax rate is primarily due to the acceleration of certain income tax benefits due to distribution rate case settlement which allows ACE to retain certain tax benefits.settlements.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 7 — Income Taxes
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Six Months Ended June 30, 2022(a) | |
| Exelon | | ComEd | | PECO(b) | | BGE(b) | | PHI | | Pepco(b) | | DPL | | ACE(b) | |
| 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 taxes, net of Federal income tax benefit(c) | 9.9 | | | 7.9 | | | (0.3) | | | 2.3 | | | 2.8 | | | (3.8) | | | 6.5 | | | 6.7 | | |
| Plant basis differences | (3.5) | | | (0.5) | | | (11.2) | | | (1.0) | | | (1.7) | | | (2.5) | | | (0.7) | | | (1.2) | | |
| Excess deferred tax amortization | (11.0) | | | (5.8) | | | (3.2) | | | (17.8) | | | (18.3) | | | (16.3) | | | (19.5) | | | (22.9) | | |
| Amortization of investment tax credit, including deferred taxes on basis difference | (0.1) | | | (0.1) | | | — | | | (0.1) | | | (0.1) | | | — | | | (0.2) | | | (0.2) | | |
Tax credits(d) | 0.8 | | | (0.3) | | | — | | | (0.6) | | | (0.4) | | | (0.4) | | | (0.3) | | | (0.3) | | |
Other(e) | 4.7 | | | 0.1 | | | 0.3 | | | 0.3 | | | 0.1 | | | (0.7) | | | 0.4 | | | (0.5) | | |
| Effective income tax rate | 21.8 | % | | 22.3 | % | | 6.6 | % | | 4.1 | % | | 3.4 | % | | (2.7) | % | | 7.2 | % | | 2.6 | % | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Six Months Ended June 30, 2021(a) |
| Exelon | | ComEd | | PECO(f) | | BGE(f) | | PHI | | Pepco(f) | | DPL | | ACE(f) |
| 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 taxes, net of Federal income tax benefit | 2.0 | | | 7.4 | | | (2.1) | | | (10.5) | | | 4.2 | | | 1.5 | | | 6.6 | | | 7.8 | |
| Plant basis differences | (3.6) | | | (0.6) | | | (11.3) | | | (1.6) | | | (1.3) | | | (1.8) | | | (0.7) | | | (0.7) | |
| Excess deferred tax amortization | (12.5) | | | (7.0) | | | (3.3) | | | (15.9) | | | (20.8) | | | (17.2) | | | (19.7) | | | (28.3) | |
| Amortization of investment tax credit, including deferred taxes on basis difference | (0.1) | | | (0.1) | | | — | | | (0.1) | | | (0.1) | | | — | | | (0.2) | | | (0.2) | |
| Tax credits | (0.5) | | | (0.5) | | | — | | | (0.9) | | | (0.5) | | | (0.5) | | | (0.4) | | | (0.5) | |
| Other | (1.6) | | | (2.3) | | | (0.1) | | | (1.0) | | | (0.7) | | | (0.8) | | | (0.1) | | | (1.1) | |
| Effective income tax rate | 4.7 | % | | 17.9 | % | | 4.2 | % | | (9.0) | % | | 1.8 | % | | 2.2 | % | | 6.5 | % | | (2.0) | % |
__________
(a)Positive percentages represent income tax expense. Negative percentages represent income tax benefit.
(b)For Exelon, "Other" is primarily driven byPECO, the consolidating income tax adjustment recorded at Exelon Corporate in the first quarter of 2021 that was required pursuant to GAAP interim reporting guidance. This incremental expense will reverse by year-end and will not have an impact on annual results.
(e)For ComEd, the higherlower effective tax rate is primarily related to plant basis differences attributable to tax repair deductions. For BGE, the nondeductible Deferred Prosecution Agreement payments.lower effective tax rate is primarily due to the Maryland multi-year plan which resulted in the acceleration of certain income tax benefits. For PECO,Pepco, the income tax benefit is primarily due to the Maryland and Washington, D.C. multi-year plans which resulted in the acceleration of certain income tax benefits. For ACE, the lower effective tax rate is primarily due to the acceleration of certain income tax benefits due to distribution rate case settlements.
(c)For Exelon, the higher state income taxes, net of federal income tax benefit, is primarily due to the long-term marginal state income tax rate change of $67 million and the recognition of a valuation allowance of $40 million against the net deferred tax asset position for certain standalone state filing jurisdictions, partially offset by a one-time impact associated with a state tax benefit of $43 million and indemnification adjustments pursuant to the Tax Matters Agreement of $4 million as a result of the separation.
(d)For Exelon, reflects the income tax expense related to an increase inthe write-off of federal tax credits subject to recapture of $15 million as a result of the separation.
(e)For Exelon, primarily reflects the nondeductible transaction costs of approximately $19 million arising as part of the separation and indemnification adjustments pursuant to the Tax Matters Agreement of $48 million.
(f)For PECO, the lower effective tax rate is primarily related to plant basis differences attributable to storm tax repairsrepair deductions. For BGE, PHI, Pepco, DPL, and ACE, the income tax benefit is primarily attributable to accelerated amortization of transmission related deferred income tax regulatory liabilities as a result of regulatory settlements.
(f)Exelon's and Generation’s unrecognized federal and state tax benefits decreased in the first quarter of 2020 by approximately $411 million due to the settlementMaryland multi-year plan which resulted in the acceleration of a federal refund claim with IRS Appeals. The recognitioncertain income tax benefits. For Pepco, the income tax benefit is primarily due to the Maryland multi-year plan which resulted in the acceleration of thesecertain income tax benefits. For ACE, the lower effective tax rate is primarily due to the acceleration of certain income tax benefits resulted in an increasedue to Exelon's and Generation’s net income of $76 million and $73 million, respectively, in the first quarter of 2020, reflecting a decrease to Exelon's and Generation's income tax expense of $67 million.distribution rate case settlements.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 7 — Income Taxes
Unrecognized Tax Benefits
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)
Note 10 — Income Taxes
Exelon, PHI and ACE have the following unrecognized tax benefits as of SeptemberJune 30, 20212022 and December 31, 2020. Exelon's, Generation's,2021. ComEd's, PECO's, BGE's, Pepco's, and DPL's amounts are not material.
| | | | | | | | | | | | | | | | |
| | | | PHI | | ACE |
| September 30, 2021 | | | | $ | 56 | | | $ | 16 | |
| December 31, 2020 | | | | 52 | | | 15 | |
| | | | | | | | | | | | | | | | | | | |
| Exelon(a) | | | | PHI | | ACE |
| June 30, 2022 | $ | 147 | | | | | $ | 58 | | | $ | 16 | |
| December 31, 2021 | 143 | | | | | 56 | | | 16 | |
__________(a)As of June 30, 2022, Exelon recorded a receivable of $50 million in Noncurrent other assets in the Consolidated Balance Sheet for Constellation’s share of unrecognized tax benefits for periods prior to the separation.
Reasonably possible the total amount of unrecognized tax benefits could significantly increase or decrease within 12 months after the reporting date
As of SeptemberJune 30, 2021,2022, ACE has approximately $14 million of unrecognized state tax benefits that could significantly decrease within the 12 months after the reporting date based on the outcome of pending court cases involving other taxpayers. The unrecognized tax benefit, if recognized, may be included in future base rates and that portion would have no impact to the effective tax rate.
Other Income Tax Matters
CENG Put Option (ExelonSeparation (Exelon)
In the first quarter of 2022, in connection with the separation, Exelon recorded an income tax expense related to continuing operations of $148 million primarily due to the long-term marginal state income tax rate change of $67 million discussed further below, the recognition of valuation allowances of approximately $40 million against the net deferred tax assets positions for certain standalone state filing jurisdictions, the write-off of federal and Generation)state tax credits subject to recapture of $17 million, and nondeductible transaction costs for federal and state taxes of $24 million.
On August 6, 2021, Generation and EDF
Tax Matters Agreement (Exelon)
In connection with the separation, Exelon entered into a settlement agreement pursuant to which Generation purchased EDF’s equity interest in CENG.TMA with Constellation. The TMA governs the respective rights, responsibilities, and obligations between Exelon and Generation recorded deferredConstellation after the separation with respect to tax liabilities, refunds and attributes for open tax years that Constellation was part of $290Exelon’s consolidated group for U.S. federal, state, and local tax purposes.
Indemnification for Taxes. As a former subsidiary of Exelon, Constellation has joint and several liability with Exelon to the IRS and certain state jurisdictions relating to the taxable periods prior to the separation. The TMA specifies that Constellation is liable for their share of taxes required to be paid by Exelon with respect to taxable periods prior to the separation to the extent Constellation would have been responsible for such taxes under the existing Exelon tax sharing agreement. As a result, Exelon recorded a receivable of $55 million and $288 million, respectively, against Common Stock in Exelon’sCurrent other assets in the Consolidated Balance Sheet for Constellation’s share of taxes for periods prior to the separation, as of March 31, 2022. As of June 30, 2022, the remaining amount of the receivable is $31 million.
Tax Refunds. The TMA specifies that Constellation is entitled to their share of any future tax refunds claimed by Exelon with respect to taxable periods prior to the separation to the extent that Constellation would have received such tax refunds under the existing Exelon tax sharing agreement.
Tax Attributes. At the date of separation certain tax attributes, primarily pre-closing tax credit carryforwards, that were generated by Constellation were required by law to be allocated to Exelon. The TMA also provides that Exelon will reimburse Constellation when those allocated tax credit carryforwards are utilized. As of March 31, 2022, Exelon recorded a payable of $11 million and Membership Interest$484 million in Generation’sCurrent other liabilities and Noncurrent other liabilities, respectively, in the Consolidated Balance Sheet. The deferredSheet for tax liabilities representcredit carryforwards that are expected to be utilized and reimbursed to Constellation. As of June 30, 2022, the tax effect on the difference between the net purchase pricecurrent and EDF’s noncontrolling interest asnoncurrent payable amounts are $0 million and $480 million, respectively.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 2 – Mergers, Acquisitions, and Dispositions for additional information.7 — Income Taxes
Long-Term Marginal State Income Tax Rate (All Registrants)
In the thirdfirst quarter of 2021 and 2020,2022, Exelon updated its marginal state income tax rates for changes in state apportionment. The changes in marginal rates inapportionment due to the third quarter of 2021separation, which resulted in an increase of $27$67 million to the deferred income tax liability at Exelon, and a corresponding adjustment to income tax expense, net of federal taxes.
Pennsylvania Corporate Income Tax Rate Change (Exelon and PECO)
On July 8, 2022, Pennsylvania enacted House Bill 1342, which will permanently reduce the corporate income tax rate from 9.99% to 4.99%. The changestax rate will be reduced to 8.99% for the 2023 tax year. Starting with the 2024 tax year, the rate is reduced by 0.50% annually until it reaches 4.99% in marginal rates2031. As a result of the rate change, in the third quarter of 2020 resulted in2022, Exelon and PECO will record an increaseestimated one-time decrease to deferred income taxes of $66$390 million andwith a corresponding decrease of $26 million to the deferred income tax liability at Exelontaxes regulatory asset of $428 million for the amounts that are expected to be settled through future customer rates and Generation, respectively. Exelon and Generation recorded a corresponding adjustmentan increase to income tax expense netof $38 million (net of federal taxes.
Allocation of Tax Benefits (All Registrants)
Generation and the Utility Registrants are all party to an agreement with Exelon and other subsidiaries of Exelon that provides for the allocation of consolidated tax liabilities and benefits (Tax Sharing Agreement)taxes). The Tax Sharing Agreement provides that each partytax rate decrease is allocated an amount of tax similarnot expected to that which would be owed had the party been separately subjecthave a material ongoing impact to tax. In addition, any net benefit attributable to Exelon is reallocated to the other Registrants. That allocation is treated as a contribution to the capital of the party receiving the benefit.
The following table presents the allocation of federal tax benefits from Exelon under the Tax Sharing Agreement.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| September 30, 2021 | $ | 64 | | | $ | 1 | | | $ | 19 | | | $ | — | | | $ | 17 | | | $ | 16 | | | $ | — | | | $ | — | |
| September 30, 2020 | 64 | | | 14 | | | 17 | | | — | | | 17 | | | 8 | | | 6 | | | 1 | |
11.8. Retirement Benefits (All Registrants)
Defined Benefit Pension and OPEB
DuringEffective February 1, 2022, in connection with the first quarter of 2021, Exelon received an updated valuation of itsseparation, pension and OPEB obligations and assets for current and former employees of the Constellation business and certain other former employees of Exelon and its subsidiaries transferred to reflect actual census data aspension and OPEB plans and trusts maintained by Constellation or its subsidiaries. The Exelon New England Union Employees Pension Plan and Constellation Mystic Power, LLC Union Employees Pension Plan Including Plan A and Plan B were transferred. The following OPEB plans were also transferred: Constellation Mystic Power, LLC Post-Employment Medical Account Savings Plan, Exelon New England Union Post-Employment Medical Savings Account Plan, and the Nine Mile Point Nuclear Station, LLC Medical Care and Prescription Drug Plan for Retired Employees.
As a result of January 1, 2021. This valuation resultedthe separation, Exelon restructured certain of its qualified pension plans. Pension obligations and assets for current and former employees continuing with Exelon and who are participants in an increasethe Exelon Employee Pension Plan for Clinton, TMI, and Oyster Creek, Pension Plan of Constellation Energy Nuclear Group, LLC, and Nine Mile Point Pension Plan were merged into the Pension Plan of Constellation Energy Group, Inc, which was subsequently renamed, Exelon Pension Plan (EPP). Exelon employees who participated in these plans prior to the pension obligationsseparation now participate in the EPP. The merging of $33 million and a decreasethe plans did not change the benefits offered to the OPEB obligations of $9 million. Additionally, accumulated other comprehensive lossplan participants and, thus, had no impact on Exelon's pension obligations.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 118 — Retirement Benefits
increasedThe tables below show the pension and OPEB plans in which employees of each operating company participated as of June 30, 2022:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Operating Company(a) |
| Name of Plan: | | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Qualified Pension Plans: | | | | | | | | | | | | | | | | |
| Exelon Corporation Retirement Program | | | | X | | X | | X | | X | | X | | X | | X |
| Exelon Corporation Pension Plan for Bargaining Unit Employees | | | | X | | | | | | | | | | | | |
| Exelon Pension Plan | | | | X | | X | | X | | X | | X | | X | | X |
| Pepco Holdings LLC Retirement Plan | | | | X | | X | | X | | X | | X | | X | | X |
| Non-Qualified Pension Plans: | | | | | | | | | | | | | | | | |
| Exelon Corporation Supplemental Pension Benefit Plan and 2000 Excess Benefit Plan | | | | X | | X | | | | X | | | | | | |
| Exelon Corporation Supplemental Management Retirement Plan | | | | X | | X | | X | | X | | | | X | | |
| Constellation Energy Group, Inc. Senior Executive Supplemental Plan | | | | | | | | X | | X | | | | | | |
| Constellation Energy Group, Inc. Supplemental Pension Plan | | | | | | | | X | | X | | | | | | |
| Constellation Energy Group, Inc. Benefits Restoration Plan | | | | | | X | | X | | X | | | | | | |
| Baltimore Gas & Electric Company Executive Benefit Plan | | | | | | | | X | | | | | | | | |
| Baltimore Gas & Electric Company Manager Benefit Plan | | | | | | X | | X | | | | | | | | |
| Pepco Holdings LLC 2011 Supplemental Executive Retirement Plan | | | | | | | | | | X | | X | | X | | X |
| Conectiv Supplemental Executive Retirement Plan | | | | | | | | | | X | | | | X | | X |
| Pepco Holdings LLC Combined Executive Retirement Plan | | | | | | | | | | X | | X | | | | |
| Atlantic City Electric Director Retirement Plan | | | | | | | | | | X | | | | | | X |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 8 — Retirement Benefits
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Operating Company(a) |
| Name of Plan: | | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| OPEB Plans: | | | | | | | | | | | | | | | | |
| PECO Energy Company Retiree Medical Plan | | | | X | | X | | X | | X | | X | | X | | X |
| Exelon Corporation Health Care Program | | | | X | | X | | X | | X | | X | | X | | X |
| Exelon Corporation Employees’ Life Insurance Plan | | | | X | | X | | X | | | | | | | | |
| Exelon Corporation Health Reimbursement Arrangement Plan | | | | X | | X | | X | | | | | | | | |
| BGE Retiree Medical Plan | | | | X | | X | | X | | X | | X | | X | | |
| BGE Retiree Dental Plan | | | | | | | | X | | | | | | | | |
| Exelon Employee Life Insurance Plan and Family Life Insurance Plan | | | | X | | | | X | | X | | X | | X | | |
| Exelon Retiree Medical Plan of Constellation Energy Nuclear Group, LLC | | | | X | | | | X | | X | | | | | | |
| Exelon Retiree Dental Plan of Constellation Energy Nuclear Group, LLC | | | | X | | | | X | | X | | | | | | |
| Pepco Holdings LLC Welfare Plan for Retirees | | | | X | | X | | X | | X | | X | | X | | X |
__________
(a)Employees generally remain in their legacy benefit plans when transferring between operating companies.
As of February 1, 2022, in connection with the separation, Exelon's pension and OPEB plans were remeasured. The remeasurement and separation resulted in a decrease to the pension obligation, net of plan assets, of $921 million and a decrease to the OPEB obligation of $893 million. Additionally, accumulated other comprehensive loss, decreased by $1$1,994 million (after-tax) and regulatory assets and liabilities increased by $21$14 million and $1$5 million respectively. Key assumptions were held consistent with the year end December 31, 2021 assumptions with the exception of the discount rate.
The majority of the 20212022 pension benefit cost for the Exelon-sponsored plans is calculated using an expected long-term rate of return on plan assets of 7.00% and a discount rate of 2.58%3.24%. The majority of the 20212022 OPEB cost is calculated using an expected long-term rate of return on plan assets of 6.46%6.44% for funded plans and a discount rate of 2.51%3.20%.
During the first quarter of 2022, Exelon received an updated valuation of its pension and OPEB to reflect actual census data as of February 1, 2022. This valuation resulted in a decrease to the pension obligation of $24 million and an increase to the OPEB obligation of $5 million. Additionally, accumulated other comprehensive loss increased by $5 million (after-tax) and regulatory assets and liabilities decreased by $30 million and $3 million, respectively.
A portion of the net periodic benefit cost for all plans is capitalized inwithin the Consolidated Balance Sheets. The following table presents the components of Exelon's net periodic benefit costs, prior to capitalization, for the three and ninesix months ended SeptemberJune 30, 20212022 and 2020.
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | |
| Pension Benefits | | OPEB |
| Three Months Ended September 30, | | Three Months Ended September 30, |
| | 2021 | | 2020 | | 2021 | | 2020 |
| Components of net periodic benefit cost: | | | | | | | |
| Service cost | $ | 110 | | | $ | 97 | | | $ | 20 | | | $ | 22 | |
| Interest cost | 161 | | | 190 | | | 29 | | | 37 | |
| Expected return on assets | (335) | | | (317) | | | (40) | | | (41) | |
| Amortization of: | | | | | | | |
| Prior service cost (credit) | 1 | | | 1 | | | (8) | | | (30) | |
| Actuarial loss | 150 | | | 128 | | | 9 | | | 12 | |
| Settlement charges | 12 | | | 8 | | | — | | | — | |
| | | | | | | |
| Net periodic benefit cost | $ | 99 | | | $ | 107 | | | $ | 10 | | | $ | — | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | |
| Pension Benefits | | OPEB |
| Nine Months Ended September 30, | | Nine Months Ended September 30, |
| 2021 | | 2020 | | 2021 | | 2020 |
| Components of net periodic benefit cost: | | | | | | | |
| Service cost | $ | 330 | | | $ | 290 | | | $ | 60 | | | $ | 67 | |
| Interest cost | 481 | | | 569 | | | 86 | | | 114 | |
| Expected return on assets | (1,003) | | | (953) | | | (119) | | | (122) | |
| Amortization of: | | | | | | | |
| Prior service cost (credit) | 3 | | | 3 | | | (25) | | | (92) | |
| Actuarial loss | 449 | | | 384 | | | 27 | | | 36 | |
| Curtailment benefits | — | | | — | | | (1) | | | — | |
| Settlement charges | 16 | | | 14 | | | — | | | — | |
| | | | | | | |
| Net periodic benefit cost | $ | 276 | | | $ | 307 | | | $ | 28 | | | $ | 3 | |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 118 — Retirement Benefits
| | | | | | | | | | | | | | | | | | | | | | | | |
| Pension Benefits | | OPEB | |
| Three Months Ended June 30, | | Three Months Ended June 30, | |
| 2022 | | 2021 | | 2022 | | 2021 | |
| Components of net periodic benefit cost: | | | | | | | | |
| Service cost | $ | 58 | | | $ | 75 | | | $ | 10 | | | $ | 13 | | |
| Interest cost | 110 | | | 101 | | | 19 | | | 17 | | |
| Expected return on assets | (205) | | | (210) | | | (25) | | | (25) | | |
| Amortization of: | | | | | | | | |
| Prior service cost (credit) | 1 | | | — | | | (5) | | | (7) | | |
| Actuarial loss | 73 | | | 99 | | | 4 | | | 8 | | |
| | | | | | | | |
| | | | | | | | |
| Net periodic benefit cost | $ | 37 | | | $ | 65 | | | $ | 3 | | | $ | 6 | | |
| | | | | | | | |
| Pension Benefits | | OPEB | |
| Six Months Ended June 30, | | Six Months Ended June 30, | |
| 2022 | | 2021 | | 2022 | | 2021 | |
| Components of net periodic benefit cost: | | | | | | | | |
| Service cost | $ | 119 | | | $ | 148 | | | $ | 20 | | | $ | 26 | | |
| Interest cost | 220 | | | 202 | | | 38 | | | 35 | | |
| Expected return on assets | (414) | | | (421) | | | (50) | | | (50) | | |
| Amortization of: | | | | | | | | |
| Prior service cost (credit) | 2 | | | 1 | | | (10) | | | (13) | | |
| Actuarial loss | 149 | | | 199 | | | 8 | | | 14 | | |
| Curtailment benefits | — | | | — | | | — | | | (1) | | |
| | | | | | | | |
| Net periodic benefit cost | $ | 76 | | | $ | 129 | | | $ | 6 | | | $ | 11 | | |
The amounts below represent the Registrants' allocated pension and OPEB costs. For Exelon, the service cost component is included in Operating and maintenance expense and Property, plant, and equipment, net while the non-service cost components are included in Other, net and Regulatory assets. For Generation and the Utility Registrants, the service cost and non-service cost components are included in Operating and maintenance expense and Property, plant, and equipment, net in their consolidated financial statements.
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Three Months Ended September 30, | | Nine Months Ended September 30, |
| Pension and OPEB Costs | | 2021 | | 2020 | | 2021 | | 2020 |
| Exelon | | $ | 109 | | | $ | 107 | | | $ | 304 | | | $ | 310 | |
| Generation | | 36 | | | 30 | | | 92 | | | 89 | |
| ComEd | | 32 | | | 29 | | | 97 | | | 85 | |
| PECO | | 2 | | | 1 | | | 5 | | | 4 | |
| BGE | | 16 | | | 16 | | | 47 | | | 47 | |
| PHI | | 12 | | | 17 | | | 36 | | | 52 | |
| Pepco | | 2 | | | 4 | | | 5 | | | 11 | |
| DPL | | 1 | | | 2 | | | 2 | | | 6 | |
| ACE | | 3 | | | 3 | | | 8 | | | 10 | |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 8 — Retirement Benefits
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Three Months Ended June 30, | | Six Months Ended June 30, |
| Pension and OPEB Costs (Benefit) | | 2022 | | 2021 | | 2022 | | 2021 |
| Exelon | | $ | 40 | | | $ | 71 | | | $ | 82 | | | $ | 140 | |
| ComEd | | 14 | | | 32 | | | 30 | | | 64 | |
| PECO | | (2) | | | 2 | | | (4) | | | 4 | |
| BGE | | 11 | | | 16 | | | 22 | | | 31 | |
| PHI | | 13 | | | 12 | | | 26 | | | 24 | |
| Pepco | | 2 | | | 2 | | | 4 | | | 3 | |
| DPL | | 1 | | | 1 | | | 2 | | | 1 | |
| ACE | | 3 | | | 3 | | | 6 | | | 5 | |
Defined Contribution Savings PlansPlan
The Registrants participate in variousa 401(k) defined contribution savings plansplan that areis sponsored by Exelon. The plans areplan is qualified under applicable sections of the IRC and allow employees to contribute a portion of their pre-tax and/or after-tax income in accordance with specified guidelines. All Registrants match a percentage of the employee contributions up to certain limits. The following table presents the employer contributions and employer matching contributions to the savings plansplan for the three and ninesix months ended SeptemberJune 30, 20212022 and 2020,2021, respectively.
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| Savings Plans Matching Contributions | | 2021 | | 2020 | | 2021 | | 2020 |
| Exelon | | $ | 38 | | | $ | 37 | | | $ | 107 | | | $ | 104 | |
| Generation | | 14 | | | 14 | | | 40 | | | 41 | |
| ComEd | | 9 | | | 9 | | | 27 | | | 25 | |
| PECO | | 2 | | | 3 | | | 8 | | | 8 | |
| BGE | | 4 | | | 4 | | | 8 | | | 8 | |
| PHI | | 5 | | | 3 | | | 12 | | | 9 | |
| Pepco | | 1 | | | 1 | | | 3 | | | 3 | |
| DPL | | 1 | | | 1 | | | 3 | | | 2 | |
| ACE | | 1 | | | — | | | 2 | | | 1 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended June 30, | | Six Months Ended June 30, |
| Savings Plan Matching Contributions | | 2022 | | 2021 | | 2022 | | 2021 |
| Exelon | | $ | 23 | | | $ | 23 | | | $ | 43 | | | $ | 43 | |
| ComEd | | 10 | | | 10 | | | 18 | | | 18 | |
| PECO | | 3 | | | 3 | | | 6 | | | 6 | |
| BGE | | 3 | | | 2 | | | 5 | | | 4 | |
| PHI | | 4 | | | 4 | | | 7 | | | 7 | |
| Pepco | | 1 | | | 1 | | | 2 | | | 2 | |
| DPL | | 1 | | | 1 | | | 2 | | | 2 | |
| ACE | | 1 | | | 1 | | | 1 | | | 1 | |
12.9. Derivative Financial Instruments (All Registrants)
The Registrants use derivative instruments to manage commodity price risk, interest rate risk, and foreign exchange risk related to ongoing business operations.
Authoritative guidance requires that derivative instruments be recognized as either assets or liabilities at fair value, with changes in fair value of the derivative recognized in earnings immediately. Other accounting treatments are available through special election and designation, provided they meet specific, restrictive criteria both at the time of designation and on an ongoing basis. These alternative permissible accounting treatments include NPNS, cash flow hedges, and fair value hedges. AllAt ComEd, derivative economic hedges related to commodities referred to as economic hedges, are recorded at fair value through earnings at Generation and are offset by a corresponding regulatory asset or liability at ComEd.liability. For all NPNS derivative instruments, accounts receivable or accounts payable are recorded when derivatives settle and revenue or expense is recognized in earnings as the underlying physical commodity is sold or consumed.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)
Note 12 — Derivative Financial Instruments
Authoritative guidance about offsetting assets and liabilities requires the fair value of derivative instruments to be shown in the Combined Notes to Consolidated Financial Statements on a gross basis, even when the derivative instruments are subject to legally enforceable master netting agreements and qualify for net presentation in the Consolidated Balance Sheets. A master netting agreement is an agreement between two counterparties that may have derivative and non-derivative contracts with each other providing for the net settlement of all referenced contracts via one payment stream, which takes place as the contracts deliver, when collateral is requested or in the event of default. In the tables below, which present fair value balances, Generation’s energy-related economic hedges and proprietary trading derivatives are shown gross. The impact of the netting of fair value balances with the same counterparty that are subject to legally enforceable master netting agreements, as well as netting of cash collateral, including margin on exchange positions, is aggregated in the collateral and netting columns.
Generation’s and ComEd’s use of cash collateral is generally unrestricted unless Generation or ComEd areis downgraded below investment grade. Cash collateral held by PECO, BGE, Pepco, DPL, and ACE must be deposited in an unaffiliated major U.S. commercial bank or foreign bank with a U.S. branch office that meet certain qualifications.
Commodity Price Risk (All Registrants)
Each of theThe Registrants employ established policies and procedures to manage their risks associated with market fluctuations in commodity prices by entering into physical and financial derivative contracts, including swaps, futures, forwards, options, and short-term and long-term commitments to purchase and sell energy and commodity products. The Registrants believe these instruments, which are either determined to be non-derivative or classified as economic hedges, mitigate exposure to fluctuations in commodity prices.
Generation. To the extent the amount of energy Generation produces differs from the amount of energy it has contracted to sell, Exelon and Generation are exposed to market fluctuations in the prices of electricity, fossil fuels, and other commodities. Within Exelon, Generation has the most exposure to commodity price risk. As such, Generation uses a variety of derivative and non-derivative instruments to manage the commodity price risk of its electric generation facilities, including power and gas sales, fuel and power purchases, natural gas transportation and pipeline capacity agreements, and other energy-related products marketed and purchased. To manage these risks, Generation may enter into fixed-price derivative or non-derivative contracts to hedge the variability in future cash flows from expected sales of power and gas and purchases of power and fuel. The objectives for executing such hedges include fixing the price for a portion of anticipated future electricity sales at a level that provides an acceptable return. Generation is also exposed to differences between the locational settlement prices of certain economic hedges and the hedged generating units. This price difference is actively managed through other instruments which include derivative congestion products, whose changes in fair value are recognized in earnings each period, and auction revenue rights, which are accounted for on an accrual basis.
Additionally, Generation is exposed to certain market risks through its proprietary trading activities. The proprietary trading activities are a complement to Generation’s energy marketing portfolio but represent a small portion of Generation’s overall energy marketing activities and are subject to limits established by Exelon’s RMC.
Utility Registrants.hedges. The Utility Registrants procure electric and natural gas supply through a competitive procurement process approved by each of the respective state utility commissions. The Utility Registrants’ hedging programs are intended to reduce exposure to energy and natural
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 9 — Derivative Financial Instruments
gas price volatility and have no direct earnings impact as the costs are fully recovered from customers through regulatory-approved recovery
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)
Note 12 — Derivative Financial Instruments
mechanisms. The following table provides a summary of the Utility Registrants’ primary derivative hedging instruments, listed by commodity and accounting treatment.
| | | | | | | | | | | |
| Registrant | Commodity | Accounting Treatment | Hedging Instrument |
| ComEd | Electricity | NPNS | Fixed price contracts based on all requirements in the IPA procurement plans. |
| Electricity | Changes in fair value of economic hedge recorded to an offsetting regulatory asset or liability(a) | 20-year floating-to-fixed energy swap contracts beginning June 2012 based on the renewable energy resource procurement requirements in the Illinois Settlement Legislation of approximately 1.3 million MWhs per year. |
| PECO | Electricity | NPNS | Fixed price contracts for default supply requirements through full requirements contracts. |
| Gas | NPNS | Fixed price contracts to cover about 10% of planned natural gas purchases in support of projected firm sales. |
| BGE | Electricity | NPNS | Fixed price contracts for all SOS requirements through full requirements contracts. |
| Gas | NPNS | Fixed price contracts for between 10-20% of forecasted system supply requirements for flowing (i.e., non-storage) gas for the November through March period. |
| Pepco | Electricity | NPNS | Fixed price contracts for all SOS requirements through full requirements contracts. |
| DPL | Electricity | NPNS | Fixed price contracts for all SOS requirements through full requirements contracts. |
| Gas | NPNS | Fixed and Indexindex priced contracts through full requirements contracts. |
Changes in fair value of economic hedge recorded to an offsetting regulatory asset or liability(b) | Exchange traded future contracts for up to 50% of estimated monthly purchase requirements each month, including purchases for storage injections. |
| ACE | Electricity | NPNS | Fixed price contracts for all BGS requirements through full requirements contracts. |
__________
(a)See Note 3 — Regulatory Matters of the 20202021 Recast Form 10-K for additional information.
(b)The fair value of the DPL economic hedge is not material as of SeptemberJune 30, 20212022 and December 31, 2020 and is not presented in the fair value tables below.
The following tables provide a summary of the derivative fair value balances recorded by Exelon, Generation, and ComEd as of September 30, 2021 and December 31, 2020:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Exelon | | Generation | | ComEd | | | | |
| September 30, 2021 | | Total
Derivatives | | Economic
Hedges | | Proprietary
Trading | | Collateral(a)(b) | | Netting(a) | | Subtotal | | Economic
Hedges | | | | | | | | |
Mark-to-market derivative assets
(current assets) | | $ | 1,505 | | | $ | 19,631 | | | $ | 63 | | | $ | (790) | | | $ | (17,399) | | | $ | 1,505 | | | $ | — | | | | | | | | | |
Mark-to-market derivative assets
(noncurrent assets) | | 661 | | | 3,612 | | | 5 | | | (201) | | | (2,755) | | | 661 | | | — | | | | | | | | | |
| Total mark-to-market derivative assets | | 2,166 | | | 23,243 | | | 68 | | | (991) | | | (20,154) | | | 2,166 | | | — | | | | | | | | | |
Mark-to-market derivative liabilities
(current liabilities) | | (1,710) | | | (18,490) | | | (55) | | | (559) | | | 17,399 | | | (1,705) | | | (5) | | | | | | | | | |
Mark-to-market derivative liabilities
(noncurrent liabilities) | | (720) | | | (3,168) | | | (3) | | | (95) | | | 2,755 | | | (511) | | | (209) | | | | | | | | | |
| Total mark-to-market derivative liabilities | | (2,430) | | | (21,658) | | | (58) | | | (654) | | | 20,154 | | | (2,216) | | | (214) | | | | | | | | | |
| Total mark-to-market derivative net (liabilities) assets | | $ | (264) | | | $ | 1,585 | | | $ | 10 | | | $ | (1,645) | | | $ | — | | | $ | (50) | | | $ | (214) | | | | | | | | | |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollarsderivative economic hedges is presented in millions, except per share data, unless otherwise noted)
Note 12 — Derivative Financial Instruments
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Exelon | | Generation | | ComEd | | | | |
| December 31, 2020 | | Total
Derivatives | | Economic
Hedges | | Proprietary
Trading | | Collateral(a)(b) | | Netting(a) | | Subtotal | | Economic
Hedges | | | | | | | | |
Mark-to-market derivative assets
(current assets) | | $ | 639 | | | $ | 2,757 | | | $ | 40 | | | $ | 103 | | | $ | (2,261) | | | $ | 639 | | | $ | — | | | | | | | | | |
Mark-to-market derivative assets
(noncurrent assets) | | 554 | | | 1,501 | | | 4 | | | 64 | | | (1,015) | | | 554 | | | — | | | | | | | | | |
| Total mark-to-market derivative assets | | 1,193 | | | 4,258 | | | 44 | | | 167 | | | (3,276) | | | 1,193 | | | — | | | | | | | | | |
Mark-to-market derivative liabilities
(current liabilities) | | (293) | | | (2,629) | | | (23) | | | 131 | | | 2,261 | | | (260) | | | (33) | | | | | | | | | |
Mark-to-market derivative liabilities
(noncurrent liabilities) | | (472) | | | (1,335) | | | (2) | | | 118 | | | 1,015 | | | (204) | | | (268) | | | | | | | | | |
| Total mark-to-market derivative liabilities | | (765) | | | (3,964) | | | (25) | | | 249 | | | 3,276 | | | (464) | | | (301) | | | | | | | | | |
| Total mark-to-market derivative net assets (liabilities) | | $ | 428 | | | $ | 294 | | | $ | 19 | | | $ | 416 | | | $ | — | | | $ | 729 | | | $ | (301) | | | | | | | | | |
_________
(a)ExelonOther current assets and Generation net all available amounts allowed under thecurrent and noncurrent Mark-to-market derivative authoritative guidanceliabilities in the balance sheet. These amounts include unrealizedExelon's and ComEd's Consolidated Balance Sheets. The Mark-to-market derivative transactions with the same counterparty under legally enforceable master netting agreementsassets included in Other current assets in Exelon’s and cash collateral. In some cases ExelonComEd’s Consolidated Balance Sheets were $15 million and Generation may have other offsetting exposures, subject to a master netting or similar agreement, such as trade receivables and payables, transactions that do not qualify as derivatives, letters of credit, and other forms of non-cash collateral. As of September 30, 2021, $1 million of cash collateral posted with external counterparties and an additional $71 million of cash collateral posted with affiliates, including $50 million with ComEd, andnone as of December 31, 2020, $15 million of cash collateral held with external counterparties, was not offset against derivative positions because such collateral was not associated with any energy-related derivatives, was associated with accrual positions, or had no positions to offset as of the balance sheet date.
(b)Includes $2,084 million held and $209 million posted of variation margin with the exchanges as of SeptemberJune 30, 20212022 and December 31, 20202021, respectively.
Economic Hedges (Commodity Price Risk)
Generation. For the three and nine months ended September 30, 2021 and 2020, Exelon and Generation recognized the following net pre-tax commodity mark-to-market gains (losses) which are also located in the Net fair value changes related to derivatives line in the Consolidated Statements of Cash Flows.
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended
September 30, | | Nine Months Ended
September 30, |
| | 2021 | | 2020 | | 2021 | | 2020 |
| Income Statement Location | | (Loss) Gain | | (Loss) Gain |
| Operating revenues | | $ | (637) | | | $ | 39 | | | $ | (961) | | | $ | 238 | |
| Purchased power and fuel | | 1,392 | | | 209 | | | 2,209 | | | 224 | |
| Total Exelon and Generation | | $ | 755 | | | $ | 248 | | | $ | 1,248 | | | $ | 462 | |
In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on Generation’s owned and contracted generation positions that have not been hedged. Generation hedges commodity price risk on a ratable basis over three-year periods. As of September 30, 2021, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York, and ERCOT reportable segments is 96%-99% for the remainder of 2021.
Proprietary Trading (Commodity Price Risk)
Generation also executes commodity derivatives for proprietary trading purposes. Proprietary trading includes all contracts executed with the intent of benefiting from shifts or changes in market prices as opposed to those executed with the intent of hedging or managing risk. Gains and losses associated with proprietary trading are reported as Operating revenues in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income and are included in the Net fair value changes related to derivatives line in the Consolidated Statements of Cash Flows. For the three and nine months ended September 30, 2021 and 2020,
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)
Note 12 — Derivative Financial Instruments
net pre-tax commodity mark-to-market gains and losses for Exelon and Generation were not material. The Utility Registrants do not execute derivatives for proprietary trading purposes.
Interest Rate and Foreign Exchange Risk (Exelon and Generation)
Generation utilizes interest rate swaps to manage its interest rate exposure and foreign currency derivatives to manage foreign exchange rate exposure associated with international commodity purchases in currencies other than U.S. dollars, both of which are treated as economic hedges. The notional amounts were $567 million and $665 million for Exelon and Generation as of September 30, 2021 and December 31, 2020, respectively.
The mark-to-market derivative assets and liabilities as of September 30, 2021 and December 31, 2020 and the mark-to-market gains and losses for the three and nine months ended September 30, 2021 and 2020 were not material for Exelon and Generation.
Credit Risk (All Registrants)
The Registrants would be exposed to credit-related losses in the event of non-performance by counterparties on executed derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts at the reporting date.
Generation. For commodity derivatives, Generation enters into enabling agreements that allow for payment netting with its counterparties, which reduces Generation’s exposure to counterparty risk by providing for the offset of amounts payable to the counterparty against amounts receivable from the counterparty. Typically, each enabling agreement is for a specific commodity and so, with respect to each individual counterparty, netting is limited to transactions involving that specific commodity product, except where master netting agreements exist with a counterparty that allow for cross product netting. In addition to payment netting language in the enabling agreement, Generation’s credit department establishes credit limits, margining thresholds, and collateral requirements for each counterparty, which are defined in the derivative contracts. Counterparty credit limits are based on an internal credit review process that considers a variety of factors, including the results of a scoring model, leverage, liquidity, profitability, credit ratings by credit rating agencies, and risk management capabilities. To the extent that a counterparty’s margining thresholds are exceeded, the counterparty is required to post collateral with Generation as specified in each enabling agreement. Generation’s credit department monitors current and forward credit exposure to counterparties and their affiliates, both on an individual and an aggregate basis.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)
Note 12 — Derivative Financial Instruments
The following tables provide information on Generation’s credit exposure for all derivative instruments, NPNS, and payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of September 30, 2021. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties. The amounts in the tables below exclude credit risk exposure from individual retail counterparties, nuclear fuel procurement contracts, and exposure through RTOs, ISOs, NYMEX, ICE, NASDAQ, NGX, and Nodal commodity exchanges.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Rating as of September 30, 2021 | | Total Exposure Before Credit Collateral | | Credit Collateral(a) | | Net Exposure | | Number of Counterparties Greater than 10% of Net Exposure | | Net Exposure of Counterparties Greater than 10% of Net Exposure |
| Investment grade | | $ | 701 | | | $ | 254 | | | $ | 447 | | | — | | | $ | — | |
| Non-investment grade | | 23 | | | 2 | | | 21 | | | — | | | — | |
| No external ratings | | | | | | | | | | |
| Internally rated — investment grade | | 110 | | | 1 | | | 109 | | | — | | | — | |
| Internally rated — non-investment grade | | 309 | | | 48 | | | 261 | | | — | | | — | |
| Total | | $ | 1,143 | | | $ | 305 | | | $ | 838 | | | — | | | $ | — | |
| | | | | | | | |
Net Credit Exposure by Type of Counterparty | | As of September 30, 2021 |
Financial institutions | | $ | 53 | |
Investor-owned utilities, marketers, power producers | | 652 | |
Energy cooperatives and municipalities | | 62 | |
Other | | 71 | |
Total | | $ | 838 | |
_________
(a)As of September 30, 2021, credit collateral held from counterparties where Generation had credit exposure included $188 million of cash and $117 million of letters of credit. The credit collateral does not include non-liquid collateral.
Utility Registrants. The Utility Registrants have contracts to procure electric and natural gas supply that provide suppliers with a certain amount of unsecured credit. If the exposure on the supply contract exceeds the amount of unsecured credit, the suppliers may be required to post collateral. The net credit exposure is mitigated primarily by the ability to recover procurement costs through customer rates. As of SeptemberJune 30, 2021,2022, the amount of cash collateral held with external counterparties by Exelon, ComEd, BGE, PHI, Pepco, DPL, and DPLACE was $56$781 million, $21$133 million, $194 million, $452 million, $87 million, $224 million, and $25$141 million, respectively, which is recorded in Other Current Liabilitiescurrent liabilities in ComEd’s, BGE’s,Exelon's, ComEd's, BGE's, PHI's, Pepco's, DPL's, and DPL’sACE's Consolidated Balance Sheets. The amounts for PECO, Pepco, and ACE asamount of September 30, 2021 and for the Utility Registrants as of December 31, 2020 are not material. The amount for ComEd as of September 30, 2021 does not include cash collateral heldreceived from Generation, which is disclosed in the notes to the derivative fair value balances tables above.
Credit-Risk-Related Contingent Features (All Registrants)
Generation. As part of the normal course of business, Generation routinely enters into physically or financially settled contracts for the purchase and sale of electric capacity, electricity, fuels, emissions allowances, and other energy-related products. Certain of Generation’s derivative instruments contain provisions that require Generation to post collateral. Generation also enters into commodity transactions on exchanges where the exchanges act as the counterparty to each trade. Transactions on the exchanges must adhere to comprehensive collateral and margining requirements. This collateral may be posted in the form of cash or credit support with thresholds contingent upon Generation’s credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. These credit-risk-related contingent features stipulate that if Generation were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide additional collateral. This incremental collateral requirement allows for the offsetting of derivative instruments that are assets with the same counterparty, whereexternal counterparties
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 129 — Derivative Financial Instruments
the contractual rightincreased as of offset exists under applicable master netting agreements. In the absenceJune 30, 2022 due to rising energy prices. The amount for PECO was not material as of expressly agreed-to provisions that specify the collateral that must be provided, collateral requested will be a function of the facts and circumstances of the situation at the time of the demand. In this case, Generation believes an amount of several months of future payments (i.e., capacity payments) rather than a calculation of fair value is the best estimate for the contingent collateral obligation, which has been factored into the disclosure below.
The aggregate fair value of all derivative instruments with credit-risk related contingent features in a liability position that are not fully collateralized (excluding transactions on the exchanges that are fully collateralized) is detailed in the table below:
| | | | | | | | | | | | | | |
| Credit-Risk Related Contingent Features | | September 30, 2021 | | December 31, 2020 |
Gross fair value of derivative contracts containing this feature(a) | | $ | (5,289) | | | $ | (834) | |
Offsetting fair value of in-the-money contracts under master netting arrangements(b) | | 2,735 | | | 537 | |
Net fair value of derivative contracts containing this feature(c) | | $ | (2,554) | | | $ | (297) | |
_________
(a)Amount represents the gross fair value of out-of-the-money derivative contracts containing credit-risk related contingent features ignoring the effects of master netting agreements.
(b)Amount represents the offsetting fair value of in-the-money derivative contracts under legally enforceable master netting agreements with the same counterparty, which reduces the amount of any liability for which Generation could potentially be required to post collateral.
(c)Amount represents the net fair value of out-of-the-money derivative contracts containing credit-risk related contingent features after considering the mitigating effects of offsetting positions under master netting arrangements and reflects the actual net liability upon which any potential contingent collateral obligations would be based.
June 30, 2022. As of September 30, 2021 and December 31, 2020,2021, the amounts for ComEd and DPL were $41 million and $43 million, respectively. The amounts for Exelon, PECO, BGE, PHI, Pepco, and Generation posted or held the following amountsACE were not material as of cash collateral and letters of credit on derivative contracts with external counterparties, after giving consideration to offsetting derivative and non-derivative positions under master netting agreements.
| | | | | | | | | | | | | | |
| | September 30, 2021 | | December 31, 2020 |
| Cash collateral posted | | $ | 299 | | | $ | 511 | |
| Letters of credit posted | | 477 | | | 226 | |
| Cash collateral held | | 1,872 | | | 110 | |
| Letters of credit held | | 130 | | | 40 | |
| Additional collateral required in the event of a credit downgrade below investment grade | | 3,001 | | | 1,432 | |
Generation entered into supply forward contracts with certain utilities, including PECO and BGE, with one-sided collateral postings only from Generation. If market prices fall below the benchmark price levels in these contracts, the utilities are not required to post collateral. However, when market prices rise above the benchmark price levels, counterparty suppliers, including Generation, are required to post collateral once certain unsecured credit limits are exceeded.
Utility RegistrantsDecember 31, 2021.
The Utility Registrants’ electric supply procurement contracts do not contain provisions that would require them to post collateral.
PECO’s, BGE’s, and DPL’s natural gas procurement contracts contain provisions that could require PECO, BGE, and DPL to post collateral in the form of cash or credit support, which vary by contract and counterparty, with thresholds contingent upon PECO’s, BGE's, and DPL’s credit rating. As of SeptemberJune 30, 2021,2022, PECO, BGE, and DPL were not required to post collateral for any of these agreements. If PECO, BGE, or DPL lost their investment grade credit rating as of SeptemberJune 30, 2021,2022, they could have been required to post incremental collateral to their counterparties of $23$37 million, $46$75 million, and $11$15 million, respectively.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)
Note 13 — Debt and Credit Agreements
13.10. Debt and Credit Agreements (All Registrants)
Short-Term Borrowings
Exelon Corporate, ComEd, and BGE meet their short-term liquidity requirements primarily through the issuance of commercial paper. Generation and PECO meetmeets their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the Exelon intercompany money pool. Pepco, DPL, and ACE meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the PHI intercompany money pool. PHI Corporate meets its short-term liquidity requirements primarily through the issuance of short-term notes and borrowings from the Exelon intercompany money pool. The Registrants may use their respective credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit.
Commercial Paper
The following table reflects the Registrants' commercial paper programs as of SeptemberJune 30, 20212022 and December 31, 2020. PECO and BGE2021. ComEd had no commercial paper borrowings as of SeptemberJune 30, 20212022 and December 31, 2020.2021.
| | | Outstanding Commercial
Paper as of | | Average Interest Rate on
Commercial Paper Borrowings as of | | Outstanding Commercial
Paper as of | | Average Interest Rate on
Commercial Paper Borrowings as of |
| Commercial Paper Issuer | Commercial Paper Issuer | September 30, 2021 | | December 31, 2020 | | September 30, 2021 | | December 31, 2020 | Commercial Paper Issuer | June 30, 2022 | | December 31, 2021 | | June 30, 2022 | | December 31, 2021 |
Exelon(a) | Exelon(a) | $ | 287 | | | $ | 1,031 | | | 0.19 | % | | 0.25 | % | Exelon(a) | $ | 353 | | | $ | 599 | | | 1.86 | % | | 0.35 | % |
| Generation | — | | | 340 | | | — | % | | 0.27 | % | |
| ComEd | — | | | 323 | | | — | % | | 0.23 | % | |
| | PECO | | PECO | 210 | | | — | | | 1.86 | % | | — | % |
| BGE | | BGE | — | | | 130 | | | — | % | | 0.37 | % |
PHI(b) | PHI(b) | 287 | | | 368 | | | 0.19 | % | | 0.24 | % | PHI(b) | 43 | | | 469 | | | 1.85 | % | | 0.35 | % |
| | Pepco | Pepco | 40 | | | 35 | | | 0.15 | % | | 0.22 | % | Pepco | 43 | | | 175 | | | 1.85 | % | | 0.33 | % |
| DPL | DPL | 22 | | | 146 | | | 0.15 | % | | 0.24 | % | DPL | — | | | 149 | | | — | % | | 0.36 | % |
| ACE | ACE | 225 | | | 187 | | | 0.20 | % | | 0.25 | % | ACE | — | | | 145 | | | — | % | | 0.35 | % |
__________
(a)Exelon Corporate had $100 million of outstanding commercial paper borrowings at June 30, 2022 and no outstanding commercial paper borrowings as of September 30, 2021 and December 31, 2020.2021.
(b)Represents the consolidated amounts of Pepco, DPL, and ACE.
See Note 17
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 10 — Debt and Credit Agreements
Revolving Credit Agreements
On February 1, 2022, Exelon Corporate and the Utility Registrants' each entered into a new 5-year revolving credit facility that replaced its existing syndicated revolving credit facility. The following table reflects the credit agreements:
| | | | | | | | | | | | | | |
| Borrower | | Aggregate Bank Commitment | | Interest Rate |
| Exelon Corporate | | 900 | | | SOFR plus 1.275 | % |
| ComEd | | 1,000 | | | SOFR plus 1.000 | % |
| PECO | | 600 | | | SOFR plus 0.900 | % |
| BGE | | 600 | | | SOFR plus 0.900 | % |
| Pepco | | 300 | | | SOFR plus 1.075 | % |
| DPL | | 300 | | | SOFR plus 1.000 | % |
| ACE | | 300 | | | SOFR plus 1.075 | % |
See Note 15 — Debt and Credit Agreements of the Exelon 20202021 Recast Form 10-K for additional information on the Registrants' credit facilities.
Short-Term Loan Agreements
On March 23, 2017, Exelon Corporate entered into a term loan agreement for $500 million. The loan agreement was renewed on March 17, 202114, 2022 and will expire on March 16, 2022.2023. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.65% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Exelon's Consolidated Balance Sheets within Short-term borrowings.
On March 24, 2021, Exelon Corporate entered into a 9-month term loan agreement for $200 million. The loan agreement has an expiration of December 24, 2021. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBORSOFR plus 0.65% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Exelon's Consolidated Balance Sheets within Short-term borrowings.
On March 31, 2021, Exelon Corporate entered into a 9-month and 364-day term loan agreement for $150 million each with a variable interest ratesrate of LIBOR plus 0.65% and an expiration datesdate of December 31, 2021 and March 30, 2022. Exelon Corporate repaid the term loan on March 30, 2022.
In connection with the separation, on January 24, 2022, respectively.Exelon Corporate entered into a 364-day term loan agreement for $1.15 billion. The loan agreements are reflected in Exelon's Consolidated Balance Sheets within Short-term borrowings.agreement will expire on January 23, 2023. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to SOFR plus 0.75% with a 22.5 basis point increase which commenced on July 24, 2022. All indebtedness pursuant to the loan agreement is unsecured.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 1310 — Debt and Credit Agreements
On March 19, 2020, Generation entered into a term loan agreement for $200 million. The loan agreement was renewed on March 17, 2021 and will expire on March 16, 2022. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.875% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Exelon's and Generation's Consolidated Balance Sheets within Short-term borrowings.
On March 31, 2020, Generation entered into a term loan agreement for $300 million. The loan agreement was renewed on March 30, 2021 and will expire on March 29, 2022. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.70% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Exelon's and Generation's Consolidated Balance Sheets within Short-term borrowings.
On August 6, 2021, Generation entered into a 364-day term loan agreement for $880 million with a variable interest rate of LIBOR plus 0.875% until March 31, 2022 and a rate of LIBOR plus 1% thereafter and all indebtedness thereunder is unsecured. The loan agreement has an expiration date of August 5, 2022 and is reflected in Short-term borrowings in Exelon's and Generation's Consolidated Balance Sheets.
On January 25, 2021, ComEd entered into two 90-day term loan agreements for $125 million each with variable interest rates of LIBOR plus 0.50% and LIBOR plus 0.75%, respectively. ComEd repaid the term loans on March 9, 2021.
Bilateral Credit Agreements
On January 11, 2013, Generation entered into a bilateral credit agreement for $100 million. The agreement was renewed on March 1, 2021 with a maturity date of March 1, 2023.
On February 21, 2019, Generation entered into a bilateral credit agreement for $100 million. The agreement was renewed on March 31, 2021 with a maturity date of March 31, 2022.
On January 5, 2016, Generation entered into a bilateral credit agreement for $150 million. The agreement was renewed on April 2, 2021 with a maturity date of April 5, 2023.
On October 26, 2012, Generation entered into a bilateral credit agreement for $200 million. The agreement had a maturity date of October 22, 2021, however, was terminated on August 27, 2021.
See Note 17 — Debt and Credit Agreements of the Exelon 2020 Form 10-K for additional information on Generation's bilateral credit agreements.
Credit Agreements
On July 15, 2021, each of the Registrants' respective syndicated revolving credit facilities had their maturity dates extended to May 26, 2024.
Long-Term Debt
Issuance of Long-Term Debt
During the ninesix months ended SeptemberJune 30, 2021,2022, the following long-term debt was issued:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Company | | Type | | Interest Rate | | Maturity | | Amount | | Use of Proceeds | |
| Exelon | | SMBC Term Loan Agreement | | SOFR plus 0.65% | | July 21, 2023 | | $300 | | Fund a cash payment to Constellation and for general corporate purposes. | |
| Exelon | | U.S. Bank Term Loan Agreement | | SOFR plus 0.65% | | July 21, 2023 | | 300 | | Fund a cash payment to Constellation and for general corporate purposes. | |
| Exelon | | PNC Term Loan Agreement | | SOFR plus 0.65% | | July 24, 2023 | | 250 | | Fund a cash payment to Constellation and for general corporate purposes. | |
| Exelon | | Notes(b) | | 2.75% | | March 15, 2027 | | 650 | | Repay existing indebtedness and for general corporate purposes. | |
| Exelon | | Notes(b) | | 3.35% | | March 15, 2032 | | 650 | | Repay existing indebtedness and for general corporate purposes. | |
| Exelon | | Notes(b) | | 4.10% | | March 15, 2052 | | 700 | | Repay existing indebtedness and for general corporate purposes. | |
| ComEd | | First Mortgage Bonds, Series 132 | | 3.15% | | March 15, 2032 | | 300 | | Repay outstanding commercial paper obligations and to fund other general corporate purposes. | |
| ComEd | | First Mortgage Bonds, Series 133 | | 3.85% | | March 15, 2052 | | 450 | | Repay outstanding commercial paper obligations and to fund other general corporate purposes. | |
| PECO | | First and Refunding Mortgage Bonds | | 4.60% | | May 15, 2052 | | 350 | | Refinance existing indebtedness and for general corporate purposes. | |
| BGE | | Notes | | 4.55% | | June 1, 2052 | | 500 | | Repay outstanding commercial paper obligations, repay existing indebtedness, and for general corporate purposes. | |
Pepco(a) | | First Mortgage Bonds | | 3.97% | | March 24, 2052 | | 400 | | Repay existing indebtedness and for general corporate purposes. | |
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| | | | | | | | | | | |
| DPL | | First Mortgage Bonds | | 3.06% | | February 15, 2052 | | 125 | | Repay existing indebtedness and for general corporate purposes. | |
| ACE | | First Mortgage Bonds | | 2.27% | | February 15, 2032 | | 25 | | Repay existing indebtedness and for general corporate purposes. | |
| ACE | | First Mortgage Bonds | | 3.06% | | February 15, 2052 | | 150 | | Repay existing indebtedness and for general corporate purposes. | |
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__________
(a)On March 24, 2022, Pepco entered into a purchase agreement of First Mortgage Bonds of $225 million at 3.35% due on September 15, 2032. The closing date of the issuance is expected to occur in September 2022.
(b)In connection with the issuance and sale of the Notes, Exelon entered into a Registration Rights Agreement with the representatives of the initial purchasers of the Notes and other parties. Pursuant to the Registration Rights Agreement, Exelon will be obligated to file a registration statement with respect to an offer to exchange the Notes for substantially similar notes of Exelon that are registered under the Securities Act or, in certain circumstances, register the resale of the Notes. The registered exchange notes, if and when issued, will have terms identical in all material respects to the Notes, except that their issuance will have been registered under the Securities Act.
Long-Term Debt to Affiliates
As of December 31, 2021, Exelon Corporate had $319 million recorded to intercompany notes receivable from Generation. See Note 15 — Debt and Credit Agreements of the 2021 Recast Form 10-K for additional information. In connection with the separation, on January 31, 2022, Exelon Corporate received cash from Generation of $258 million to settle the intercompany loan.
Debt Covenants
As of June 30, 2022, the Registrants are in compliance with debt covenants.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 1311 — DebtFair Value of Financial Assets and Credit AgreementsLiabilities
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| Company | | Type | | Interest Rate | | | Maturity | | Amount | | Use of Proceeds | |
| Exelon | | Long-Term Software License Agreements | | 3.62 | % | | | December 1, 2025 | | $ | 4 | | | Procurement of software licenses. | |
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| Generation | | West Medway II
Nonrecourse Debt | | LIBOR + 3% | (a) | | March 31, 2026 | | 150 | | | Funding for general corporate purposes. | |
| Generation | | Energy Efficiency Project Financing(b) | | 2.53 | % | | | November 30, 2021 | | 1 | | | Funding to install energy conservation measures for the Fort AP Hill project. | |
| Generation | | Energy Efficiency Project Financing(b) | | 4.24 | % | | | November 30, 2021 | | 1 | | | Funding to install energy conservation measures for the Marine Corps. Logistics Project. | |
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| ComEd | | First Mortgage Bonds, Series 130 | | 3.13 | % | | | March 15, 2051 | | 700 | | | Repay a portion of outstanding commercial paper obligations and two outstanding term loans, and to fund other general corporate purposes. | |
| ComEd | | First Mortgage Bonds, Series 131 | | 2.75 | % | | | September 1, 2051 | | 450 | | | Refinance existing indebtedness and for general corporate purposes. | |
| PECO | | First and Refunding Mortgage Bonds | | 3.05 | % | | | March 15, 2051 | | 375 | | | Funding for general corporate purposes. | |
| PECO | | First and Refunding Mortgage Bonds | | 2.85 | % | | | September 15, 2051 | | 375 | | | Refinance existing indebtedness and for general corporate purposes. | |
| BGE | | Senior Notes | | 2.25 | % | | | June 15, 2031 | | 600 | | | Repay a portion of outstanding commercial paper obligations, repay existing indebtedness, and to fund other general corporate purposes. | |
| Pepco | | First Mortgage Bonds | | 2.32 | % | | | March 30, 2031 | | 150 | | | Repay existing indebtedness and for general corporate purposes. | |
| Pepco | | First Mortgage Bonds | | 3.29 | % | | | September 28, 2051 | | 125 | | | Repay existing indebtedness and for general corporate purposes. | |
| DPL | | First Mortgage Bonds | | 3.24 | % | | | March 30, 2051 | | 125 | | | Repay existing indebtedness and for general corporate purposes. | |
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| ACE | | First Mortgage Bonds | | 2.30 | % | | | March 15, 2031 | | 350 | | | Refinance existing indebtedness, repay outstanding commercial paper obligations, and for general corporate purposes. | |
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__________
(a)The nonrecourse debt has an average blended interest rate.
(b)For Energy Efficiency Project Financing, the maturity dates represent the expected date of project completion, upon which the respective customer assumes the outstanding debt.
Debt Covenants
As of September 30, 2021, the Registrants are in compliance with debt covenants.
Nonrecourse Debt
Exelon and Generation have issued nonrecourse debt financing. Borrowings under these agreements are secured by the assets and equity of each respective project. The lenders do not have recourse against Exelon or Generation in the event of a default.
West Medway II, LLC. On May 13, 2021, West Medway II, LLC (West Medway II), an indirect subsidiary of Generation, entered into a financing agreement for a $150 million nonrecourse senior secured term loan credit facility with a maturity date of March 31, 2026. The term loan bears interest at an average blended interest rate of
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)
Note 13 — Debt and Credit Agreements
LIBOR plus 3%, paid quarterly. In addition to the financing, West Medway II, entered into interest rate swaps with an initial notional amount of $113 million at an interest rate of 0.61%, paid quarterly, to manage a portion of the interest rate exposure in connection with the financing. The net proceeds were distributed to Generation for general corporate purposes. Generation’s interests in West Medway II, were pledged as collateral for this financing. As of September 30, 2021, approximately $145 million was outstanding.
See Note 17 — Debt and Credit Agreements of the Exelon 2020 Form 10-K for additional information on nonrecourse debt and Note 12 — Derivative Financial Instruments for additional information on interest rate swaps.
14.11. Fair Value of Financial Assets and Liabilities (All Registrants)
Exelon measures and classifies fair value measurements in accordance with the hierarchy as defined by GAAP. The hierarchy prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:
•Level 1 - quoted prices (unadjusted) in active markets for identical assets or liabilities that the Registrants have the ability to liquidate as of the reporting date.
•Level 2 - inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data.
•Level 3 - unobservable inputs, such as internally developed pricing models or third-party valuations for the asset or liability due to little or no market activity for the asset or liability.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)
Note 14 — Fair Value of Financial Assets and Liabilities
Fair Value of Financial Liabilities Recorded at Amortized Cost
The following tables present the carrying amounts and fair values of the Registrants’ short-term liabilities, long-term debt, SNF obligation, and trust preferred securities (long-term debt to financing trusts or junior subordinated debentures) as of SeptemberJune 30, 20212022 and December 31, 2020.2021. The Registrants have no financial liabilities classified as Level 1.
The carrying amounts of the Registrants’ short-term liabilities as presented in their Consolidated Balance Sheets are representative of their fair value (Level 2) because of the short-term nature of these instruments.
| | | September 30, 2021 | | December 31, 2020 | | June 30, 2022 | | December 31, 2021 |
| | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value |
| | Level 2 | | Level 3 | | Total | | Level 2 | | Level 3 | | Total | | Level 2 | | Level 3 | | Total | | Level 2 | | Level 3 | | Total |
Long-Term Debt, including amounts due within one year(a) | Long-Term Debt, including amounts due within one year(a) | Long-Term Debt, including amounts due within one year(a) |
| Exelon | Exelon | | $ | 38,644 | | | $ | 40,570 | | | $ | 3,289 | | | $ | 43,859 | | | $ | 36,912 | | | $ | 40,688 | | | $ | 3,064 | | | $ | 43,752 | | Exelon | | $ | 36,294 | | | $ | 30,960 | | | $ | 2,315 | | | $ | 33,275 | | | $ | 32,902 | | | $ | 34,897 | | | $ | 2,217 | | | $ | 37,114 | |
| Generation | | 6,130 | | | 5,835 | | | 1,111 | | | 6,946 | | | 6,087 | | | 5,648 | | | 1,208 | | | 6,856 | | |
| ComEd | ComEd | | 9,772 | | | 11,344 | | | — | | | 11,344 | | | 8,983 | | | 11,117 | | | — | | | 11,117 | | ComEd | | 10,516 | | | 9,609 | | | — | | | 9,609 | | | 9,773 | | | 11,305 | | | — | | | 11,305 | |
| PECO | PECO | | 4,196 | | | 4,738 | | | 50 | | | 4,788 | | | 3,753 | | | 4,553 | | | 50 | | | 4,603 | | PECO | | 4,192 | | | 3,772 | | | 50 | | | 3,822 | | | 4,197 | | | 4,740 | | | 50 | | | 4,790 | |
| BGE | BGE | | 3,960 | | | 4,416 | | | — | | | 4,416 | | | 3,664 | | | 4,366 | | | — | | | 4,366 | | BGE | | 4,456 | | | 4,096 | | | — | | | 4,096 | | | 3,961 | | | 4,406 | | | — | | | 4,406 | |
| PHI | PHI | | 7,482 | | | 6,030 | | | 2,128 | | | 8,158 | | | 7,006 | | | 6,099 | | | 1,806 | | | 7,905 | | PHI | | 8,027 | | | 4,853 | | | 2,265 | | | 7,118 | | | 7,547 | | | 5,970 | | | 2,167 | | | 8,137 | |
| Pepco | Pepco | | 3,441 | | | 3,226 | | | 990 | | | 4,216 | | | 3,165 | | | 3,336 | | | 748 | | | 4,084 | | Pepco | | 3,642 | | | 2,465 | | | 1,104 | | | 3,569 | | | 3,445 | | | 3,201 | | | 975 | | | 4,176 | |
| DPL | DPL | | 1,808 | | | 1,433 | | | 559 | | | 1,992 | | | 1,677 | | | 1,484 | | | 455 | | | 1,939 | | DPL | | 1,938 | | | 1,210 | | | 503 | | | 1,713 | | | 1,810 | | | 1,426 | | | 552 | | | 1,978 | |
| ACE | ACE | | 1,510 | | | 1,107 | | | 579 | | | 1,686 | | | 1,413 | | | 1,018 | | | 602 | | | 1,620 | | ACE | | 1,757 | | | 954 | | | 658 | | | 1,612 | | | 1,582 | | | 1,091 | | | 641 | | | 1,732 | |
Long-Term Debt to Financing Trusts(a) | |
| Long-Term Debt to Financing Trusts | | Long-Term Debt to Financing Trusts |
| Exelon | Exelon | | $ | 390 | | | $ | — | | | $ | 479 | | | $ | 479 | | | $ | 390 | | | $ | — | | | $ | 467 | | | $ | 467 | | Exelon | | $ | 390 | | | $ | — | | | $ | 398 | | | $ | 398 | | | $ | 390 | | | $ | — | | | $ | 470 | | | $ | 470 | |
| ComEd | ComEd | | 205 | | | — | | | 255 | | | 255 | | | 205 | | | — | | | 246 | | | 246 | | ComEd | | 205 | | | — | | | 209 | | | 209 | | | 205 | | | — | | | 248 | | | 248 | |
| PECO | PECO | | 184 | | | — | | | 224 | | | 224 | | | 184 | | | — | | | 221 | | | 221 | | PECO | | 184 | | | — | | | 189 | | | 189 | | | 184 | | | — | | | 222 | | | 222 | |
| SNF Obligation | |
| Exelon | | $ | 1,209 | | | $ | 1,021 | | | $ | — | | | $ | 1,021 | | | $ | 1,208 | | | $ | 909 | | | $ | — | | | $ | 909 | | |
| Generation | | 1,209 | | | 1,021 | | | — | | | 1,021 | | | 1,208 | | | 909 | | | — | | | 909 | | |
__________
(a)Includes unamortized debt issuance costs, unamortized debt discount and premium, net, purchase accounting fair value adjustments, and finance lease liabilities which are not fair valued. Refer to Note 15 - Debt and Credit Agreements of the 2021 Recast Form 10-K for unamortized debt issuance costs, unamortized debt discount and premium, net, and purchase accounting fair value adjustments and Note 10 - Leases of the 2021 Recast Form 10-K for finance lease liabilities.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 1411 — Fair Value of Financial Assets and Liabilities
Recurring Fair Value Measurements
The following tables present assets and liabilities measured and recorded at fair value in the Registrants' Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of SeptemberJune 30, 20212022 and December 31, 2020:2021:
Exelon
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| As of June 30, 2022 | | As of December 31, 2021 |
| Level 1 | | Level 2 | | Level 3 | | | | Total | | Level 1 | | Level 2 | | Level 3 | | | | Total |
| Assets | | | | | | | | | | | | | | | | | | | |
Cash equivalents(a) | $ | 1,319 | | | $ | — | | | $ | — | | | | | $ | 1,319 | | | $ | 524 | | | $ | — | | | $ | — | | | | | $ | 524 | |
| Rabbi trust investments | | | | | | | | | | | | | | | | | | | |
| Cash equivalents | 63 | | | — | | | — | | | | | 63 | | | 60 | | | — | | | — | | | | | 60 | |
| Mutual funds | 52 | | | — | | | — | | | | | 52 | | | 60 | | | — | | | — | | | | | 60 | |
| Fixed income | — | | | 8 | | | — | | | | | 8 | | | — | | | 10 | | | — | | | | | 10 | |
| Life insurance contracts | — | | | 59 | | | 38 | | | | | 97 | | | — | | | 61 | | | 37 | | | | | 98 | |
| Rabbi trust investments subtotal | 115 | | | 67 | | | 38 | | | | | 220 | | | 120 | | | 71 | | | 37 | | | | | 228 | |
| Mark-to-market derivative assets | — | | | — | | | 15 | | | | | 15 | | | — | | | — | | | — | | | | | — | |
| Total assets | 1,434 | | | 67 | | | 53 | | | | | 1,554 | | | 644 | | | 71 | | | 37 | | | | | 752 | |
| Liabilities | | | | | | | | | | | | | | | | | | | |
| Mark-to-market derivative liabilities | — | | | — | | | (103) | | | | | (103) | | | — | | | — | | | (219) | | | | | (219) | |
| Deferred compensation obligation | — | | | (73) | | | — | | | | | (73) | | | — | | | (131) | | | — | | | | | (131) | |
| Total liabilities | — | | | (73) | | | (103) | | | | | (176) | | | — | | | (131) | | | (219) | | | | | (350) | |
| Total net assets (liabilities) | $ | 1,434 | | | $ | (6) | | | $ | (50) | | | | | $ | 1,378 | | | $ | 644 | | | $ | (60) | | | $ | (182) | | | | | $ | 402 | |
__________
(a)Exelon excludes cash of $177 million and Generation$464 million as of June 30, 2022 and December 31, 2021, respectively, and restricted cash of $340 million and $49 million as of June 30, 2022 and December 31, 2021, respectively, and includes long-term restricted cash of $59 million and $44 million as of June 30, 2022 and December 31, 2021, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets.
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| Exelon | | Generation |
| As of September 30, 2021 | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total | | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total |
| Assets | | | | | | | | | | | | | | | | | | | |
Cash equivalents(a) | $ | 2,573 | | | $ | — | | | $ | — | | | $ | — | | | $ | 2,573 | | | $ | 1,673 | | | $ | — | | | $ | — | | | $ | — | | | $ | 1,673 | |
| NDT fund investments | | | | | | | | | | | | | | | | | | | |
Cash equivalents(b) | 647 | | | 135 | | | — | | | — | | | 782 | | | 647 | | | 135 | | | — | | | — | | | 782 | |
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| Equities | 4,373 | | | 1,717 | | | 1 | | | 1,559 | | | 7,650 | | | 4,373 | | | 1,717 | | | 1 | | | 1,559 | | | 7,650 | |
| Fixed income | | | | | | | | | | | | | | | | | | | |
Corporate debt(c) | — | | | 1,155 | | | 287 | | | — | | | 1,442 | | | — | | | 1,155 | | | 287 | | | — | | | 1,442 | |
| U.S. Treasury and agencies | 2,192 | | | 29 | | | — | | | — | | | 2,221 | | | 2,192 | | | 29 | | | — | | | — | | | 2,221 | |
| Foreign governments | — | | | 54 | | | — | | | — | | | 54 | | | — | | | 54 | | | — | | | — | | | 54 | |
| State and municipal debt | — | | | 29 | | | — | | | — | | | 29 | | | — | | | 29 | | | — | | | — | | | 29 | |
| Other | 31 | | | 29 | | | — | | | 1,259 | | | 1,319 | | | 31 | | | 29 | | | — | | | 1,259 | | | 1,319 | |
| Fixed income subtotal | 2,223 | | | 1,296 | | | 287 | | | 1,259 | | | 5,065 | | | 2,223 | | | 1,296 | | | 287 | | | 1,259 | | | 5,065 | |
| Private credit | — | | | — | | | 187 | | | 592 | | | 779 | | | — | | | — | | | 187 | | | 592 | | | 779 | |
| Private equity | — | | | — | | | — | | | 654 | | | 654 | | | — | | | — | | | — | | | 654 | | | 654 | |
| Real estate | — | | | — | | | — | | | 802 | | | 802 | | | — | | | — | | | — | | | 802 | | | 802 | |
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NDT fund investments subtotal(d)(e) | 7,243 | | | 3,148 | | | 475 | | | 4,866 | | | 15,732 | | | 7,243 | | | 3,148 | | | 475 | | | 4,866 | | | 15,732 | |
| Rabbi trust investments | | | | | | | | | | | | | | | | | | | |
| Cash equivalents | 65 | | | — | | | — | | | — | | | 65 | | | 4 | | | — | | | — | | | — | | | 4 | |
| Mutual funds | 104 | | | — | | | — | | | — | | | 104 | | | 35 | | | — | | | — | | | — | | | 35 | |
| Fixed income | — | | | 10 | | | — | | | — | | | 10 | | | — | | | — | | | — | | | — | | | — | |
| Life insurance contracts | — | | | 99 | | | 34 | | | — | | | 133 | | | — | | | 33 | | | — | | | — | | | 33 | |
| Rabbi trust investments subtotal | 169 | | | 109 | | | 34 | | | — | | | 312 | | | 39 | | | 33 | | | — | | | — | | | 72 | |
Investments in equities(f) | 137 | | | — | | | — | | | — | | | 137 | | | 137 | | | — | | | — | | | — | | | 137 | |
| Commodity derivative assets | | | | | | | | | | | | | | | | | | | |
| Economic hedges | 5,527 | | | 10,633 | | | 7,083 | | | — | | | 23,243 | | | 5,527 | | | 10,633 | | | 7,083 | | | — | | | 23,243 | |
| Proprietary trading | — | | | 56 | | | 12 | | | — | | | 68 | | | — | | | 56 | | | 12 | | | — | | | 68 | |
Effect of netting and allocation of collateral(g)(h) | (4,468) | | | (9,869) | | | (6,808) | | | — | | | (21,145) | | | (4,468) | | | (9,869) | | | (6,808) | | | — | | | (21,145) | |
| Commodity derivative assets subtotal | 1,059 | | | 820 | | | 287 | | | — | | | 2,166 | | | 1,059 | | | 820 | | | 287 | | | — | | | 2,166 | |
| DPP consideration | — | | | 501 | | | — | | | — | | | 501 | | | — | | | 501 | | | — | | | — | | | 501 | |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 14 — Fair Value of Financial Assets and Liabilities
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| Exelon | | Generation |
| As of September 30, 2021 | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total | | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total |
| Total assets | 11,181 | | | 4,578 | | | 796 | | | 4,866 | | | 21,421 | | | 10,151 | | | 4,502 | | | 762 | | | 4,866 | | | 20,281 | |
| Liabilities | | | | | | | | | | | | | | | | | | | |
| Commodity derivative liabilities | | | | | | | | | | | | | | | | | | | |
| Economic hedges | (4,126) | | | (9,192) | | | (8,554) | | | — | | | (21,872) | | | (4,126) | | | (9,192) | | | (8,340) | | | — | | | (21,658) | |
| Proprietary trading | — | | | (32) | | | (26) | | | — | | | (58) | | | — | | | (32) | | | (26) | | | — | | | (58) | |
Effect of netting and allocation of collateral(g)(h) | 4,123 | | | 9,159 | | | 6,218 | | | — | | | 19,500 | | | 4,123 | | | 9,159 | | | 6,218 | | | — | | | 19,500 | |
| Commodity derivative liabilities subtotal | (3) | | | (65) | | | (2,362) | | | — | | | (2,430) | | | (3) | | | (65) | | | (2,148) | | | — | | | (2,216) | |
| Deferred compensation obligation | — | | | (149) | | | — | | | — | | | (149) | | | — | | | (44) | | | — | | | — | | | (44) | |
| Total liabilities | (3) | | | (214) | | | (2,362) | | | — | | | (2,579) | | | (3) | | | (109) | | | (2,148) | | | — | | | (2,260) | |
| Total net assets (liabilities) | $ | 11,178 | | | $ | 4,364 | | | $ | (1,566) | | | $ | 4,866 | | | $ | 18,842 | | | $ | 10,148 | | | $ | 4,393 | | | $ | (1,386) | | | $ | 4,866 | | | $ | 18,021 | |
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| Exelon | | Generation |
| As of December 31, 2020 | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total | | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total |
| Assets | | | | | | | | | | | | | | | | | | | |
Cash equivalents(a) | $ | 686 | | | $ | — | | | $ | — | | | $ | — | | | $ | 686 | | | $ | 124 | | | $ | — | | | $ | — | | | $ | — | | | $ | 124 | |
| NDT fund investments | | | | | | | | | | | | | | | | | | | |
Cash equivalents(b) | 210 | | | 95 | | | — | | | — | | | 305 | | | 210 | | | 95 | | | — | | | — | | | 305 | |
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| Equities | 3,886 | | | 2,077 | | | — | | | 1,562 | | | 7,525 | | | 3,886 | | | 2,077 | | | — | | | 1,562 | | | 7,525 | |
| Fixed income | | | | | | | | | | | | | | | | | | | |
Corporate debt(c) | — | | | 1,485 | | | 285 | | | — | | | 1,770 | | | — | | | 1,485 | | | 285 | | | — | | | 1,770 | |
| U.S. Treasury and agencies | 1,871 | | | 126 | | | — | | | — | | | 1,997 | | | 1,871 | | | 126 | | | — | | | — | | | 1,997 | |
| Foreign governments | — | | | 56 | | | — | | | — | | | 56 | | | — | | | 56 | | | — | | | — | | | 56 | |
| State and municipal debt | — | | | 101 | | | — | | | — | | | 101 | | | — | | | 101 | | | — | | | — | | | 101 | |
| Other | — | | | 41 | | | — | | | 961 | | | 1,002 | | | — | | | 41 | | | — | | | 961 | | | 1,002 | |
| Fixed income subtotal | 1,871 | | | 1,809 | | | 285 | | | 961 | | | 4,926 | | | 1,871 | | | 1,809 | | | 285 | | | 961 | | | 4,926 | |
| Private credit | — | | | — | | | 212 | | | 629 | | | 841 | | | — | | | — | | | 212 | | | 629 | | | 841 | |
| Private equity | — | | | — | | | — | | | 504 | | | 504 | | | — | | | — | | | — | | | 504 | | | 504 | |
| Real estate | — | | | — | | | — | | | 679 | | | 679 | | | — | | | — | | | — | | | 679 | | | 679 | |
| | | | | | | | | | | | | | | | | | | |
NDT fund investments subtotal(d)(e) | 5,967 | | | 3,981 | | | 497 | | | 4,335 | | | 14,780 | | | 5,967 | | | 3,981 | | | 497 | | | 4,335 | | | 14,780 | |
| Rabbi trust investments | | | | | | | | | | | | | | | | | | | |
| Cash equivalents | 60 | | | — | | | — | | | — | | | 60 | | | 4 | | | — | | | — | | | — | | | 4 | |
| Mutual funds | 91 | | | — | | | — | | | — | | | 91 | | | 29 | | | — | | | — | | | — | | | 29 | |
| Fixed income | — | | | 11 | | | — | | | — | | | 11 | | | — | | | — | | | — | | | — | | | — | |
| Life insurance contracts | — | | | 87 | | | 34 | | | — | | | 121 | | | — | | | 28 | | | — | | | — | | | 28 | |
| Rabbi trust investments subtotal | 151 | | | 98 | | | 34 | | | — | | | 283 | | | 33 | | | 28 | | | — | | | — | | | 61 | |
Investments in equities(f) | 195 | | | — | | | — | | | — | | | 195 | | | 195 | | | — | | | — | | | — | | | 195 | |
| Commodity derivative assets | | | | | | | | | | | | | | | | | | | |
| Economic hedges | 745 | | | 1,914 | | | 1,599 | | | — | | | 4,258 | | | 745 | | | 1,914 | | | 1,599 | | | — | | | 4,258 | |
| Proprietary trading | — | | | 17 | | | 27 | | | — | | | 44 | | | — | | | 17 | | | 27 | | | — | | | 44 | |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)
Note 14 — Fair Value of Financial Assets and Liabilities
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Exelon | | Generation |
| As of December 31, 2020 | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total | | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total |
Effect of netting and allocation of collateral(g)(h) | (607) | | | (1,597) | | | (905) | | | — | | | (3,109) | | | (607) | | | (1,597) | | | (905) | | | — | | | (3,109) | |
| Commodity derivative assets subtotal | 138 | | | 334 | | | 721 | | | — | | | 1,193 | | | 138 | | | 334 | | | 721 | | | — | | | 1,193 | |
| DPP consideration | — | | | 639 | | | — | | | — | | | 639 | | | — | | | 639 | | | — | | | — | | | 639 | |
| Total assets | 7,137 | | | 5,052 | | | 1,252 | | | 4,335 | | | 17,776 | | | 6,457 | | | 4,982 | | | 1,218 | | | 4,335 | | | 16,992 | |
| Liabilities | | | | | | | | | | | | | | | | | | | |
| Commodity derivative liabilities | | | | | | | | | | | | | | | | | | | |
| Economic hedges | (682) | | | (1,928) | | | (1,655) | | | — | | | (4,265) | | | (682) | | | (1,928) | | | (1,354) | | | — | | | (3,964) | |
| Proprietary trading | — | | | (21) | | | (4) | | | — | | | (25) | | | — | | | (21) | | | (4) | | | — | | | (25) | |
Effect of netting and allocation of collateral(g)(h) | 540 | | | 1,918 | | | 1,067 | | | — | | | 3,525 | | | 540 | | | 1,918 | | | 1,067 | | | — | | | 3,525 | |
| Commodity derivative liabilities subtotal | (142) | | | (31) | | | (592) | | | — | | | (765) | | | (142) | | | (31) | | | (291) | | | — | | | (464) | |
| Deferred compensation obligation | — | | | (145) | | | — | | | — | | | (145) | | | — | | | (42) | | | — | | | — | | | (42) | |
| Total liabilities | (142) | | | (176) | | | (592) | | | — | | | (910) | | | (142) | | | (73) | | | (291) | | | — | | | (506) | |
| Total net assets | $ | 6,995 | | | $ | 4,876 | | | $ | 660 | | | $ | 4,335 | | | $ | 16,866 | | | $ | 6,315 | | | $ | 4,909 | | | $ | 927 | | | $ | 4,335 | | | $ | 16,486 | |
__________
(a)Exelon excludes cash of $689 million and $409 million at September 30, 2021 and December 31, 2020, respectively, and restricted cash of $222 million and $59 million at September 30, 2021 and December 31, 2020, respectively, and includes long-term restricted cash of $54 million and $53 million at September 30, 2021 and December 31, 2020, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. Generation excludes cash of $292 million and $171 million at September 30, 2021 and December 31, 2020, respectively, and restricted cash of $54 million and $20 million at September 30, 2021 and December 31, 2020, respectively.
(b)Includes $109 million and $116 million of cash received from outstanding repurchase agreements at September 30, 2021 and December 31, 2020, respectively, and is offset by an obligation to repay upon settlement of the agreement as discussed in (e) below.
(c)Includes investments in equities sold short of $(50) million and $(62) million as of September 30, 2021 and December 31, 2020, respectively, held in an investment vehicle primarily to hedge the equity option component of its convertible debt.
(d)Includes net derivative liabilities of less than $1 million and net derivative assets of $2 million, which have total notional amounts of $728 million and $1,043 million at September 30, 2021 and December 31, 2020, respectively. The notional principal amounts for these instruments provide one measure of the transaction volume outstanding as of the periods ended and do not represent the amount of Exelon and Generation's exposure to credit or market loss.
(e)Excludes net liabilities of $130 million and $181 million at September 30, 2021 and December 31, 2020, respectively, which include certain derivative assets that have notional amounts of $194 million and $104 million at September 30, 2021 and December 31, 2020, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, repurchase agreement obligations, and payables related to pending securities purchases. The repurchase agreements are generally short-term in nature with durations generally of 30 days or less.
(f)Includes equity investments held by Generation which were previously designated as equity investments without readily determinable fair value but are now publicly traded and therefore have readily determinable fair values. The first investment became publicly traded in the fourth quarter of 2020. Generation records the fair value of these investments in Other current assets in Exelon's and Generation's Consolidated Balance Sheets based on the quoted market prices of the stocks as of the respective balance sheet date. There were no equity investments without readily determinable fair value that became publicly traded during the third quarter of 2021. For investments that became publicly traded during the first half of 2021, unrealized gains of $220 million were recorded in Other, net in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income.
(g)Collateral (received) from counterparties, net of collateral paid to counterparties, totaled $(345) million, $(710) million, and $(590) million allocated to Level 1, Level 2, and Level 3 mark-to-market derivatives, respectively, as of September 30, 2021. Collateral (received)/posted from counterparties, net of collateral paid to counterparties, totaled $(67) million, $321 million, and $162 million allocated to Level 1, Level 2, and Level 3 mark-to-market derivatives, respectively, as of December 31, 2020.
(h)Includes $2,084 million held and $209 million posted of variation margin with the exchanges as of September 30, 2021 and December 31, 2020, respectively.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)
Note 14 — Fair Value of Financial Assets and Liabilities
As of September 30, 2021, Exelon and Generation have outstanding commitments to invest in private credit, private equity, and real estate investments of approximately $359 million, $174 million, and $371 million, respectively. These commitments will be funded by Generation’s existing NDT funds.
Exelon and Generation held investments without readily determinable fair values with carrying amounts of $44 million and $32 million as of September 30, 2021, respectively. Exelon and Generation held investments without readily determinable fair values with carrying amounts of $73 million and $55 million as of December 31, 2020, respectively. Changes in fair value, cumulative adjustments, and impairments were not material for the three and nine months ended September 30, 2021 and for the year ended December 31, 2020.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)
Note 1411 — Fair Value of Financial Assets and Liabilities
ComEd, PECO, and BGE
| | | ComEd | | PECO | | BGE | | ComEd | | PECO | | BGE |
| As of September 30, 2021 | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total | |
| As of June 30, 2022 | | As of June 30, 2022 | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total |
| Assets | Assets | | | | | | | | | | | | | | | | | | | | | | | | Assets | | | | | | | | | | | | | | | | | | | | | | | |
Cash equivalents(a) | Cash equivalents(a) | $ | 309 | | | $ | — | | | $ | — | | | $ | 309 | | | $ | 247 | | | $ | — | | | $ | — | | | $ | 247 | | | $ | 169 | | | $ | — | | | $ | — | | | $ | 169 | | Cash equivalents(a) | $ | 409 | | | $ | — | | | $ | — | | | $ | 409 | | | $ | 11 | | | $ | — | | | $ | — | | | $ | 11 | | | $ | 318 | | | $ | — | | | $ | — | | | $ | 318 | |
| Rabbi trust investments | Rabbi trust investments | | Rabbi trust investments | |
| | Mutual funds | Mutual funds | — | | | — | | | — | | | — | | | 10 | | | — | | | — | | | 10 | | | 14 | | | — | | | — | | | 14 | | Mutual funds | — | | | — | | | — | | | — | | | 9 | | | — | | | — | | | 9 | | | 7 | | | — | | | — | | | 7 | |
| Life insurance contracts | Life insurance contracts | — | | | — | | | — | | | — | | | — | | | 15 | | | — | | | 15 | | | — | | | — | | | — | | | — | | Life insurance contracts | — | | | — | | | — | | | — | | | — | | | 16 | | | — | | | 16 | | | — | | | — | | | — | | | — | |
| Rabbi trust investments subtotal | Rabbi trust investments subtotal | — | | | — | | | — | | | — | | | 10 | | | 15 | | | — | | | 25 | | | 14 | | | — | | | — | | | 14 | | Rabbi trust investments subtotal | — | | | — | | | — | | | — | | | 9 | | | 16 | | | — | | | 25 | | | 7 | | | — | | | — | | | 7 | |
Mark-to-market derivative assets(b) | | Mark-to-market derivative assets(b) | — | | | — | | | 15 | | | 15 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Total assets | Total assets | 309 | | | — | | | — | | | 309 | | | 257 | | | 15 | | | — | | | 272 | | | 183 | | | — | | | — | | | 183 | | Total assets | 409 | | | — | | | 15 | | | 424 | | | 20 | | | 16 | | | — | | | 36 | | | 325 | | | — | | | — | | | 325 | |
| Liabilities | Liabilities | | | | | | | | | | | | | | | | | | | | | | | | Liabilities | | | | | | | | | | | | | | | | | | | | | | | |
Mark-to-market derivative liabilities(b) | | Mark-to-market derivative liabilities(b) | — | | | — | | | (103) | | | (103) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Deferred compensation obligation | Deferred compensation obligation | — | | | (9) | | | — | | | (9) | | | — | | | (8) | | | — | | | (8) | | | — | | | (6) | | | — | | | (6) | | Deferred compensation obligation | — | | | (8) | | | — | | | (8) | | | — | | | (7) | | | — | | | (7) | | | — | | | (4) | | | — | | | (4) | |
Mark-to-market derivative liabilities(b) | — | | | — | | | (214) | | | (214) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | |
| Total liabilities | Total liabilities | — | | | (9) | | | (214) | | | (223) | | | — | | | (8) | | | — | | | (8) | | | — | | | (6) | | | — | | | (6) | | Total liabilities | — | | | (8) | | | (103) | | | (111) | | | — | | | (7) | | | — | | | (7) | | | — | | | (4) | | | — | | | (4) | |
| Total net assets (liabilities) | Total net assets (liabilities) | $ | 309 | | | $ | (9) | | | $ | (214) | | | $ | 86 | | | $ | 257 | | | $ | 7 | | | $ | — | | | $ | 264 | | | $ | 183 | | | $ | (6) | | | $ | — | | | $ | 177 | | Total net assets (liabilities) | $ | 409 | | | $ | (8) | | | $ | (88) | | | $ | 313 | | | $ | 20 | | | $ | 9 | | | $ | — | | | $ | 29 | | | $ | 325 | | | $ | (4) | | | $ | — | | | $ | 321 | |
| | | ComEd | | PECO | | BGE | | ComEd | | PECO | | BGE |
| As of December 31, 2020 | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total | |
| As of December 31, 2021 | | As of December 31, 2021 | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total |
| Assets | Assets | | | | | | | | | | | | | | | | | | | | | | | | Assets | | | | | | | | | | | | | | | | | | | | | | | |
Cash equivalents(a) | Cash equivalents(a) | $ | 285 | | | $ | — | | | $ | — | | | $ | 285 | | | $ | 8 | | | $ | — | | | $ | — | | | $ | 8 | | | $ | 120 | | | $ | — | | | $ | — | | | $ | 120 | | Cash equivalents(a) | $ | 237 | | | $ | — | | | $ | — | | | $ | 237 | | | $ | 9 | | | $ | — | | | $ | — | | | $ | 9 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
| Rabbi trust investments | Rabbi trust investments | | Rabbi trust investments | |
| Mutual funds | Mutual funds | — | | | — | | | — | | | — | | | 9 | | | — | | | — | | | 9 | | | 10 | | | — | | | — | | | 10 | | Mutual funds | — | | | — | | | — | | | — | | | 11 | | | — | | | — | | | 11 | | | 14 | | | — | | | — | | | 14 | |
| Life insurance contracts | Life insurance contracts | — | | | — | | | — | | | — | | | — | | | 13 | | | — | | | 13 | | | — | | | — | | | — | | | — | | Life insurance contracts | — | | | — | | | — | | | — | | | — | | | 16 | | | — | | | 16 | | | — | | | — | | | — | | | — | |
| Rabbi trust investments subtotal | Rabbi trust investments subtotal | — | | | — | | | — | | | — | | | 9 | | | 13 | | | — | | | 22 | | | 10 | | | — | | | — | | | 10 | | Rabbi trust investments subtotal | — | | | — | | | — | | | — | | | 11 | | | 16 | | | — | | | 27 | | | 14 | | | — | | | — | | | 14 | |
| Total assets | Total assets | 285 | | | — | | | — | | | 285 | | | 17 | | | 13 | | | — | | | 30 | | | 130 | | | — | | | — | | | 130 | | Total assets | 237 | | | — | | | — | | | 237 | | | 20 | | | 16 | | | — | | | 36 | | | 14 | | | — | | | — | | | 14 | |
| Liabilities | Liabilities | | | | | | | | | | | | | | | | | | | | | | | | Liabilities | | | | | | | | | | | | | | | | | | | | | | | |
Mark-to-market derivative liabilities(b) | | Mark-to-market derivative liabilities(b) | — | | | — | | | (219) | | | (219) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Deferred compensation obligation | Deferred compensation obligation | — | | | (8) | | | — | | | (8) | | | — | | | (9) | | | — | | | (9) | | | — | | | (5) | | | — | | | (5) | | Deferred compensation obligation | — | | | (10) | | | — | | | (10) | | | — | | | (9) | | | — | | | (9) | | | — | | | (7) | | | — | | | (7) | |
Mark-to-market derivative liabilities(b) | — | | | — | | | (301) | | | (301) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | |
| Total liabilities | Total liabilities | — | | | (8) | | | (301) | | | (309) | | | — | | | (9) | | | — | | | (9) | | | — | | | (5) | | | — | | | (5) | | Total liabilities | — | | | (10) | | | (219) | | | (229) | | | — | | | (9) | | | — | | | (9) | | | — | | | (7) | | | — | | | (7) | |
| Total net assets (liabilities) | Total net assets (liabilities) | $ | 285 | | | $ | (8) | | | $ | (301) | | | $ | (24) | | | $ | 17 | | | $ | 4 | | | $ | — | | | $ | 21 | | | $ | 130 | | | $ | (5) | | | $ | — | | | $ | 125 | | Total net assets (liabilities) | $ | 237 | | | $ | (10) | | | $ | (219) | | | $ | 8 | | | $ | 20 | | | $ | 7 | | | $ | — | | | $ | 27 | | | $ | 14 | | | $ | (7) | | | $ | — | | | $ | 7 | |
__________
(a)ComEd excludes cash of $145$21 million and $83$105 million at Septemberas of June 30, 20212022 and December 31, 2020,2021, respectively, and restricted cash of $107$133 million and $37$42 million at Septemberas of June 30, 20212022 and December 31, 2020,2021, respectively, and includes long-term restricted cash of $44$59 million and $43 million at Septemberas of June 30, 20212022 and December 31, 2020,2021, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. PECO excludes cash of $105$21 million and $18$35 million at Septemberas of June 30, 20212022 and December 31, 2020,2021, respectively. BGE excludes cash of $56$36 million and $24$51 million at Septemberas of June 30, 20212022 and December 31, 2020,2021, respectively, and restricted cash of $27$205 million and $1$4 million at Septemberas of June 30, 20212022 and December 31, 2020,2021, respectively.
(b)The Level 3 balance consists of the current asset of $15 million and current and noncurrent liability of $5none and $103 million, respectively, as of June 30, 2022 and none, $18 million and $209$201 million, respectively, at September 30, 2021 and $33 million and $268 million, respectively, atas of December 31, 20202021 related to floating-to-fixed energy swap contracts with unaffiliated suppliers.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 1411 — Fair Value of Financial Assets and Liabilities
PHI, Pepco, DPL, and ACE
| | | | As of September 30, 2021 | | As of December 31, 2020 | | As of June 30, 2022 | | As of December 31, 2021 |
| PHI | PHI | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total | PHI | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total |
| Assets | Assets | | | | | | | | | | | | | | | | Assets | | | | | | | | | | | | | | | |
Cash equivalents(a) | Cash equivalents(a) | $ | 100 | | | $ | — | | | $ | — | | | $ | 100 | | | $ | 86 | | | $ | — | | | $ | — | | | $ | 86 | | Cash equivalents(a) | $ | 557 | | | $ | — | | | $ | — | | | $ | 557 | | | $ | 110 | | | $ | — | | | $ | — | | | $ | 110 | |
| | Rabbi trust investments | Rabbi trust investments | | Rabbi trust investments | |
| Cash equivalents | Cash equivalents | 59 | | | — | | | — | | | 59 | | | 55 | | | — | | | — | | | 55 | | Cash equivalents | 60 | | | — | | | — | | | 60 | | | 59 | | | — | | | — | | | 59 | |
| Mutual funds | Mutual funds | 14 | | | — | | | — | | | 14 | | | 14 | | | — | | | — | | | 14 | | Mutual funds | 11 | | | — | | | — | | | 11 | | | 14 | | | — | | | — | | | 14 | |
| Fixed income | Fixed income | — | | | 10 | | | — | | | 10 | | | — | | | 11 | | | — | | | 11 | | Fixed income | — | | | 8 | | | — | | | 8 | | | — | | | 10 | | | — | | | 10 | |
| Life insurance contracts | Life insurance contracts | — | | | 27 | | | 34 | | | 61 | | | — | | | 26 | | | 34 | | | 60 | | Life insurance contracts | — | | | 22 | | | 37 | | | 59 | | | — | | | 27 | | | 35 | | | 62 | |
| Rabbi trust investments subtotal | Rabbi trust investments subtotal | 73 | | | 37 | | | 34 | | | 144 | | | 69 | | | 37 | | | 34 | | | 140 | | Rabbi trust investments subtotal | 71 | | | 30�� | | | 37 | | | 138 | | | 73 | | | 37 | | | 35 | | | 145 | |
| Total assets | Total assets | 173 | | | 37 | | | 34 | | | 244 | | | 155 | | | 37 | | | 34 | | | 226 | | Total assets | 628 | | | 30 | | | 37 | | | 695 | | | 183 | | | 37 | | | 35 | | | 255 | |
| Liabilities | Liabilities | | | | | | | | | | | | | | | | Liabilities | | | | | | | | | | | | | | | |
| Deferred compensation obligation | Deferred compensation obligation | — | | | (19) | | | — | | | (19) | | | — | | | (17) | | | — | | | (17) | | Deferred compensation obligation | — | | | (14) | | | — | | | (14) | | | — | | | (18) | | | — | | | (18) | |
| | Total liabilities | Total liabilities | — | | | (19) | | | — | | | (19) | | | — | | | (17) | | | — | | | (17) | | Total liabilities | — | | | (14) | | | — | | | (14) | | | — | | | (18) | | | — | | | (18) | |
| Total net assets | Total net assets | $ | 173 | | | $ | 18 | | | $ | 34 | | | $ | 225 | | | $ | 155 | | | $ | 20 | | | $ | 34 | | | $ | 209 | | Total net assets | $ | 628 | | | $ | 16 | | | $ | 37 | | | $ | 681 | | | $ | 183 | | | $ | 19 | | | $ | 35 | | | $ | 237 | |
| | | Pepco | | DPL | | ACE | | Pepco | | DPL | | ACE |
| As of September 30, 2021 | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total | |
| As of June 30, 2022 | | As of June 30, 2022 | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total |
| Assets | Assets | | | | | | | | | | | | | | | | | | | | | | | | Assets | | | | | | | | | | | | | | | | | | | | | | | |
Cash equivalents(a) | Cash equivalents(a) | $ | 36 | | | $ | — | | | $ | — | | | $ | 36 | | | $ | 26 | | | $ | — | | | $ | — | | | $ | 26 | | | $ | 14 | | | $ | — | | | $ | — | | | $ | 14 | | Cash equivalents(a) | $ | 115 | | | $ | — | | | $ | — | | | $ | 115 | | | $ | 223 | | | $ | — | | | $ | — | | | $ | 223 | | | $ | 218 | | | $ | — | | | $ | — | | | $ | 218 | |
| | Rabbi trust investments | Rabbi trust investments | | Rabbi trust investments | |
| Cash equivalents | Cash equivalents | 58 | | | — | | | — | | | 58 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Cash equivalents | 59 | | | — | | | — | | | 59 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Fixed income | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | |
| | Life insurance contracts | Life insurance contracts | — | | | 27 | | | 34 | | | 61 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Life insurance contracts | — | | | 22 | | | 37 | | | 59 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Rabbi trust investments subtotal | Rabbi trust investments subtotal | 58 | | | 27 | | | 34 | | | 119 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Rabbi trust investments subtotal | 59 | | | 22 | | | 37 | | | 118 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Total assets | Total assets | 94 | | | 27 | | | 34 | | | 155 | | | 26 | | | — | | | — | | | 26 | | | 14 | | | — | | | — | | | 14 | | Total assets | 174 | | | 22 | | | 37 | | | 233 | | | 223 | | | — | | | — | | | 223 | | | 218 | | | — | | | — | | | 218 | |
| Liabilities | Liabilities | | | | | | | | | | | | | | | | | | | | | | | | Liabilities | | | | | | | | | | | | | | | | | | | | | | | |
| Deferred compensation obligation | Deferred compensation obligation | — | | | (2) | | | — | | | (2) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Deferred compensation obligation | — | | | (1) | | | — | | | (1) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| | Total liabilities | Total liabilities | — | | | (2) | | | — | | | (2) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Total liabilities | — | | | (1) | | | — | | | (1) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Total net assets | Total net assets | $ | 94 | | | $ | 25 | | | $ | 34 | | | $ | 153 | | | $ | 26 | | | $ | — | | | $ | — | | | $ | 26 | | | $ | 14 | | | $ | — | | | $ | — | | | $ | 14 | | Total net assets | $ | 174 | | | $ | 21 | | | $ | 37 | | | $ | 232 | | | $ | 223 | | | $ | — | | | $ | — | | | $ | 223 | | | $ | 218 | | | $ | — | | | $ | — | | | $ | 218 | |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 1411 — Fair Value of Financial Assets and Liabilities
| | | Pepco | | DPL | | ACE | | Pepco | | DPL | | ACE |
| As of December 31, 2020 | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total | |
| As of December 31, 2021 | | As of December 31, 2021 | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total |
| Assets | Assets | | | | | | | | | | | | | | | | | | | | | | | | Assets | | | | | | | | | | | | | | | | | | | | | | | |
Cash equivalents(a) | Cash equivalents(a) | $ | 35 | | | $ | — | | | $ | — | | | $ | 35 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 13 | | | $ | — | | | $ | — | | | $ | 13 | | Cash equivalents(a) | $ | 31 | | | $ | — | | | $ | — | | | $ | 31 | | | $ | 43 | | | $ | — | | | $ | — | | | $ | 43 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
| | Rabbi trust investments | Rabbi trust investments | | Rabbi trust investments | |
| Cash equivalents | Cash equivalents | 53 | | | — | | | — | | | 53 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Cash equivalents | 58 | | | — | | | — | | | 58 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| | Fixed income | — | | | 2 | | | — | | | 2 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | |
| | Life insurance contracts | Life insurance contracts | — | | | 26 | | | 34 | | | 60 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Life insurance contracts | — | | | 27 | | | 35 | | | 62 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Rabbi trust investments subtotal | Rabbi trust investments subtotal | 53 | | | 28 | | | 34 | | | 115 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Rabbi trust investments subtotal | 58 | | | 27 | | | 35 | | | 120 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Total assets | Total assets | 88 | | | 28 | | | 34 | | | 150 | | | — | | | — | | | — | | | — | | | 13 | | | — | | | — | | | 13 | | Total assets | 89 | | | 27 | | | 35 | | | 151 | | | 43 | | | — | | | — | | | 43 | | | — | | | — | | | — | | | — | |
| Liabilities | Liabilities | | | | | | | | | | | | | | | | | | | | | | | | Liabilities | | | | | | | | | | | | | | | | | | | | | | | |
| Deferred compensation obligation | Deferred compensation obligation | — | | | (2) | | | — | | | (2) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Deferred compensation obligation | — | | | (2) | | | — | | | (2) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| | Total liabilities | Total liabilities | — | | | (2) | | | — | | | (2) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Total liabilities | — | | | (2) | | | — | | | (2) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Total net assets | Total net assets | $ | 88 | | | $ | 26 | | | $ | 34 | | | $ | 148 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 13 | | | $ | — | | | $ | — | | | $ | 13 | | Total net assets | $ | 89 | | | $ | 25 | | | $ | 35 | | | $ | 149 | | | $ | 43 | | | $ | — | | | $ | — | | | $ | 43 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
__________
(a)PHI excludes cash of $57$60 million and $74$100 million at Septemberas of June 30, 20212022 and December 31, 2020,2021, respectively, and restricted cash of $5$2 million and none at September$3 million as of June 30, 20212022 and December 31, 2020, respectively, and includes long-term restricted cash of $9 million and $10 million at September 30, 2021, and December 31, 2020, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets.respectively. Pepco excludes cash of $19$14 million and $30$34 million at Septemberas of June 30, 20212022 and December 31, 2020,2021, respectively, and restricted cash of $5$2 million and none at September$3 million as of June 30, 20212022 and December 31, 2020,2021, respectively. DPL excludes cash of $13$26 million and $15$28 million at Septemberas of June 30, 20212022 and December 31, 2020,2021, respectively. ACE excludes cash of $16$15 million and $17$29 million at Septemberas of June 30, 20212022 and December 31, 2020, respectively, and includes long-term restricted cash of $9 million and $10 million at September 30, 2021, and December 31, 2020, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets.respectively.
Reconciliation of Level 3 Assets and Liabilities
The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the three and ninesix months ended SeptemberJune 30, 20212022 and 2020:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Exelon | | Generation | | ComEd | | PHI and Pepco | | | | |
| Three Months Ended September 30, 2021 | Total | | NDT Fund
Investments | | Mark-to-Market
Derivatives | | | | Total Generation | | Mark-to-Market
Derivatives | | Life Insurance Contracts | | | | Eliminated in Consolidation |
| Balance as of June 30, 2021 | $ | (235) | | | $ | 461 | | | $ | (465) | | | | | $ | (4) | | | $ | (265) | | | $ | 34 | | | | | $ | — | |
| Total realized / unrealized gains (losses) | | | | | | | | | | | | | | | | | |
| Included in net income | (967) | | | 3 | | | (970) | | (a) | | | (967) | | | — | | | — | | | | | — | |
| Included in noncurrent payables to affiliates | — | | | 11 | | | — | | | | | 11 | | | — | | | — | | | | | (11) | |
| | | | | | | | | | | | | | | | | |
| Included in regulatory assets | 62 | | | — | | | — | | | | | — | | | 51 | | (b) | — | | | | | 11 | |
| Change in collateral | (413) | | | — | | | (413) | | | | | (413) | | | — | | | — | | | | | — | |
| Purchases, sales, and settlements | | | | | | | | | | | | | | | | | |
| Purchases | 8 | | | 2 | | | 6 | | | | | 8 | | | — | | | — | | | | | — | |
| Sales | 6 | | | — | | | 6 | | | | | 6 | | | — | | | — | | | | | — | |
| | | | | | | | | | | | | | | | | |
| Settlements | (2) | | | (2) | | | — | | | | | (2) | | | — | | | — | | | | | — | |
| Transfers into Level 3 | 2 | | | — | | | 2 | | (c) | | | 2 | | | — | | | — | | | | | — | |
| Transfers out of Level 3 | (27) | | | — | | | (27) | | (c) | | | (27) | | | — | | | — | | | | | — | |
| Balance at September 30, 2021 | $ | (1,566) | | | $ | 475 | | | $ | (1,861) | | | | | $ | (1,386) | | | $ | (214) | | | $ | 34 | | | | | $ | — | |
| The amount of total (losses) gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2021 | $ | (1,001) | | | $ | 3 | | | $ | (1,004) | | | | | $ | (1,001) | | | $ | — | | | $ | — | | | | | $ | — | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | |
| Exelon | | ComEd | | PHI and Pepco | | |
| Three Months Ended June 30, 2022 | Total | | Mark-to-Market
Derivatives | | Life Insurance Contracts | | |
| Balance as of April 1, 2022 | $ | (107) | | | $ | (144) | | | $ | 36 | | | |
| Total realized / unrealized gains | | | | | | | |
Included in net income(a) | 1 | | | — | | | 1 | | | |
| | | | | | | |
| | | | | | | |
| Included in regulatory assets/liabilities | 56 | | | 56 | | (b) | — | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| Balance at June 30, 2022 | $ | (50) | | | $ | (88) | | (c) | $ | 37 | | | |
| The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities as of June 30, 2022 | $ | 1 | | | $ | — | | | $ | 1 | | | |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 1411 — Fair Value of Financial Assets and Liabilities
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Exelon | | Generation | | ComEd | | PHI and Pepco | | | | |
| Nine months ended September 30, 2021 | Total | | NDT Fund
Investments | | Mark-to-Market
Derivatives | | | | Total Generation | | Mark-to-Market
Derivatives | | Life Insurance Contracts | | | | Eliminated in Consolidation |
| Balance as of December 31, 2020 | $ | 660 | | | $ | 497 | | | $ | 430 | | | | | $ | 927 | | | $ | (301) | | | $ | 34 | | | | | $ | — | |
| Total realized / unrealized gains (losses) | | | | | | | | | | | | | | | | | |
| Included in net income | (1,600) | | | 4 | | | (1,606) | | (a) | | | (1,602) | | | — | | | 2 | | | | | — | |
| Included in noncurrent payables to affiliates | — | | | 18 | | | — | | | | | 18 | | | — | | | — | | | | | (18) | |
| | | | | | | | | | | | | | | | | |
| Included in regulatory assets | 105 | | | — | | | — | | | | | — | | | 87 | | (b) | — | | | | | 18 | |
| Change in collateral | (751) | | | — | | | (751) | | | | | (751) | | | — | | | — | | | | | — | |
| Purchases, sales, and settlements | | | | | | | | | | | | | | | | | |
| Purchases | 123 | | | 3 | | | 120 | | | | | 123 | | | — | | | — | | | | | — | |
| Sales | 7 | | | — | | | 7 | | | | | 7 | | | — | | | — | | | | | — | |
| | | | | | | | | | | | | | | | | |
| Settlements | (50) | | | (48) | | | — | | | | | (48) | | | — | | | (2) | | | | | — | |
| Transfers into Level 3 | 4 | | | 1 | | | 3 | | (c) | | | 4 | | | — | | | — | | | | | — | |
| Transfers out of Level 3 | (64) | | | — | | | (64) | | (c) | | | (64) | | | — | | | — | | | | | — | |
| Balance as of September 30, 2021 | $ | (1,566) | | | $ | 475 | | | $ | (1,861) | | | | | $ | (1,386) | | | $ | (214) | | | $ | 34 | | | | | $ | — | |
| The amount of total (losses) gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2021 | $ | (1,521) | | | $ | 4 | | | $ | (1,527) | | | | | $ | (1,523) | | | $ | — | | | $ | 2 | | | | | $ | — | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | |
| Exelon | | ComEd | | PHI and Pepco | | |
| Three Months Ended June 30, 2021 | Total | | Mark-to-Market
Derivatives | | Life Insurance Contracts | | |
| Balance as of April 1, 2021 | $ | (260) | | | $ | (295) | | | $ | 35 | | | |
| Total realized / unrealized gains | | | | | | | |
Included in net income(a) | 1 | | | — | | | 1 | | | |
| | | | | | | |
| Included in regulatory assets | 30 | | | 30 | | (b) | — | | | |
| | | | | | | |
| Purchases, sales, and settlements | | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| Settlements | (2) | | | — | | | (2) | | | |
| | | | | | | |
| | | | | | | |
| Balance as of June 30, 2021 | $ | (231) | | | $ | (265) | | | $ | 34 | | | |
| The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities as of June 30, 2021 | $ | 1 | | | $ | — | | | $ | 1 | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Exelon | | Generation | | ComEd | | PHI and Pepco | | | | |
| Three Months Ended September 30, 2020 | Total | | NDT Fund
Investments | | Mark-to-Market
Derivatives | | | | Total Generation | | Mark-to-Market
Derivatives | | Life Insurance Contracts | | | | Eliminated in Consolidation |
| Balance as of June 30, 2020 | $ | 883 | | | $ | 499 | | | $ | 659 | | | | | $ | 1,158 | | | $ | (318) | | | $ | 43 | | | | | $ | — | |
| Total realized / unrealized gains (losses) | | | | | | | | | | | | | | | | | |
| Included in net income | (327) | | | 3 | | | (318) | | (a) | | | (315) | | | — | | | (12) | | | | | — | |
| Included in noncurrent payables to affiliates | — | | | 18 | | | — | | | | | 18 | | | — | | | — | | | | | (18) | |
| Included in regulatory assets/liabilities | 32 | | | — | | | — | | | | | — | | | 14 | | (b) | — | | | | | 18 | |
| Change in collateral | (79) | | | — | | | (79) | | | | | (79) | | | — | | | — | | | | | — | |
| Purchases, sales, and settlements | | | | | | | | | | | | | | | | | |
| Purchases | 66 | | | 1 | | | 65 | | | | | 66 | | | — | | | — | | | | | — | |
| Sales | (3) | | | — | | | (3) | | | | | (3) | | | — | | | — | | | | | — | |
| | | | | | | | | | | | | | | | | |
| Settlements | — | | | (3) | | | — | | | | | (3) | | | — | | | 3 | | | | | — | |
| | | | | | | | | | | | | | | | | |
| Transfers out of Level 3 | 9 | | | — | | | 9 | | (c) | | | 9 | | | — | | | — | | | | | — | |
| Balance as of September 30, 2020 | $ | 581 | | | $ | 518 | | | $ | 333 | | | | | $ | 851 | | | $ | (304) | | | $ | 34 | | | | | $ | — | |
| The amount of total (losses) gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2020 | $ | (222) | | | $ | 3 | | | $ | (213) | | | | | $ | (210) | | | $ | — | | | $ | (12) | | | | | $ | — | |
122 | | | | | | | | | | | | | | | | | | | |
| Exelon | | ComEd | | PHI and Pepco | | |
| Six months ended June 30, 2022 | Total | | Mark-to-Market
Derivatives | | Life Insurance Contracts | | |
| Balance as of January 1, 2022 | $ | (182) | | | $ | (219) | | | $ | 35 | | | |
| Total realized / unrealized gains | | | | | | | |
Included in net income(a) | 2 | | | — | | | 2 | | | |
| | | | | | | |
| | | | | | | |
| Included in regulatory assets/liabilities | 131 | | | 131 | | (b) | — | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| Transfers out of Level 3 | (1) | | | — | | | — | | | |
| Balance as of June 30, 2022 | $ | (50) | | | $ | (88) | | (c) | $ | 37 | | | |
| The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities as of June 30, 2022 | $ | 2 | | | $ | — | | | $ | 2 | | | |
| | | | | | | | | | | | | | | | | | | |
| Exelon | | ComEd | | PHI and Pepco | | |
| Six Months Ended June 30, 2021 | Total | | Mark-to-Market
Derivatives | | Life Insurance Contracts | | |
| Balance as of January 1, 2021 | $ | (267) | | | $ | (301) | | | $ | 34 | | | |
| Total realized / unrealized gains | | | | | | | |
Included in net income(a) | 2 | | | — | | | 2 | | | |
| | | | | | | |
| | | | | | | |
| Included in regulatory assets | 36 | | | 36 | | (b) | — | | | |
| | | | | | | |
| Purchases, sales, and settlements | | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| Settlements | (2) | | | — | | | (2) | | | |
| | | | | | | |
| | | | | | | |
| Balance as of June 30, 2021 | $ | (231) | | | $ | (265) | | | $ | 34 | | | |
| The amount of total gains included in income attributed to the change in unrealized gain related to assets and liabilities as of June 30, 2021 | $ | 2 | | | $ | — | | | $ | 2 | | | |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)
Note 14 — Fair Value of Financial Assets and Liabilities
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Exelon | | Generation | | ComEd | | PHI and Pepco | | | | |
| Nine Months Ended September 30, 2020 | Total | | NDT Fund
Investments | | Mark-to-Market
Derivatives | | | | Total Generation | | Mark-to-Market
Derivatives | | Life Insurance Contracts | | | | Eliminated in Consolidation |
| Balance as of December 31, 2019 | $ | 1,068 | | | $ | 511 | | | $ | 817 | | | | | $ | 1,328 | | | $ | (301) | | | $ | 41 | | | | | $ | — | |
| Total realized / unrealized gains (losses) | | | | | | | | | | | | | | | | | |
| Included in net income | (483) | | | 1 | | | (474) | | (a) | | | (473) | | | — | | | (10) | | | | | — | |
| Included in noncurrent payables to affiliates | — | | | 17 | | | — | | | | | 17 | | | — | | | — | | | | | (17) | |
| | | | | | | | | | | | | | | | | |
| Included in regulatory assets | 14 | | | — | | | — | | | | | — | | | (3) | | (b) | — | | | | | 17 | |
| Change in collateral | (120) | | | — | | | (120) | | | | | (120) | | | — | | | — | | | | | — | |
| Purchases, sales, and settlements | | | | | | | | | | | | | | | | | |
| Purchases | 136 | | | 6 | | | 130 | | | | | 136 | | | — | | | — | | | | | — | |
| Sales | (27) | | | — | | | (27) | | | | | (27) | | | — | | | — | | | | | — | |
| | | | | | | | | | | | | | | | | |
| Settlements | (15) | | | (18) | | | — | | | | | (18) | | | — | | | 3 | | | | | — | |
| Transfers into Level 3 | (5) | | | 1 | | | (6) | | (c) | | | (5) | | | — | | | — | | | | | — | |
| Transfers out of Level 3 | 13 | | | — | | | 13 | | (c) | | | 13 | | | — | | | — | | | | | — | |
| Balance as of September 30, 2020 | $ | 581 | | | $ | 518 | | | $ | 333 | | | | | $ | 851 | | | $ | (304) | | | $ | 34 | | | | | $ | — | |
| The amount of total (losses) gains included in income attributed to the change in unrealized (losses) gains related to assets and liabilities as of September 30, 2020 | $ | (107) | | | $ | 1 | | | $ | (98) | | | | | $ | (97) | | | $ | — | | | $ | (10) | | | | | $ | — | |
__________
(a)Includes an additionClassified in Operating and maintenance expense in the Consolidated Statements of $34 million for realized lossesOperations and a reduction of $80 million for realized gains due to the settlement of derivative contracts for the three and nine months ended September 30, 2021. Includes a reduction of $105 million and $376 million for realized gains due to the settlement of derivative contracts for the three and nine months ended September 30, 2020.Comprehensive Income.
(b)Includes $49$59 million of increases in fair value and an increasea decrease for realized lossesgains due to settlements of $2$3 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended SeptemberJune 30, 2021.2022. Includes $72 million of increases in fair value and an increase for realized losses due to settlements of $15 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the nine months ended September 30, 2021. Includes $9$25 million of increases in fair value and an increase for realized losses due to settlements of $5 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended SeptemberJune 30, 2020.2021. Includes $26$128 million of decreaseincreases in fair value and an increase for realized losses due to settlements of $3 million recorded in purchase power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the six months ended June 30, 2022. Includes $23 million of increases in fair value and an increase for realized losses due to settlements of $13 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the ninesix months ended SeptemberJune 30, 2020.2021.
(c)Transfers into and outThe balance consists of Level 3 generally occur when the contract tenor becomes less and more observable respectively, primarily due to changes in market liquidity or assumptions for certain commodity contracts.
The following tables present the income statement classification$15 million of the total realized and unrealized gains (losses) included in income for Level 3current assets and liabilities measured at fair value on a recurring basis during the threecurrent and nine months ended Septembernoncurrent liability of none and $103 million, respectively, as of June 30, 2021 and 2020:2022.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Exelon | | Generation | | | | | | | | PHI and Pepco |
| Operating
Revenues | | Purchased
Power and
Fuel | | Operating and Maintenance | | Other, net | | Operating
Revenues | | Purchased
Power and
Fuel | | Other, net | | | | | | | | Operating and Maintenance |
| Total (losses) gains included in net income for the three months ended September 30, 2021 | $ | (1,274) | | | $ | 304 | | | $ | — | | | $ | 3 | | | $ | (1,274) | | | $ | 304 | | | $ | 3 | | | | | | | | | $ | — | |
| Total (losses) gains included in net income for the nine months ended September 30, 2021 | (1,944) | | | 338 | | | 2 | | | 4 | | | (1,944) | | | 338 | | | 4 | | | | | | | | | 2 | |
| Total unrealized (losses) gains for the three months ended September 30, 2021 | (1,361) | | | 357 | | | — | | | 3 | | | (1,361) | | | 357 | | | 3 | | | | | | | | | — | |
| Total unrealized (losses) gains for the nine months ended September 30, 2021 | (1,969) | | | 443 | | | 2 | | | 4 | | | (1,969) | | | 443 | | | 4 | | | | | | | | | 2 | |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 1411 — Fair Value of Financial Assets and Liabilities
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Exelon | | Generation | | PHI and Pepco |
| Operating
Revenues | | Purchased
Power and
Fuel | | Operating and Maintenance | | Other, net | | Operating
Revenues | | Purchased
Power and
Fuel | | Other, net | | Operating and Maintenance |
| Total losses included in net income for the three months ended September 30, 2020 | $ | (305) | | | $ | (13) | | | $ | (12) | | | $ | — | | | $ | (305) | | | $ | (13) | | | $ | — | | | $ | (12) | |
| Total losses included in net income for the nine months ended September 30, 2020 | (370) | | | (104) | | | (10) | | | — | | | (370) | | | (104) | | | — | | | (10) | |
| Total unrealized (losses) gains for the three months ended September 30, 2020 | (216) | | | 3 | | | (12) | | | 3 | | | (216) | | | 3 | | | 3 | | | (12) | |
| Total unrealized gains (losses) for the nine months ended September 30, 2020 | (50) | | | (48) | | | (10) | | | 1 | | | (50) | | | (48) | | | 1 | | | (10) | |
Valuation Techniques Used to Determine Fair Value
Exelon’s valuation techniques used to measure the fair value of the assets and liabilities shown in the tables below are in accordance with the policies discussed in Note 1816 — Fair Value of Financial Assets and Liabilities of the Exelon 20202021 Recast Form 10-K.
Valuation Techniques Used to Determine Net asset Value (Exelon and Generation)
Certain NDT Fund Investments are not classified within the fair value hierarchy and are included under the heading “Not subject to leveling” in the table above. These investments are measured at fair value using NAV per share as a practical expedient and include commingled funds, mutual funds which are not publicly quoted, managed private credit funds, private equity and real estate funds.
For commingled funds and mutual funds, which are not publicly quoted, the fair value is primarily derived from the quoted prices in active markets on the underlying securities and can typically be redeemed monthly with 30 or less days of notice and without further restrictions. For managed private credit funds, the fair value is determined using a combination of valuation models including cost models, market models, and income models and typically cannot be redeemed until maturity of the term loan. Private equity and real estate investments include those in limited partnerships that invest in operating companies and real estate holding companies that are not publicly traded on a stock exchange, such as, leveraged buyouts, growth capital, venture capital, distressed investments, investments in natural resources, and direct investments in pools of real estate properties. These investments typically cannot be redeemed and are generally liquidated over a period of 8 to 10 years from the initial investment date, which is based on Exelon’s understanding of the investment funds. Private equity and real estate valuations are reported by the fund manager and are based on the valuation of the underlying investments, which include inputs such as cost, operating results, discounted future cash flows, market based comparable data, and independent appraisals from sources with professional qualifications. These valuation inputs are unobservable.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)
Note 14 — Fair Value of Financial Assets and Liabilities
Mark-to-Market Derivatives (Exelon Generation, and ComEd)
The table below discloses the significant unobservable inputs to the forward curve used to value mark-to-market derivatives.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Type of trade | | Fair Value at September 30, 2021 | | Fair Value at December 31, 2020 | | Valuation
Technique | | Unobservable
Input | | 2021 Range & Arithmetic Average | | 2020 Range & Arithmetic Average |
Mark-to-market derivatives — Economic Hedges (Exelon and Generation)(a)(b) | | $ | (1,257) | | | $ | 245 | | | Discounted
Cash Flow | | Forward power
price | | $9.77 | - | $301 | $55 | | $2.25 | - | $163 | $30 |
| | | | | | | | Forward gas
price | | $1.76 | - | $23.00 | $4.16 | | $1.57 | - | $7.88 | $2.59 |
| | | | | | Option
Model | | Volatility
percentage | | 35% | - | 197% | 49% | | 11% | - | 237% | 32% |
| | | | | | | | | | | | | | | | | | |
Mark-to-market derivatives — Proprietary trading (Exelon and Generation)(a)(b) | | $ | (14) | | | $ | 23 | | | Discounted
Cash Flow | | Forward power
price | | $16 | - | $156 | $53 | | $10 | - | $106 | $27 |
| | | | | | | | | | | | | | | | | | |
| Mark-to-market derivatives (Exelon and ComEd) | | $ | (214) | | | $ | (301) | | | Discounted
Cash Flow | | Forward heat
rate(c) | | 9x | - | 10x | 9.13x | | 8x | - | 9x | 8.85x |
| | | | | | | | Marketability
reserve | | 3% | - | 7% | 4.77% | | 3% | - | 8% | 4.93% |
| | | | | | | | Renewable
factor | | 95% | - | 122% | 100% | | 91% | - | 123% | 99% |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Type of trade | | Fair Value as of June 30, 2022 | | Fair Value as of December 31, 2021 | | Valuation
Technique | | Unobservable
Input | | 2022 Range & Arithmetic Average | | 2021 Range & Arithmetic Average |
| Mark-to-market derivatives | | $ | (88) | | | $ | (219) | | | Discounted
Cash Flow | | Forward power price(a) | | $30.54 | - | $89.78 | $46.33 | | $28.65 | - | $47.10 | $33.96 |
__________________
(a)The valuation techniques, unobservable inputs, ranges and arithmetic averages are the same for the asset and liability positions.
(b)The fair values do not include cash collateral (received)/posted on level three positions of $(590) million and $162 million as of September 30, 2021 and December 31, 2020, respectively.
(c)Quoted forward natural gas rates are utilized to project the forward power curve for the delivery of energy at specified future dates. The natural gas curve is extrapolated beyond its observable period to the end of the contract’s delivery.
The inputs listed above, which are as of the balance sheet date, would have a direct impact on the fair values of the above instruments if they were adjusted. The significant unobservable inputs used in the fair value measurement of Generation’s commodity derivatives are forward commodity prices and for options is price volatility. Increases (decreases) in the forward commodity price in isolation would result in significantly higher (lower) fair values for long positions (contracts that give Generation the obligation or option to purchase a commodity), with offsetting impacts to short positions (contracts that give Generation the obligation or right to sell a commodity). Increases (decreases) in volatility would increase (decrease) the value for the holder of the option (writer of the option). Generally, a change in the estimate of forward commodity prices is unrelated to a change in the estimate of volatility of prices. An increase to the reserves listed above would decrease the fair value of the positions. An increase to the heat rate or renewable factorsforward power price would increase the fair value accordingly. Generally, interrelationships exist between market prices of natural gas and power. As such, an increase in natural gas pricing would potentially have a similar impact on forward power markets.value.
15.12. Commitments and Contingencies (All Registrants)
The following is an update to the current status of commitments and contingencies set forth in Note 1917 — Commitments and Contingencies of the Exelon 20202021 Recast Form 10-K.
Commitments
PHI Merger Commitments (Exelon, PHI, Pepco, DPL, and ACE). Approval of the PHI Merger in Delaware, New Jersey, Maryland, and the District of Columbia was conditioned upon Exelon and PHI agreeing to certain commitments. The following amounts represent total commitment costs that have been recorded since the acquisition date and the total remaining obligations for Exelon, PHI, Pepco, DPL, and ACE as of SeptemberJune 30, 2021:2022:
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)
Note 15 — Commitments and Contingencies
| | Description | Description | Exelon | | PHI | | Pepco | | DPL | | ACE | Description | Exelon | | PHI | | Pepco | | DPL | | ACE |
| Total commitments | Total commitments | $ | 513 | | | $ | 320 | | | $ | 120 | | | $ | 89 | | | $ | 111 | | Total commitments | $ | 513 | | | $ | 320 | | | $ | 120 | | | $ | 89 | | | $ | 111 | |
Remaining commitments(a) | Remaining commitments(a) | 74 | | | 62 | | | 51 | | | 7 | | | 4 | | Remaining commitments(a) | 61 | | | 53 | | | 44 | | | 6 | | | 3 | |
|
__________
(a)Remaining commitments extend through 2026 and include rate credits, energy efficiency programs and delivery system modernization.
In addition, Exelon is committed to develop or to assist in the commercial development of approximately 37 MWs of new solar generation in Maryland, District of Columbia, and Delaware at an estimated cost of approximately $135 million, which will generate future earnings at Exelon and Generation. Investment costs, which are expected to be primarily capital in nature, are recognized as incurred and recorded in Exelon's and Generation's financial statements. As of September 30, 2021, approximately 33 MWs of new generation were developed and Exelon and Generation have incurred costs of $121 million. Approximately 30 MWs of the new generation developed was part of Generation's first quarter 2021 sale of a significant portion of its solar business. Refer to Note 2 — Mergers, Acquisitions, and Dispositions for additional information on the solar business. Exelon has also committed to purchase 100 MWs of wind energy in PJM. DPL has committed to conducting three RFPs to procure up to a total of 120 MWs of wind RECs for the purpose of meeting Delaware's renewable portfolio standards. DPL has conducted two of the three wind REC RFPs. The first 40 MW wind REC tranche was conducted in 2017 and did not result in a purchase agreement. The second 40 MW wind REC tranche was conducted in 2018 and resulted in a proposed REC purchase agreement that was approved by the DPSCDEPSC in 2019. The RFP for the third and final 40 MW wind REC tranche is under way and bids will be conductedevaluated in the third quarter of 2022, with a potential award in the fourth quarter of 2022.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 1512 — Commitments and Contingencies
Commercial Commitments (All Registrants). The Registrants’ commercial commitments as of SeptemberJune 30, 2021,2022, representing commitments potentially triggered by future events were as follows:follows:
| | | Expiration within | | Expiration within |
| | Total | | 2021 | | 2022 | | 2023 | | 2024 | | 2025 | | 2026 and beyond | | Total | | 2022 | | 2023 | | 2024 | | 2025 | | 2026 | | 2027 and beyond |
| Exelon | Exelon | | | | | | | | | | | | | | Exelon | | | | | | | | | | | | | |
| Letters of credit | Letters of credit | $ | 2,241 | | | $ | 268 | | | $ | 1,860 | | | $ | 113 | | | $ | — | | | $ | — | | | $ | — | | Letters of credit | $ | 17 | | | $ | 8 | | | $ | 9 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
Surety bonds(a) | Surety bonds(a) | 971 | | | 403 | | | 566 | | | — | | | 2 | | | — | | | — | | Surety bonds(a) | 185 | | | 144 | | | 39 | | | 2 | | | — | | | — | | | — | |
| Financing trust guarantees | Financing trust guarantees | 378 | | | — | | | — | | | — | | | — | | | — | | | 378 | | Financing trust guarantees | 378 | | | — | | | — | | | — | | | — | | | — | | | 378 | |
Guaranteed lease residual values(b) | Guaranteed lease residual values(b) | 31 | | | — | | | 3 | | | 3 | | | 6 | | | 6 | | | 13 | | Guaranteed lease residual values(b) | 30 | | | — | | | 2 | | | 6 | | | 6 | | | 5 | | | 11 | |
| Total commercial commitments | $ | 3,621 | | | $ | 671 | | | $ | 2,429 | | | $ | 116 | | | $ | 8 | | | $ | 6 | | | $ | 391 | | |
| | Generation | | |
| Letters of credit | $ | 2,223 | | | $ | 264 | | | $ | 1,846 | | | $ | 113 | | | $ | — | | | $ | — | | | $ | — | | |
Surety bonds(a) | 826 | | | 352 | | | 474 | | | — | | | — | | | — | | | — | | |
| Total commercial commitments | Total commercial commitments | $ | 3,049 | | | $ | 616 | | | $ | 2,320 | | | $ | 113 | | | $ | — | | | $ | — | | | $ | — | | Total commercial commitments | $ | 610 | | | $ | 152 | | | $ | 50 | | | $ | 8 | | | $ | 6 | | | $ | 5 | | | $ | 389 | |
| | ComEd | ComEd | | ComEd | |
| Letters of credit | Letters of credit | $ | 7 | | | $ | 2 | | | $ | 5 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | Letters of credit | $ | 10 | | | $ | 4 | | | $ | 6 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
Surety bonds(a) | Surety bonds(a) | 17 | | | 5 | | | 10 | | | — | | | 2 | | | — | | | — | | Surety bonds(a) | 16 | | | 9 | | | 5 | | | 2 | | | — | | | — | | | — | |
| Financing trust guarantees | Financing trust guarantees | 200 | | | — | | | — | | | — | | | — | | | — | | | 200 | | Financing trust guarantees | 200 | | | — | | | — | | | — | | | — | | | — | | | 200 | |
| Total commercial commitments | Total commercial commitments | $ | 224 | | | $ | 7 | | | $ | 15 | | | $ | — | | | $ | 2 | | | $ | — | | | $ | 200 | | Total commercial commitments | $ | 226 | | | $ | 13 | | | $ | 11 | | | $ | 2 | | | $ | — | | | $ | — | | | $ | 200 | |
| | PECO | PECO | | PECO | |
| Letters of credit | Letters of credit | $ | 1 | | | $ | — | | | $ | 1 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | Letters of credit | $ | 1 | | | $ | — | | | $ | 1 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
Surety bonds(a) | Surety bonds(a) | 2 | | | — | | | 2 | | | — | | | — | | | — | | | — | | Surety bonds(a) | 3 | | | 1 | | | 2 | | | — | | | — | | | — | | | — | |
| Financing trust guarantees | Financing trust guarantees | 178 | | | — | | | — | | | — | | | — | | | — | | | 178 | | Financing trust guarantees | 178 | | | — | | | — | | | — | | | — | | | — | | | 178 | |
| Total commercial commitments | Total commercial commitments | $ | 181 | | | $ | — | | | $ | 3 | | | $ | — | | | $ | — | | | $ | — | | | $ | 178 | | Total commercial commitments | $ | 182 | | | $ | 1 | | | $ | 3 | | | $ | — | | | $ | — | | | $ | — | | | $ | 178 | |
| | BGE | BGE | | BGE | |
| Letters of credit | Letters of credit | $ | 2 | | | $ | — | | | $ | 2 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | Letters of credit | $ | 2 | | | $ | 2 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
Surety bonds(a) | Surety bonds(a) | 3 | | | 2 | | | 1 | | | — | | | — | | | — | | | — | | Surety bonds(a) | 2 | | | 1 | | | 1 | | | — | | | — | | | — | | | — | |
| Total commercial commitments | Total commercial commitments | $ | 5 | | | $ | 2 | | | $ | 3 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | Total commercial commitments | $ | 4 | | | $ | 3 | | | $ | 1 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
| | PHI | PHI | | PHI | |
| Surety bonds(a) | Surety bonds(a) | $ | 23 | | | $ | 3 | | | $ | 20 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | Surety bonds(a) | $ | 95 | | | $ | 76 | | | $ | 19 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
Guaranteed lease residual values(b) | Guaranteed lease residual values(b) | 31 | | | — | | | 3 | | | 3 | | | 6 | | | 6 | | | 13 | | Guaranteed lease residual values(b) | 30 | | | — | | | 2 | | | 6 | | | 6 | | | 5 | | | 11 | |
| Total commercial commitments | Total commercial commitments | $ | 54 | | | $ | 3 | | | $ | 23 | | | $ | 3 | | | $ | 6 | | | $ | 6 | | | $ | 13 | | Total commercial commitments | $ | 125 | | | $ | 76 | | | $ | 21 | | | $ | 6 | | | $ | 6 | | | $ | 5 | | | $ | 11 | |
| | Pepco | Pepco | | Pepco | |
| Surety bonds(a) | Surety bonds(a) | $ | 14 | | | $ | — | | | $ | 14 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | Surety bonds(a) | $ | 84 | | | $ | 71 | | | $ | 13 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
Guaranteed lease residual values(b) | Guaranteed lease residual values(b) | 10 | | | — | | | 1 | | | 1 | | | 2 | | | 2 | | | 4 | | Guaranteed lease residual values(b) | 10 | | | — | | | 1 | | | 2 | | | 2 | | | 2 | | | 3 | |
| Total commercial commitments | Total commercial commitments | $ | 24 | | | $ | — | | | $ | 15 | | | $ | 1 | | | $ | 2 | | | $ | 2 | | | $ | 4 | | Total commercial commitments | $ | 94 | | | $ | 71 | | | $ | 14 | | | $ | 2 | | | $ | 2 | | | $ | 2 | | | $ | 3 | |
| | DPL | DPL | | DPL | |
| Surety bonds(a) | Surety bonds(a) | $ | 5 | | | $ | 2 | | | $ | 3 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | Surety bonds(a) | $ | 7 | | | $ | 3 | | | $ | 4 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
Guaranteed lease residual values(b) | Guaranteed lease residual values(b) | 13 | | | — | | | 1 | | | 1 | | | 3 | | | 3 | | | 5 | | Guaranteed lease residual values(b) | 13 | | | — | | | — | | | 3 | | | 3 | | | 2 | | | 5 | |
| Total commercial commitments | Total commercial commitments | $ | 18 | | | $ | 2 | | | $ | 4 | | | $ | 1 | | | $ | 3 | | | $ | 3 | | | $ | 5 | | Total commercial commitments | $ | 20 | | | $ | 3 | | | $ | 4 | | | $ | 3 | | | $ | 3 | | | $ | 2 | | | $ | 5 | |
| | ACE | ACE | | ACE | |
Surety bonds(a) | Surety bonds(a) | $ | 4 | | | $ | 1 | | | $ | 3 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | Surety bonds(a) | $ | 4 | | | $ | 2 | | | $ | 2 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
Guaranteed lease residual values(b) | Guaranteed lease residual values(b) | 8 | | | — | | | 1 | | | 1 | | | 1 | | | 1 | | | 4 | | Guaranteed lease residual values(b) | 7 | | | — | | | 1 | | | 1 | | | 1 | | | 1 | | | 3 | |
| Total commercial commitments | Total commercial commitments | $ | 12 | | | $ | 1 | | | $ | 4 | | | $ | 1 | | | $ | 1 | | | $ | 1 | | | $ | 4 | | Total commercial commitments | $ | 11 | | | $ | 2 | | | $ | 3 | | | $ | 1 | | | $ | 1 | | | $ | 1 | | | $ | 3 | |
__________
(a)Surety bonds—bonds — Guarantees issued related to contract and commercial agreements, excluding bid bonds.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 1512 — Commitments and Contingencies
(b)Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The lease term associated with these assets ranges from 1 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $75$74 million guaranteed by Exelon and PHI, of which $25$24 million, $32$31 million, and $18$19 million is guaranteed by Pepco, DPL, and ACE, respectively. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote.
Environmental Remediation Matters
General (All Registrants). The Registrants’ operations have in the past, and may in the future, require substantial expenditures to comply with environmental laws. Additionally, under Federalfederal and state environmental laws, the Registrants are generally liable for the costs of remediating environmental contamination of property now or formerly owned by them and of property contaminated by hazardous substances generated by them. The Registrants own or lease a number of real estate parcels, including parcels on which their operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws. In addition, the Registrants are currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and may be subject to additional proceedings in the future. Unless otherwise disclosed, the Registrants cannot reasonably estimate whether they will incur significant liabilities for additional investigation and remediation costs at these or additional sites identified by the Registrants, environmental agencies or others, or whether such costs will be recoverable from third parties, including customers. Additional costs could have a material, unfavorable impact on the Registrants' financial statements.
MGP Sites (Exelon and the Utility(All Registrants). ComEd, PECO, BGE, and DPL have identified sites where former MGP or gas purification activities have or may have resulted in actual site contamination. For almost all of these sites, there are additional PRPs that may share responsibility for the ultimate remediation of each location.
•ComEd has 21 sites that are currently under some degree of active study and/or remediation. ComEd expects the majority of the remediation at these sites to continue through at least 2027.2031.
•PECO has 6 sites that are currently under some degree of active study and/or remediation. PECO expects the majority of the remediation at these sites to continue through at least 2023.
•BGE has 4 sites that currently require some level of remediation and/or ongoing activity. BGE expects the majority of the remediation at these sites to continue through at least 2023.
•DPL has 1 site that is currently under study and the required cost at the site is not expected to be material.
The historical nature of the MGP and gas purification sites and the fact that many of the sites have been buried and built over, impacts the ability to determine a precise estimate of the ultimate costs prior to initial sampling and determination of the exact scope and method of remedial activity. Management determines its best estimate of remediation costs using all available information at the time of each study, including probabilistic and deterministic modeling for ComEd and PECO, and the remediation standards currently required by the applicable state environmental agency. Prior to completion of any significant clean up, each site remediation plan is approved by the appropriate state environmental agency.
ComEd, pursuant to an ICC order, and PECO, pursuant to settlements of natural gas distribution rate cases with thea PAPUC order, are currently recovering environmental remediation costs of former MGP facility sites through customer rates. While BGE and DPL do not have riders for MGP clean-up costs, they have historically received recovery of actual clean-up costs in distribution rates.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 1512 — Commitments and Contingencies
As of SeptemberJune 30, 20212022 and December 31, 2020,2021, the Registrants had accrued the following undiscounted amounts for environmental liabilities in Accrued expenses, Other current liabilities, and Other deferred credits and other liabilities in their respective Consolidated Balance Sheets:
| | | | | | | | | | | | | | | | | | | | | | | |
| September 30, 2021 | | December 31, 2020 |
| Total environmental
investigation and
remediation liabilities | | Portion of total related to
MGP investigation and
remediation | | Total environmental
investigation and
remediation liabilities | | Portion of total related to
MGP investigation and
remediation |
| Exelon | $ | 474 | | | $ | 310 | | | $ | 483 | | | $ | 314 | |
| Generation | 119 | | | — | | | 121 | | | — | |
| ComEd | 284 | | | 284 | | | 293 | | | 293 | |
| PECO | 23 | | | 21 | | | 23 | | | 21 | |
| BGE | 6 | | | 5 | | | 2 | | | — | |
| PHI | 42 | | | — | | | 44 | | | — | |
| Pepco | 40 | | | — | | | 42 | | | — | |
| DPL | 1 | | | — | | | 1 | | | — | |
| ACE | 1 | | | — | | | 1 | | | — | |
Cotter Corporation (Exelon and Generation). The EPA has advised Cotter Corporation (Cotter), a former ComEd subsidiary, that it is potentially liable in connection with radiological contamination at a site known as the West Lake Landfill in Missouri. In 2000, ComEd sold Cotter to an unaffiliated third-party. As part of the sale, ComEd agreed to indemnify Cotter for any liability arising in connection with the West Lake Landfill. In connection with Exelon’s 2001 corporate restructuring, this responsibility to indemnify Cotter was transferred to Generation. Including Cotter, there are three PRPs participating in the West Lake Landfill remediation proceeding. Investigation by Generation has identified a number of other parties who also may be PRPs and could be liable to contribute to the final remedy. Further investigation is ongoing.
In September 2018, the EPA issued its Record of Decision Amendment (RODA) for the selection of a final remedy. The RODA modified the remedy previously selected by EPA in its 2008 Record of Decision (ROD). While the ROD required only that the radiological materials and other wastes at the site be capped, the 2018 RODA requires partial excavation of the radiological materials in addition to the previously selected capping remedy. The RODA also allows for variation in depths of excavation depending on radiological concentrations. The EPA and the PRPs have entered into a Consent Agreement to perform the Remedial Design, which is expected to be completed in late 2024. In March 2019 the PRPs received Special Notice Letters from the EPA to perform the Remedial Action work. On October 8, 2019, Cotter (Generation’s indemnitee) provided a non-binding good faith offer to conduct, or finance, a portion of the remedy, subject to certain conditions. The total estimated cost of the remedy, taking into account the current EPA technical requirements and the total costs expected to be incurred collectively by the PRPs in fully executing the remedy, is approximately $290 million, including cost escalation on an undiscounted basis, which would be allocated among the final group of PRPs. Generation has determined that a loss associated with the EPA’s partial excavation and enhanced landfill cover remedy is probable and has recorded a liability included in the table above, that reflects management’s best estimate of Cotter’s allocable share of the ultimate cost. Given the joint and several nature of this liability, the magnitude of Generation’s ultimate liability will depend on the actual costs incurred to implement the required remedy as well as on the nature and terms of any cost-sharing arrangements with the final group of PRPs. Therefore, it is reasonably possible that the ultimate cost and Cotter's associated allocable share could differ significantly once these uncertainties are resolved, which could have a material impact in Exelon's and Generation's future financial statements.
One of the other PRPs has indicated it will be making a contribution claim against Cotter for costs that it has incurred to prevent a subsurface fire from spreading to those areas of the West Lake Landfill where radiological materials are believed to have been disposed. At this time, Exelon and Generation do not possess sufficient information to assess this claim and therefore are unable to estimate a range of loss, if any. As such, no liability has been recorded for the potential contribution claim. It is reasonably possible, however, that resolution of this matter could have a material, unfavorable impact in Exelon’s and Generation's financial statements.
In January 2018, the PRPs were advised by the EPA that it will begin an additional investigation and evaluation of groundwater conditions at the West Lake Landfill. In September 2018, the PRPs agreed to an Administrative
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)
Note 15 — Commitments and Contingencies
Settlement Agreement and Order on Consent for the performance by the PRPs of the groundwater Remedial Investigation and Feasibility Study (RI/FS). The purpose of this RI/FS is to define the nature and extent of any groundwater contamination from the West Lake Landfill site and evaluate remedial alternatives. Generation estimates the undiscounted cost for the groundwater RI/FS to be approximately $40 million. Generation determined a loss associated with the RI/FS is probable and has recorded a liability included in the table above that reflects management’s best estimate of Cotter’s allocable share of the cost among the PRPs. At this time Generation cannot predict the likelihood or the extent to which, if any, remediation activities may be required and therefore cannot estimate a reasonably possible range of loss for response costs beyond those associated with the RI/FS component. It is reasonably possible, however, that resolution of this matter could have a material, unfavorable impact in Exelon’s and Generation’s future financial statements.
In August 2011, Cotter was notified by the DOJ that Cotter is considered a PRP with respect to the government’s clean-up costs for contamination attributable to low level radioactive residues at a former storage and reprocessing facility named Latty Avenue near St. Louis, Missouri. The Latty Avenue site is included in ComEd’s (now Generation's) indemnification responsibilities discussed above as part of the sale of Cotter. The radioactive residues had been generated initially in connection with the processing of uranium ores as part of the U.S. Government’s Manhattan Project. Cotter purchased the residues in 1969 for initial processing at the Latty Avenue facility for the subsequent extraction of uranium and metals. In 1976, the NRC found that the Latty Avenue site had radiation levels exceeding NRC criteria for decontamination of land areas. Latty Avenue was investigated and remediated by the United States Army Corps of Engineers pursuant to funding under FUSRAP. Pursuant to a series of annual agreements since 2011, the DOJ and the PRPs have tolled the statute of limitations until February 28, 2022 so that settlement discussions can proceed. On August 3, 2020, the DOJ advised Cotter and the other PRPs that it is seeking approximately $90 million from all the PRPs and has directed that the PRPs must submit a good faith joint proposed settlement offer. At this time, the DOJ has stayed their request for a good faith offer while the parties review cost documentation associated with the cost claim. Generation has determined that a loss associated with this matter is probable under its indemnification agreement with Cotter and has recorded an estimated liability, which is included in the table above. | | | | | | | | | | | | | | | | | | | | | | | |
| June 30, 2022 | | December 31, 2021 |
| Total environmental
investigation and
remediation liabilities | | Portion of total related to
MGP investigation and
remediation | | Total environmental
investigation and
remediation liabilities | | Portion of total related to
MGP investigation and
remediation |
| Exelon | $ | 347 | | | $ | 299 | | | $ | 352 | | | $ | 303 | |
| ComEd | 274 | | | 273 | | | 279 | | | 279 | |
| PECO | 21 | | | 20 | | | 22 | | | 20 | |
| BGE | 7 | | | 6 | | | 6 | | | 4 | |
| PHI | 42 | | | — | | | 42 | | | — | |
| Pepco | 40 | | | — | | | 40 | | | — | |
| DPL | 1 | | | — | | | 1 | | | — | |
| ACE | 1 | | | — | | | 1 | | | — | |
Benning Road Site (Exelon, Generation, PHI, and Pepco). In September 2010, PHI received a letter from EPA identifying the Benning Road site as one of six land-based sites potentially contributing to contamination of the lower Anacostia River. A portion of the site, which is owned by Pepco, was formerly the location of aan electric generating facility owned by Pepco subsidiary, Pepco Energy Services electric(PES), which became a part of Generation, following the 2016 merger between PHI and Exelon. This generating facility which was deactivated in June 2012. The remaining portion of the site consists of a Pepco transmission and distribution service center that remains in operation. In December 2011, the U.S. District Court for the District of Columbia approved a Consent Decree entered into by Pepco and Pepco Energy Services (hereinafter "Pepco Entities") with the DOEE, which requires the Pepco and Pepco Energy ServicesEntities to conduct a RI/FSRemedial Investigation and Feasibility Study (RI/FS) for the Benning Road site and an approximately 10 to 15-acre portion of the adjacent Anacostia River. The purpose of this RI/FS is to define the nature and extent of contamination from the Benning Road site and to evaluate remedial alternatives.
SincePursuant to an internal agreement between the Pepco Entities, since 2013, Pepco has performed the work required by the Consent Decree and has been reimbursed for that work by an agreed upon allocation of costs between the Pepco Energy Services (now Generation, pursuant to Exelon's 2016 acquisition of PHI) have been performing RI work and have submitted multiple draft RI reports to the DOEE.Entities. In September 2019, the Pepco and GenerationEntities issued a draft “final” RI report which DOEE approved on February 3, 2020. The Pepco and GenerationEntities are developing a FS to evaluate possible remedial alternatives for submission to DOEE. The Court has established a schedule for completion of the FS, and approval by the DOEE, by MarchSeptember 16, 2022. After completion and approval of the FS, DOEE will prepare a Proposed Plan for public comment and then issue a RODRecord of Decision (ROD) identifying any further response actions determined to be necessary. As part of the separation between Exelon and Constellation in February 2022, the internal agreement between the Pepco Entities for completion and payment for the remaining Consent Decree work was memorialized in a formal agreement for post-separation activities. A second post-separation assumption agreement between Exelon and Constellation transferred any of the potential remaining remediation liability, if any, of PES/Generation to a non-utility subsidiary of Exelon which going forward will be responsible for those liabilities. Exelon, PHI, Pepco, and GenerationPepco have determined that a loss associated with this matter is probable and have accrued an estimated liability, which is included in the table above.
Anacostia River Tidal Reach (Exelon, PHI, and Pepco). Contemporaneous with the Benning Road site RI/FS, being performed by the Pepco and Generation,Entities, DOEE and NPSNational Park Service (NPS) have been conducting a separate RI/FS focused on the entire tidal reach of the Anacostia River extending from just north of the Maryland-District of Columbia boundary line to the confluence of the Anacostia and Potomac Rivers. The river-wide RI incorporated the results of the river sampling performed by the Pepco and Pepco Energy ServicesEntities as part of the Benning RI/FS, as well as similar sampling efforts conducted by owners of other sites adjacent to this segment of the river and supplemental river sampling conducted by DOEE’s contractor. In April 2018, DOEE released a draft RI report for public review and comment. Pepco submitted written comments to the draft RI and participated in a public hearing.
Pepco has determined that it is probable that costs for remediation will be incurred and recorded a liability in the third quarter 2019 for management’s best estimate of its share of those costs. On September 30, 2020, DOEE
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)
Note 15 — Commitments and Contingencies
released its Interim ROD. The Interim ROD reflects an adaptive management approach which will require several identified “hot spots” in the river to be addressed first while continuing to conduct studies and to monitor the river to evaluate improvements and determine potential future remediation plans. The adaptive management process chosen by DOEE is less intrusive, provides more long-term
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 12 — Commitments and Contingencies
environmental certainty, is less costly, and allows for site specific remediation plans already underway, including the plan for the Benning Road site to proceed to conclusion.
On July 15, 2022, Pepco received a letter from the District of Columbia's Office of the Attorney General (District) on behalf of DOEE conveying a settlement offer to resolve all PRPs' liability to the District. Pepco responded on July 27, 2022 to enter into settlement discussions. Exelon, PHI, and Pepco have determined that it is probable that costs for remediation will be incurred and have accrued a liability for management's best estimate of its share of the costs. Pepco concluded that incremental exposure remains reasonably possible, but management cannot reasonably estimate a range of loss beyond the amounts recorded, which are included in the table above.
On July 12, 2021, DOEE and NPS held a virtual meeting with the PRP's in response to a General Notice Letter sent by each agency inviting the PRP's to participate in discussions, which PEPCO attended.
In addition to the activities associated with the remedial process outlined above, CERCLA separately requires federal and state (here including Washington, D.C.) Natural Resource Trustees (federal or state agencies designated by the President or the relevant state, respectively, or Indian tribes) to conduct an assessment of any damages to natural resources within their jurisdiction as a result of the contamination that is being remediated. The Trustees can seek compensation from responsible parties for such damages, including restoration costs. During the second quarter of 2018, Pepco became aware that the Trustees are in the beginning stages of a Natural Resources Damages (NRD) assessment, a process that often takes many years beyond the remedial decision to complete. Pepco has entered into negotiations with the Trustees to evaluate possible incorporation of NRD assessment and restoration as part of its remedial activities associated with the Benning site to accelerate the NRD benefits for that portion of the Anacostia River Sediment Project ("ARSP") assessment. Pepco has concluded that a loss associated with the eventual NRD assessment is reasonably possible. Due to the very early stage of the assessment process, Pepco cannot reasonably estimate the final range of loss.loss potentially resulting from this process.
As noted in the Benning Road Site disclosure above, as part of the separation of Exelon and Constellation in February 2022, an assumption agreement was executed transferring any potential future remediation liabilities associated with the Benning Site remediation to a non-utility subsidiary of Exelon. Similarly, any potential future liability associated with the ARSP was also assumed by this entity.
Litigation and Regulatory Matters
Asbestos Personal Injury Claims (Exelon and Generation). Generation maintains a reserve for claims associated with asbestos-related personal injury actions in certain facilities that are currently owned by Generation or were previously owned by ComEd and PECO. The estimated liabilities are recorded on an undiscounted basis and exclude the estimated legal costs associated with handling these matters, which could be material.
At September 30, 2021 and December 31, 2020, Exelon and Generation had recorded estimated liabilities of approximately $82 million and $89 million, respectively, in total for asbestos-related bodily injury claims. As of September 30, 2021, approximately $19 million of this amount related to 211 open claims presented to Generation, while the remaining $63 million is for estimated future asbestos-related bodily injury claims anticipated to arise through 2055, based on actuarial assumptions and analyses, which are updated on an annual basis. On a quarterly basis, Generation monitors actual experience against the number of forecasted claims to be received and expected claim payments and evaluates whether adjustments to the estimated liabilities are necessary.
It is reasonably possible that additional exposure to estimated future asbestos-related bodily injury claims in excess of the amount accrued could have a material, unfavorable impact in Exelon’s and Generation’s financial statements. However, management cannot reasonably estimate a range of loss beyond the amounts recorded.
Deferred Prosecution Agreement (DPA) and Related Matters (Exelon and ComEd). Exelon and ComEd received a grand jury subpoena in the second quarter of 2019 from the U.S. Attorney’s Office for the Northern District of Illinois (USAO) requiring production of information concerning their lobbying activities in the State of Illinois. On October 4, 2019, Exelon and ComEd received a second grand jury subpoena from the USAO requiring production of records of any communications with certain individuals and entities. On October 22, 2019, the SEC notified Exelon and ComEd that it had also opened an investigation into their lobbying activities. On July 17, 2020, ComEd entered into a DPA with the USAO to resolve the USAO investigation. Under the DPA, the USAO filed a single charge alleging that ComEd improperly gave and offered to give jobs, vendor subcontracts, and payments associated with those jobs and subcontracts for the benefit of the Speaker of the Illinois House of Representatives and the Speaker’s associates, with the intent to influence the Speaker’s action regarding legislation affecting ComEd’s interests. The DPA provides that the USAO will defer any prosecution of such charge and any other criminal or civil case against ComEd in connection with the matters identified therein for a three-year period subject to certain obligations of ComEd, including payment to the U.S. Treasury of $200 million, which was paid in November 2020. Exelon was not made a party to the DPA, and therefore the investigation by the USAO into Exelon’s activities ended with no charges being brought against Exelon. The SEC’s investigation remains ongoing and Exelon and ComEd have cooperated fully and intend to continue to cooperate fully with the
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)
Note 15 — Commitments and Contingencies
SEC. Exelon and ComEd cannot predict the outcome of the SEC investigation. No loss contingency has been reflected in Exelon's and ComEd's consolidated financial statements with respect to the SEC investigation, as this contingency is neither probable nor reasonably estimable at this time.
Subsequent to Exelon announcing the receipt of the subpoenas, various lawsuits were filed, and various demand letters were received related to the subject of the subpoenas, the conduct described in the DPA and the SEC's investigation, including:
•Four putative class action lawsuits against ComEd and Exelon were filed in federal court on behalf of ComEd customers in the third quarter of 2020 alleging, among other things, civil violations of federal racketeering laws. In addition, the Citizens Utility Board (CUB) filed a motion to intervene in these cases on October 22, 2020 which was granted on December 23, 2020. On December 2, 2020, the court
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 12 — Commitments and Contingencies
appointed interim lead plaintiffs in the federal cases which consisted of counsel for three of the four federal cases. These plaintiffs filed a consolidated complaint on January 5, 2021. CUB also filed its own complaint against ComEd only on the same day. The remaining federal case, Potter, et al. v. Exelon et al, differed from the other lawsuits as it named additional individual defendants not named in the consolidated complaint. However, the Potter plaintiffs voluntarily dismissed their complaint without prejudice on April 5, 2021. ComEd and Exelon moved to dismiss the consolidated class action complaint and CUB’s complaint on February 4, 2021 and briefing was completed on March 22, 2021. On March 25, 2021, the parties agreed, along with state court plaintiffs, discussed below, to jointly engage in mediation. The parties participated in a one-day mediation on June 7, 2021 but no settlement was reached. On September 9, 2021, the federal court granted Exelon’s and ComEd’s motion to dismiss and dismissed the plaintiffs’ and CUB’s federal law claim with prejudice. The federal court also dismissed the related state law claims made by the federal plaintiffs and CUB on jurisdictional grounds. Plaintiffs have appealed dismissal of the rulingfederal law claim to the Seventh Circuit Court of Appeals. Plaintiffs' opening appeal brief is due January 14, 2022, Exelon'sPlaintiffs and ComEd's response brief is due February 14, 2022, and Plaintiffs' reply brief is due March 7, 2022. PlaintiffsCUB also refiled their state law claims in state court and have moved to consolidate that actionthem with the already pending consumer state court class action, discussed below. CUB also refiled its state law claimsPlaintiffs' opening appeal brief in state court.the Seventh Circuit was filed on January 14, 2022. Exelon and ComEd filed their response brief on March 7, 2022, and plaintiffs filed their reply brief on April 6, 2022. Oral argument was held on May 17, 2022.
•Three putative class action lawsuits against ComEd and Exelon were filed in Illinois state court in the third quarter of 2020 seeking restitution and compensatory damages on behalf of ComEd customers. The cases were consolidated into a single action in October of 2020. In November 2020, CUB filed a motion to intervene in the cases pursuant to an Illinois statute allowing CUB to intervene as a party or otherwise participate on behalf of utility consumers in any proceeding which affects the interest of utility consumers. On November 23, 2020, the court allowed CUB’s intervention, but denied itsCUB's request to stay these cases. Plaintiffs subsequently filed a consolidated complaint, and ComEd and Exelon filed a motion to dismiss on jurisdictional and substantive grounds on January 11, 2021. Briefing on that motion was completed on March 2, 2021. The parties agreed, on March 25, 2021, along with the federal court, plaintiffs discussed above, to jointly engage in mediation. The parties participated in a one-day mediation on June 7, 2021 but no settlement was reached. Oral argument onOn December 23, 2021, the state court pendinggranted ComEd and Exelon's motion to dismiss was heldwith prejudice. On December 30, 2021, plaintiffs filed a motion to reconsider that dismissal and for permission to amend their complaint. The court denied the plaintiffs' motion on August 4, 2021.January 21, 2022. Plaintiffs have appealed the court's ruling dismissing their complaint to the First District Court of Appeals. On September 27, 2021,February 15, 2022, Exelon and ComEd moved to dismiss the court set a tentative ruling datefederal plaintiffs' refiled state law claims, seeking dismissal on the same legal grounds asserted in their motion to dismiss for November 30, 2021. It is unclear at this time what impact the recent filings byoriginal state court plaintiffs' complaint. The court granted dismissal of the refiled state claims on February 16, 2022. The original federal court plaintiffs and CUB will haveappealed that dismissal on this action and the pending motion to dismiss.February 18, 2022. The two state appeals were consolidated on March 21, 2022. Plaintiffs' opening appellate briefs are currently due August 5, 2022.
•A putative class action lawsuit against Exelon and certain officers of Exelon and ComEd was filed in federal court in December 2019 alleging misrepresentations and omissions in Exelon’s SEC filings related to ComEd’s lobbying activities and the related investigations. The complaint was amended on September 16, 2020, to dismiss two of the original defendants and add other defendants, including ComEd. Defendants filed a motion to dismiss in November 2020. The court denied the motion in April 2021. On May 26, 2021, defendants moved the court to certify its order denying the motion to dismiss for interlocutory appeal. Briefing on the motion was completed in June 2021 and the2021. That motion remains pending. Litigation has proceeded and inwas denied on January 28, 2022. In May 2021, the parties each filed respective initial discovery disclosures. On June 9, 2021, defendants filed their answer and affirmative defenses to the complaint. Thecomplaint and the parties are currently engaged thereafter in discovery; however, ondiscovery. On September 9, 2021, the U.S. government moved to intervene in thisthe lawsuit and stay discovery relating to the U.S. government’s ongoing criminal proceedings until the parties entered into an amendment to their protective order that would prohibit the parties from requesting discovery into certain matters, including communications with the U.S. government. The court ordered said amendment to the litigation agreeprotective order on November 15, 2021 and discovery resumed. On February 10, 2022, the court granted an extension of the amendment to an acceptablethe protective order.order, at the U.S. government's request. The court granted a further extension of the amendment to the protective order and narrowed its scope, at the U.S. government’s motiongovernment's request, on May 14, 2022. On July 14, 2022, the court further extended the protective order amendment to September 23, 202130, 2022 and discovery remains stayed until further order ofreset the court.next court status for August 15, 2022.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 1512 — Commitments and Contingencies
•FiveSeveral shareholders have sent letters to the Exelon Board of Directors betweenfrom 2020 and 2021through May 2022 demanding, among other things, that the Exelon Board of Directors investigate and address alleged breaches of fiduciary duties and other alleged violations by Exelon and ComEd officers and directors related to the conduct described in the DPA. In the first quarter of 2021, the Exelon Board of Directors appointed a Special Litigation Committee (“SLC”)(SLC) consisting of disinterested and independent parties to investigate and address these shareholders’ allegations and make recommendations to the Exelon Board of Directors based on the outcome of the SLC’s investigation. In July 2021, one of the demand letter shareholders filed a derivative action against current and former Exelon and ComEd officers and directors, and against Exelon, as nominal defendant, asserting the same claims made in its demand letter. On October 12, 2021, the parties to the derivative action filed an agreed motion to stay that litigation for 120 days in order to allow the SLC to continue its investigation, which the court granted. The parties will confer in advanceOn February 3, 2022, the court granted an extension of the 120-day deadlinestay for another 120 days and directed the parties to determine whetherfile a status report on June 1, 2022. On June 1, 2022, the parties requested a further extension of the stay should be extended.until September 14, 2022, which the court granted.
•ATwo separate shareholder demandrequests seeking a review of certain Exelon books and records waswere received in August 2021.2021 and January 2022. Exelon is inresponded to both requests and both shareholders have since sent formal shareholder demands to the process of responding to this demand.Exelon Board, as discussed above.
No loss contingencies have been reflected in Exelon’s and ComEd’s consolidated financial statements with respect to these matters, as such contingencies are neither probable nor reasonably estimable at this time.
OnThe ICC continues to conduct an investigation into rate impacts of conduct admitted in the DPA initiated on August 12, 2021. On December 16, 2021, ComEd filed direct testimony addressing the ICC commenced a proceeding, under its general regulatory authority,costs recovered from customers related to investigate whetherthe DPA and Exelon's funding of the fine paid by ComEd. In that testimony, ComEd proposed to voluntarily refund to customers compensation costs of the former officers charged with wrongdoing in connection with events described in the DPA for the period during which those events occurred as well as costs, previously proposed to be returned, of individuals and entities specifically identified in the DPA, as well as individuals and entities who were referred to ComEd as part of the conduct described in the DPA resultedand who failed, during their tenure at ComEd, to perform work to management expectations. The testimony supports the calculation of the refund amount and proposes a refund mechanism (one-time bill credit in ComEd’s recovery, through rates, of costs that were not properly recoverable under lawApril 2023) and if so, what remedial action should be taken. The Staff Report citedalso addresses other topics outlined by statute and the ICC orders initiating the investigation. On April 14, 2022, in its initiating order expressed “concerns” about whether ComEd improperly recovered DPA-related costsresponse to rebuttal testimony from customers. TheICC staff and the Illinois Attorney General, City of Chicago, and CUB, have intervenedComEd filed surrebuttal testimony, in which ComEd proposed to increase its voluntary customer refund to $38 million, including ICC and FERC jurisdictional amounts and estimated interest, to resolve the issue of the potential expenditure of customer monies on activities identified in the proceeding. CounselDPA in this matter. An accrual for plaintiffsthe amount of the voluntary customer refund has been recorded in Other current liabilities and Other deferred credits and other liabilities in Exelon’s and ComEd’s Consolidated Balance Sheets as of June 30, 2022. The voluntary customer refund will not be recovered in rates or charged to customers and ComEd will not seek or accept reimbursement or indemnification from any source other than Exelon. The evidentiary hearing on the remaining contested issue was held on April 28, 2022. On June 13, 2022, the ICC Administrate Law Judge issued a proposed order, which accepts ComEd's voluntary customer refund of $38 million and rejects alternative proposals for other larger adjustments to rates. A final order is expected by September 9, 2022.
Savings Plan Claim (Exelon). On December 6, 2021, seven current and former employees filed a putative ERISA class action suit in U.S. District Court for the Northern District of Illinois against Exelon, its Board of Directors, the former Board Investment Oversight Committee, the Corporate Investment Committee, individual defendants, and other unnamed fiduciaries of the Exelon Corporation Employee Savings Plan (Plan). The complaint alleges that the defendants violated their fiduciary duties under the Plan by including certain investment options that allegedly were more expensive than and underperformed similar passively-managed or other funds available in the putative consumer class actions pending in Illinois Circuit Court have also soughtmarketplace and permitting a third-party administrative service provider/recordkeeper and an investment adviser to “partially” intervene, which request is pending. On October 14, 2021, as required by provisions ofcharge excessive fees for the Clean Energy Law, the ICC initiated a separate docket to investigate the rate treatment of costs associated with the DPA, including the fine paid by ComEd,services provided. The plaintiffs seek declaratory, equitable and whether ComEd “collected, spent, allocated, transferred, remitted, or caused in any other way to be expended ratepayer funds that were not lawfully recoverable through rates, and which should accordingly be refunded to ratepayers ….” That proceeding must be completed within 330 days. On October 19, 2021, the ICC moved to consolidate these two proceedings because they address "similar issues and facts." That motion is pending. No schedule has been set for submission of testimony or for an evidentiary hearing in either docket. A status hearing is set in both matters for November 4, 2021. Exelon and ComEd cannot predict the outcome of these proceedings.
Impacts of the February 2021 Extreme Cold Weather Event and Texas-based Generating Assets Outages (Exelon and Generation). Beginning on February 15, 2021, Generation’s Texas-based generating assets within the ERCOT market, specifically Colorado Bend II, Wolf Hollow II, and Handley, experienced outages as a result of extreme cold weather conditions. In addition, those weather conditions drove increased demand for service, dramatically increased wholesale power prices, and also increased gas prices in certain regions. See Note 3 — Regulatory Matters for additional information.
Various lawsuits have been filed against Generation since March 2021 related to these events, including:
•On March 5, 2021, Generation, along with more than 160 power generators and transmission and distribution companies, was sued by approximately 160 individually named plaintiffs, purportedlymonetary relief on behalf of all Texans who allegedly suffered loss of life or sustained personal injury, property damage or other losses as a resultthe Plan and participants. On February 16, 2022, the court granted the parties' stipulated dismissal of the weather events.individual named defendants without prejudice. The remaining defendants filed a motion to dismiss the complaint on February 25, 2022. The plaintiffs allege thatfiled their response brief on March 28, 2022 and the defendants failed to properly prepare forfiled their reply on April 11, 2022. On March 4, 2022, the cold weather and failed to properly conduct their operations, seeking compensatory as well as punitive damages. On April 26, 2021, another multi-plaintiff lawsuit wasChamber of Commerce filed on behalfa brief of approximately 90 plaintiffs against more than 300 defendants, including Generation, involving similar allegations of liability and claims of personal injury and property damage. Since March 2021, approximately 60 additional lawsuits, naming multiple defendants including Generation, were filed by individual or multiple plaintiffsamicus curiae in different Texas counties, all arising outsupport of the February weather events. These additional lawsuits allege wrongful death, property damage, or other losses. Co-defendants in these lawsuits include ERCOT, transmission and distribution utilities and other generators. Generation disputes liability and denies that it is responsible for any of plaintiffs’ alleged claims and is vigorously contesting them.defendants' motion to dismiss. No loss contingencies have been reflected in Exelon’s and Generation’s consolidated financial statements with respect to this matter, as such contingencies are neither probable nor reasonably estimable at this time.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 1512 — Commitments and Contingencies
financial statements with respect to these matters, as such contingencies are neither probable nor reasonably estimable at this time.
•On March 22, 2021, an LDC filed a lawsuit in Missouri federal court against Generation for breach of contract and unjust enrichment, seeking damages of approximately $40 million. The plaintiff claims that Generation failed to deliver gas to its customers in February of 2021, causing the plaintiff to incur damages by forcing it to purchase gas for Generation’s customers and by Generation’s refusal to pay the resulting penalties. On March 26, 2021, Generation filed a complaint with the MPSC against the LDC to void the OFO penalties, or alternatively to grant a waiver or variance from the tariff requirements, to prohibit the LDC from billing or otherwise attempting to collect from Generation or any Missouri customer any portion of the penalties claimed by the LDC until the resolution of the complaint, and to prohibit the LDC from taking any retaliatory measure, including termination of service. On September 1, 2021, the MPSC consolidated Generation’s complaint with two other similar complaints from other companies. The evidentiary hearing for the three consolidated complaint cases is scheduled for March 2022. Based on the penalty provisions within the tariff that was in effect at the relevant time, Exelon and Generation have recorded a liability of approximately $40 million as of September 30, 2021.
General (All Registrants).The Registrants are involved in various other litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. The Registrants maintain accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of reasonably possible loss, particularly where (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.
16.13. Changes in Accumulated Other Comprehensive Income (Exelon)
The following tables present changes in Exelon's AOCI, net of tax, by component:
| | Three Months Ended September 30, 2021 | Losses on Cash Flow Hedges | | Pension and Non-Pension Postretirement Benefit Plan Items(a) | | Foreign
Currency
Items | | | Total | |
| Beginning balance | $ | (5) | | | $ | (3,264) | | | $ | (20) | | | | $ | (3,289) | | |
| Three Months Ended June 30, 2022 | | Three Months Ended June 30, 2022 | Cash Flow Hedges | | Pension and Non-Pension Postretirement Benefit Plan Items(a) | | Foreign
Currency
Items | | | Total |
| Balance at March 31, 2022 | | Balance at March 31, 2022 | $ | — | | | $ | (713) | | | $ | — | | | | $ | (713) | |
| OCI before reclassifications | OCI before reclassifications | — | | | 14 | | | (3) | | | | 11 | | OCI before reclassifications | — | | | 2 | | | — | | | | 2 | |
| Amounts reclassified from AOCI | Amounts reclassified from AOCI | — | | | 55 | | | — | | | | 55 | | Amounts reclassified from AOCI | — | | | 10 | | | — | | | | 10 | |
| Net current-period OCI | Net current-period OCI | — | | | 69 | | | (3) | | | | 66 | | Net current-period OCI | — | | | 12 | | | — | | | | 12 | |
| Ending balance | $ | (5) | | | $ | (3,195) | | | $ | (23) | | | | $ | (3,223) | | |
| Balance at June 30, 2022 | | Balance at June 30, 2022 | $ | — | | | $ | (701) | | | $ | — | | | | $ | (701) | |
| | Three Months Ended September 30, 2020 | Losses on Cash Flow Hedges | | Pension and Non-Pension Postretirement Benefit Plan Items(a) | | Foreign
Currency
Items | | | Total | |
| Beginning balance | $ | (3) | | | $ | (3,096) | | | $ | (33) | | | | $ | (3,132) | | |
| Three Months Ended June 30, 2021 | | Three Months Ended June 30, 2021 | Cash Flow Hedges | | Pension and Non-Pension Postretirement Benefit Plan Items(a) | | Foreign
Currency
Items | | | Total |
| Balance at March 31, 2021 | | Balance at March 31, 2021 | $ | (5) | | | $ | (3,319) | | | $ | (22) | | | | $ | (3,346) | |
| OCI before reclassifications | OCI before reclassifications | (1) | | | (13) | | | 3 | | | | (11) | | OCI before reclassifications | — | | | — | | | 2 | | | | 2 | |
| Amounts reclassified from AOCI | Amounts reclassified from AOCI | — | | | 39 | | | — | | | | 39 | | Amounts reclassified from AOCI | — | | | 55 | | | — | | | | 55 | |
| Net current-period OCI | Net current-period OCI | (1) | | | 26 | | | 3 | | | | 28 | | Net current-period OCI | — | | | 55 | | | 2 | | | | 57 | |
| Ending balance | $ | (4) | | | $ | (3,070) | | | $ | (30) | | | | $ | (3,104) | | |
| Balance at June 30, 2021 | | Balance at June 30, 2021 | $ | (5) | | | $ | (3,264) | | | $ | (20) | | | | $ | (3,289) | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Six Months Ended June 30, 2022 | Cash Flow Hedges | | Pension and Non-Pension Postretirement Benefit Plan Items(a) | | Foreign
Currency
Items | | | | Total |
| Balance at December 31, 2021 | $ | (6) | | | $ | (2,721) | | | $ | (23) | | | | | $ | (2,750) | |
| Separation of Constellation | 6 | | | 1,994 | | | 23 | | | | | 2,023 | |
| OCI before reclassifications | — | | | 2 | | | — | | | | | 2 | |
| Amounts reclassified from AOCI | — | | | 24 | | | — | | | | | 24 | |
| Net current-period OCI | — | | | 26 | | | — | | | | | 26 | |
| Balance at June 30, 2022 | $ | — | | | $ | (701) | | | $ | — | | | | | $ | (701) | |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 1613 — Changes in Accumulated Other Comprehensive Income
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2021 | Losses on Cash Flow Hedges | | Pension and Non-Pension Postretirement Benefit Plan Items(a) | | Foreign
Currency
Items | | | | Total |
| Beginning balance | $ | (5) | | | $ | (3,372) | | | $ | (23) | | | | | $ | (3,400) | |
| OCI before reclassifications | (1) | | | 15 | | | — | | | | | 14 | |
| Amounts reclassified from AOCI | — | | | 163 | | | — | | | | | 163 | |
| Net current-period OCI | (1) | | | 178 | | | — | | | | | 177 | |
| Ending balance | $ | (6) | | | $ | (3,194) | | | $ | (23) | | | | | $ | (3,223) | |
| | Nine Months Ended September 30, 2020 | Losses on Cash Flow Hedges | | Pension and Non-Pension Postretirement Benefit Plan Items(a) | | Foreign
Currency
Items | | | Total | |
| Beginning balance | $ | (2) | | | $ | (3,165) | | | $ | (27) | | | | $ | (3,194) | | |
| Six Months Ended June 30, 2021 | | Six Months Ended June 30, 2021 | Cash Flow Hedges | | Pension and Non-Pension Postretirement Benefit Plan Items(a) | | Foreign
Currency
Items | | | Total |
| Balance at December 31, 2020 | | Balance at December 31, 2020 | $ | (5) | | | $ | (3,372) | | | $ | (23) | | | | $ | (3,400) | |
| OCI before reclassifications | OCI before reclassifications | (2) | | | (17) | | | (3) | | | | (22) | | OCI before reclassifications | — | | | (2) | | | 3 | | | | 1 | |
| Amounts reclassified from AOCI | Amounts reclassified from AOCI | — | | | 112 | | | — | | | | 112 | | Amounts reclassified from AOCI | — | | | 110 | | | — | | | | 110 | |
| Net current-period OCI | Net current-period OCI | (2) | | | 95 | | | (3) | | | | 90 | | Net current-period OCI | — | | | 108 | | | 3 | | | | 111 | |
| Ending balance | $ | (4) | | | $ | (3,070) | | | $ | (30) | | | | $ | (3,104) | | |
| Balance at June 30, 2021 | | Balance at June 30, 2021 | $ | (5) | | | $ | (3,264) | | | $ | (20) | | | | $ | (3,289) | |
________________(a)This AOCI amounts arecomponent is included in the computation of net periodic pension and OPEB cost. Additionally, as of February 1, 2022, in connection with the separation, Exelon's pension and OPEB plans were remeasured. See Note 118 — Retirement Benefits for additional information. See Exelon's Statements of Operations and Comprehensive Income for individual components of AOCI.
The following table presents income tax benefit (expense) allocated to each component of Exelon's other comprehensive income (loss):
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, | | |
| 2021 | | 2020 | | 2021 | | 2020 | | | | |
| Pension and non-pension postretirement benefit plans: | | | | | | | | | | | |
| Prior service benefit reclassified to periodic benefit cost | $ | 1 | | | $ | 4 | | | $ | 3 | | | $ | 12 | | | | | |
| Actuarial loss reclassified to periodic benefit cost | (19) | | | (16) | | | (57) | | | (50) | | | | | |
| Pension and non-pension postretirement benefit plans valuation adjustment | (7) | | | 3 | | | (8) | | | 6 | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended June 30, | | Six Months Ended June 30, | | |
| 2022 | | 2021 | | 2022 | | 2021 | | | | |
| Pension and non-pension postretirement benefit plans: | | | | | | | | | | | |
| Prior service benefit reclassified to periodic benefit cost | $ | — | | | $ | 1 | | | $ | — | | | $ | 2 | | | | | |
| Actuarial loss reclassified to periodic benefit cost | (3) | | | (19) | | | (8) | | | (38) | | | | | |
| Pension and non-pension postretirement benefit plans valuation adjustment | (1) | | | (1) | | | — | | | (1) | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
17. Variable Interest Entities (Exelon, Generation, PHI, and ACE)
At September 30, 2021 and December 31, 2020, Exelon, Generation, PHI, and ACE collectively consolidated several VIEs or VIE groups for which the applicable Registrant was the primary beneficiary (see Consolidated VIEs below) and had significant interests in several other VIEs for which the applicable Registrant does not have the power to direct the entities’ activities and, accordingly, was not the primary beneficiary (see Unconsolidated VIEs below). Consolidated and unconsolidated VIEs are aggregated to the extent that the entities have similar risk profiles.
Consolidated VIEs
The table below shows the carrying amounts and classification of the consolidated VIEs’ assets and liabilities included in the consolidated financial statements of Exelon, Generation, PHI, and ACE as of September 30, 2021 and December 31, 2020. The assets, except as noted in the footnotes to the table below, can only be used to settle obligations of the VIEs. The liabilities, except as noted in the footnote to the table below, are such that creditors, or beneficiaries, do not have recourse to the general credit of Exelon, Generation, PHI, and ACE.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)
Note 17 — Variable Interest Entities
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| September 30, 2021 | | December 31, 2020 |
| Exelon | | Generation | | PHI(a) | | ACE | | Exelon | | Generation | | PHI(a) | | ACE |
| Cash and cash equivalents | $ | 38 | | | $ | 38 | | | $ | — | | | $ | — | | | $ | 98 | | | $ | 98 | | | $ | — | | | $ | — | |
| Restricted cash and cash equivalents | 47 | | | 42 | | | 5 | | | 5 | | | 47 | | | 44 | | | 3 | | | 3 | |
| Accounts receivable | | | | | | | | | | | | | | | |
| Customer | 25 | | | 25 | | | — | | | — | | | 148 | | | 148 | | | — | | | — | |
| Other | 7 | | | 7 | | | — | | | — | | | 36 | | | 36 | | | — | | | — | |
| Unamortized energy contract assets | 21 | | | 21 | | | — | | | — | | | 22 | | | 22 | | | — | | | — | |
| Inventories, net | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Materials and supplies | 14 | | | 14 | | | — | | | — | | | 244 | | | 244 | | | — | | | — | |
Assets held for sale(b) | — | | | — | | | — | | | — | | | 101 | | | 101 | | | — | | | — | |
| Other current assets | 517 | | | 513 | | | 4 | | | — | | | 674 | | | 669 | | | 5 | | | — | |
| Total current assets | 669 | | | 660 | | | 9 | | | 5 | | | 1,370 | | | 1,362 | | | 8 | | | 3 | |
| Property, plant, and equipment, net | 2,052 | | | 2,052 | | | — | | | — | | | 5,803 | | | 5,803 | | | — | | | — | |
| Nuclear decommissioning trust funds | — | | | — | | | — | | | — | | | 3,007 | | | 3,007 | | | — | | | — | |
| | | | | | | | | | | | | | | |
| Unamortized energy contract assets | 210 | | | 210 | | | — | | | — | | | 249 | | | 249 | | | — | | | — | |
| Other noncurrent assets | 22 | | | 13 | | | 9 | | | 9 | | | 52 | | | 42 | | | 10 | | | 10 | |
| Total noncurrent assets | 2,284 | | | 2,275 | | | 9 | | | 9 | | | 9,111 | | | 9,101 | | | 10 | | | 10 | |
Total assets(c) | $ | 2,953 | | | $ | 2,935 | | | $ | 18 | | | $ | 14 | | | $ | 10,481 | | | $ | 10,463 | | | $ | 18 | | | $ | 13 | |
| Long-term debt due within one year | $ | 80 | | | $ | 70 | | | $ | 10 | | | $ | 6 | | | $ | 94 | | | $ | 68 | | | $ | 26 | | | $ | 21 | |
| Accounts payable | 11 | | | 11 | | | — | | | — | | | 81 | | | 81 | | | — | | | — | |
| Accrued expenses | 14 | | | 14 | | | — | | | — | | | 70 | | | 70 | | | — | | | — | |
| | | | | | | | | | | | | | | |
| Unamortized energy contract liabilities | — | | | — | | | — | | | — | | | 4 | | | 4 | | | — | | | — | |
Liabilities held for sale(b) | — | | | — | | | — | | | — | | | 16 | | | 16 | | | — | | | — | |
| Other current liabilities | — | | | — | | | — | | | — | | | 5 | | | 5 | | | — | | | — | |
| Total current liabilities | 105 | | | 95 | | | 10 | | | 6 | | | 270 | | | 244 | | | 26 | | | 21 | |
| Long-term debt | 832 | | | 832 | | | — | | | — | | | 889 | | | 889 | | | — | | | — | |
| Asset retirement obligations | 149 | | | 149 | | | — | | | — | | | 2,318 | | | 2,318 | | | — | | | — | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Other noncurrent liabilities | 3 | | | 3 | | | — | | | — | | | 129 | | | 129 | | | — | | | — | |
| Total noncurrent liabilities | 984 | | | 984 | | | — | | | — | | | 3,336 | | | 3,336 | | | — | | | — | |
Total liabilities(d) | $ | 1,089 | | | $ | 1,079 | | | $ | 10 | | | $ | 6 | | | $ | 3,606 | | | $ | 3,580 | | | $ | 26 | | | $ | 21 | |
_________
(a)Includes certain purchase accounting adjustments from the PHI merger not pushed down to ACE.
(b)In the fourth quarter of 2020, Generation entered into an agreement for the sale of a significant portion of Generation's solar business, and as a result of this transaction, Exelon and Generation reclassified the consolidated VIEs' solar assets and liabilities as held for sale. Completion of the transaction occurred in the first quarter of 2021. Refer to Note 2 — Mergers, Acquisitions, and Dispositions for additional information on the solar business.
(c)Exelon’s and Generation’s balances include unrestricted assets for current unamortized energy contract assets of $21 million and $22 million, non-current unamortized energy contract assets of $210 million and $249 million, assets held for sale of $0 millionand $9 million, and other unrestricted assets of $0 million and $1 million as of September 30, 2021 and December 31, 2020, respectively.
(d)Exelon’s and Generation’s balances include liabilities with recourse of $1 million and $8 million as of September 30, 2021 and December 31, 2020, respectively.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)
Note 17 — Variable Interest Entities
As of September 30, 2021 and December 31, 2020, Exelon's and Generation's consolidated VIEs included the following:
| | | | | | | | |
Consolidated VIE or VIE groups: | Reason entity is a VIE: | Reason Generation is primary beneficiary: |
CENG - A joint venture between Generation and EDF. Generation had a 50.01% equity ownership in CENG as of December 31, 2020 and acquired EDF's 49.99% equity interest on August 6,2021 resulting in CENG no longer being classified as a consolidated VIE beginning in the third quarter of 2021. See additional discussion below. | Disproportionate relationship between equity interest and operational control as a result of the NOSA described further below. | Generation conducts the operational activities. |
EGRP - A collection of wind and solar project entities. Generation has a 51% equity ownership in EGRP. See additional discussion below. | Similar structure to a limited partnership and the limited partners do not have kick out rights with respect to the general partner. | Generation conducts the operational activities. |
Bluestem Wind Energy Holdings, LLC - A Tax Equity structure which is consolidated by EGRP. Generation has a noncontrolling interest. | Similar structure to a limited partnership and the limited partners do not have kick out rights with respect to the general partner. | Generation conducts the operational activities. |
Antelope Valley - A solar generating facility, which is 100% owned by Generation. Antelope Valley sells all of its output to PG&E through a PPA. | The PPA contract absorbs variability through a performance guarantee. | Generation conducts all activities. |
Equity investment in distributed energy company -
Generation has a 31% equity ownership. This distributed energy company has an interest in an unconsolidated VIE. (See Unconsolidated VIEs disclosure below).
Generation fully impaired this investment in 2019.
| Similar structure to a limited partnership and the limited partners do not have kick out rights with respect to the general partner. | Generation conducts the operational activities. |
NER - A bankruptcy remote, special purpose entity which is 100% owned by Generation, which purchases certain of Generation’s customer accounts receivable arising from the sale of retail electricity.
NER’s assets will be available first and foremost to satisfy the claims of the creditors of NER. See Note 6 - Accounts Receivable for additional information on the sale of receivables.
| Equity capitalization is insufficient to support its operations.
| Generation conducts all activities.
|
CENG - On April 1, 2014, Generation, CENG, and subsidiaries of CENG executed the NOSA pursuant to which Generation conducts all activities associated with the operations of the CENG fleet and provides corporate and administrative services to CENG and the CENG fleet for the remaining life of the CENG nuclear plants as if they were a part of the Generation nuclear fleet, subject to the CENG member rights of EDF.
On November 20, 2019, Generation received notice of EDF's intention to exercise the put option to sell its 49.99% equity interest in CENG to Generation and the put automatically exercised on January 19, 2020. On August 6, 2021, Generation and EDF entered into a settlement agreement pursuant to which Generation purchased EDF's equity interest in CENG and resulted in CENG no longer being classified as a consolidated VIE beginning in the third quarter of 2021. Refer to Note 2 — Mergers, Acquisitions, and Dispositions for additional information.
Exelon and Generation, where indicated, provide the following support to CENG:
•Generation executed an Indemnity Agreement pursuant to which Generation agreed to indemnify EDF against third-party claims that may arise from any future nuclear incident (as defined in the Price-Anderson Act) in connection with the CENG nuclear plants or their operations. Exelon guarantees Generation’s obligations under this Indemnity Agreement. See Note 19 — Commitments and Contingencies of the Exelon 2020 Form 10-K for more details.
•Exelon has executed an agreement to provide up to $245 million to support the operations of CENG as well as a $165 million guarantee of CENG’s cash pooling agreement with its subsidiaries.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)
Note 17 — Variable Interest Entities
Prior to August 6, 2021, Generation and EDF shared in the $688 million of contingent payment obligations for the payment of contingent retrospective premium adjustments for the nuclear liability insurance. Following the execution of the settlement agreement, EDF no longer shares in the obligation.
EGRP - EGRP is a collection of wind and solar project entities and some of these project entities are VIEs that are consolidated by EGRP. Generation owns a number of limited liability companies that build, own, and operate solar and wind power facilities some of which are owned by EGRP. While Generation or EGRP owns 100% of the solar entities and 100% of the majority of the wind entities, it has been determined that certain of the solar and wind entities are VIEs because the entities require additional subordinated financial support in the form of a parental guarantee of debt, loans from the customers in order to obtain the necessary funds for construction of the solar facilities, or the customers absorb price variability from the entities through the fixed price power and/or REC purchase agreements. Generation is the primary beneficiary of these solar and wind entities that qualify as VIEs because Generation controls the design, construction, and operation of the facilities. There is limited recourse to Generation related to certain solar and wind entities.
In 2017, Generation’s interests in EGRP were contributed to and are pledged for the ExGen Renewables IV non-recourse debt project financing structure. Refer to Note 17 — Debt and Credit Agreements of the Exelon 2020 Form 10-K for additional information on ExGen Renewables IV.
As of September 30, 2021 and December 31, 2020, Exelon's, PHI's, and ACE's consolidated VIE consists of:
| | | | | | | | |
Consolidated VIEs: | Reason entity is a VIE: | Reason ACE is the primary beneficiary: |
ACE Funding - A special purpose entity formed by ACE for the purpose of securitizing authorized portions of ACE’s recoverable stranded costs through the issuance and sale of Transition Bonds. Proceeds from the sale of each series of Transition Bonds by ATF were transferred to ACE in exchange for the transfer by ACE to ATF of the right to collect a non-bypassable Transition Bond Charge from ACE customers pursuant to bondable stranded costs rate orders issued by the NJBPU in an amount sufficient to fund the principal and interest payments on Transition Bonds and related taxes, expenses and fees. | ACE’s equity investment is a variable interest as, by design, it absorbs any initial variability of ATF. The bondholders also have a variable interest for the investment made to purchase the Transition Bonds. | ACE controls the servicing activities. |
Unconsolidated VIEs
Exelon’s and Generation’s variable interests in unconsolidated VIEs generally include equity investments and energy purchase and sale contracts. For the equity investments, the carrying amount of the investments is reflected in Exelon’s and Generation’s Consolidated Balance Sheets in Investments. For the energy purchase and sale contracts (commercial agreements), the carrying amount of assets and liabilities in Exelon’s and Generation’s Consolidated Balance Sheets that relate to their involvement with the VIEs are predominately related to working capital accounts and generally represent the amounts owed by, or owed to, Exelon and Generation for the deliveries associated with the current billing cycles under the commercial agreements.
As of September 30, 2021 and December 31, 2020, Exelon and Generation had significant unconsolidated variable interests in several VIEs for which Exelon or Generation, as applicable, was not the primary beneficiary. These interests include certain equity method investments and certain commercial agreements.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)
Note 17 — Variable Interest Entities
The following table presents summary information about Exelon's and Generation’s significant unconsolidated VIE entities:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| September 30, 2021 | | December 31, 2020 |
| Commercial
Agreement
VIEs | | Equity
Investment
VIEs | | Total | | Commercial
Agreement
VIEs | | Equity
Investment
VIEs | | Total |
Total assets(a) | $ | 781 | | | $ | 370 | | | $ | 1,151 | | | $ | 777 | | | $ | 401 | | | $ | 1,178 | |
Total liabilities(a) | 80 | | | 209 | | | 289 | | | 61 | | | 223 | | | 284 | |
Exelon's ownership interest in VIE(a) | — | | | 143 | | | 143 | | | — | | | 157 | | | 157 | |
Other ownership interests in VIE(a) | 701 | | | 18 | | | 719 | | | 716 | | | 21 | | | 737 | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
_________
(a)These items represent amounts in the unconsolidated VIE balance sheets, not in Exelon’s or Generation’s Consolidated Balance Sheets. These items are included to provide information regarding the relative size of the unconsolidated VIEs. Exelon and Generation do not have any exposure to loss as they do not have a carrying amount in the equity investment VIEs as of September 30, 2021 and December 31, 2020.
As of September 30, 2021 and December 31, 2020, Exelon's and Generation's unconsolidated VIEs consist of:
| | | | | | | | |
Unconsolidated VIE groups: | Reason entity is a VIE: | Reason Generation is not the primary beneficiary: |
Equity investments in distributed energy companies -
1) Generation has a 90% equity ownership in a distributed energy company.
2) Generation, via a consolidated VIE, has a 90% equity ownership in another distributed energy company (See Consolidated VIEs disclosure above).
Generation fully impaired this investment in 2019.
| Similar structures to a limited partnership and the limited partners do not have kick out rights with respect to the general partner. | Generation does not conduct the operational activities. |
Energy Purchase and Sale agreements - Generation has several energy purchase and sale agreements with generating facilities. | PPA contracts that absorb variability through fixed pricing. | Generation does not conduct the operational activities. |
18.14. Supplemental Financial Information (All Registrants)
Supplemental Statement of Operations Information
The following tables provide additional information about material items recorded in the Registrants' Consolidated Statements of Operations and Comprehensive Income.Income:
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 1814 — Supplemental Financial Information
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Operating revenues |
| Exelon | | Generation | | | | | | | | PHI | | | | DPL | | |
| Three Months Ended September 30, 2021 | | | | | | | | | | | | | | | | |
| Operating lease income | $ | 30 | | | $ | 29 | | | | | | | | | $ | 1 | | | | | $ | 1 | | | |
| Variable lease income | 71 | | | 71 | | | | | | | | | — | | | | | — | | | |
| | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, 2020 | | | | | | | | | | | | | | | | |
| Operating lease income | $ | 30 | | | $ | 28 | | | | | | | | | $ | 1 | | | | | $ | 1 | | | |
| Variable lease income | 76 | | | 76 | | | | | | | | | — | | | | | — | | | |
| | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2021 | | | | | | | | | | | | | | | | | |
| Operating lease income | $ | 47 | | | $ | 44 | | | | | | | | | $ | 3 | | | | | $ | 3 | | | |
| Variable lease income | 208 | | | 207 | | | | | | | | | 1 | | | | | 1 | | | |
| | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2020 | | | | | | | | | | | | | | | | |
| Operating lease income | $ | 48 | | | $ | 43 | | | | | | | | | $ | 3 | | | | | $ | 3 | | | |
| Variable lease income | 225 | | | 224 | | | | | | | | | 1 | | | | | 1 | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Taxes other than income taxes |
| Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Three Months Ended June 30, 2022 | | | | | | | | | | | | | | | |
Utility taxes(a) | $ | 203 | | | $ | 71 | | | $ | 39 | | | $ | 20 | | | $ | 73 | | | $ | 67 | | | $ | 5 | | | $ | 1 | |
| Property | 94 | | | 10 | | | 4 | | | 46 | | | 33 | | | 23 | | | 10 | | | — | |
| Payroll | 28 | | | 7 | | | 5 | | | 4 | | | 7 | | | 1 | | | 1 | | | 1 | |
| | | | | | | | | | | | | | | |
| Three Months Ended June 30, 2021 | | | | | | | | | | | | | | | |
Utility taxes(a) | $ | 184 | | | $ | 61 | | | $ | 32 | | | $ | 20 | | | $ | 71 | | | $ | 65 | | | $ | 5 | | | $ | — | |
| Property | 86 | | | 8 | | | 4 | | | 43 | | | 31 | | | 20 | | | 10 | | | 1 | |
| Payroll | 32 | | | 6 | | | 4 | | | 5 | | | 7 | | | 1 | | | 1 | | | 1 | |
| | | | | | | | | | | | | | | |
| Six Months Ended June 30, 2022 | | | | | | | | | | | | | | | |
Utility taxes(a) | $ | 424 | | | $ | 149 | | | $ | 77 | | | $ | 47 | | | $ | 151 | | | $ | 137 | | | $ | 12 | | | $ | 2 | |
| Property | 188 | | | 20 | | | 9 | | | 92 | | | 67 | | | 46 | | | 20 | | | 1 | |
| Payroll | 64 | | | 13 | | | 8 | | | 9 | | | 14 | | | 3 | | | 2 | | | 2 | |
| | | | | | | | | | | | | | | |
| Six Months Ended June 30, 2021 | | | | | | | | | | | | | | | |
Utility taxes(a) | $ | 377 | | | $ | 121 | | | $ | 66 | | | $ | 45 | | | $ | 145 | | | $ | 132 | | | $ | 11 | | | $ | 1 | |
| Property | 173 | | | 16 | | | 9 | | | 85 | | | 63 | | | 42 | | | 19 | | | 1 | |
| Payroll | 64 | | | 13 | | | 8 | | | 9 | | | 14 | | | 3 | | | 3 | | | 2 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Taxes other than income taxes |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Three Months Ended September 30, 2021 | | | | | | | | | | | | | | | | |
Utility taxes(a) | $ | 242 | | | $ | 27 | | | $ | 67 | | | $ | 41 | | | $ | 21 | | | $ | 86 | | | $ | 80 | | | $ | 6 | | | $ | — | |
| Property | 165 | | | 66 | | | 13 | | | 5 | | | 46 | | | 34 | | | 23 | | | 10 | | | 1 | |
| Payroll | 57 | | | 26 | | | 7 | | | 4 | | | 5 | | | 7 | | | 2 | | | 1 | | | 1 | |
| | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, 2020 | | | | | | | | | | | | | | | | |
Utility taxes(a) | $ | 237 | | | $ | 26 | | | $ | 66 | | | $ | 41 | | | $ | 21 | | | $ | 83 | | | $ | 77 | | | $ | 5 | | | $ | 1 | |
| Property | 152 | | | 66 | | | 7 | | | 4 | | | 42 | | | 32 | | | 21 | | | 10 | | | 1 | |
| Payroll | 59 | | | 29 | | | 7 | | | 4 | | | 4 | | | 6 | | | 2 | | | 1 | | | 1 | |
| | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2021 | | | | | | | | | | | | | | | | |
Utility taxes(a) | $ | 665 | | | $ | 73 | | | $ | 188 | | | $ | 107 | | | $ | 66 | | | $ | 231 | | | $ | 212 | | | $ | 17 | | | $ | 2 | |
| Property | 470 | | | 199 | | | 30 | | | 13 | | | 131 | | | 97 | | | 65 | | | 30 | | | 2 | |
| Payroll | 180 | | | 83 | | | 20 | | | 12 | | | 14 | | | 21 | | | 5 | | | 4 | | | 2 | |
| | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2020 | | | | | | | | | | | | | | | | |
Utility taxes(a) | $ | 651 | | | $ | 75 | | | $ | 181 | | | $ | 102 | | | $ | 65 | | | $ | 228 | | | $ | 210 | | | $ | 16 | | | $ | 2 | |
| Property | 449 | | | 199 | | | 23 | | | 12 | | | 121 | | | 94 | | | 63 | | | 29 | | | 2 | |
| Payroll | 183 | | | 88 | | | 21 | | | 12 | | | 13 | | | 21 | | | 6 | | | 4 | | | 3 | |
___________________
(a)Generation’s utility tax represents gross receipts tax related to its retail operations, and the UtilityThe Registrants' utility taxes representsrepresent municipal and state utility taxes and gross receipts taxes related to their operating revenues. The offsetting collection of utility taxes from customers is recorded in revenues in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
140 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Other, Net |
| Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Three Months Ended June 30, 2022 | | | | | | | | | | | | | | | |
| AFUDC — Equity | $ | 38 | | | $ | 9 | | | $ | 8 | | | $ | 6 | | | $ | 15 | | | $ | 11 | | | $ | 2 | | | $ | 2 | |
| Non-service net periodic benefit cost | 16 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Three Months Ended June 30, 2021 | | | | | | | | | | | | | | | |
| AFUDC — Equity | $ | 34 | | | $ | 9 | | | $ | 6 | | | $ | 7 | | | $ | 12 | | | $ | 10 | | | $ | 1 | | | $ | 1 | |
| Non-service net periodic benefit cost | 26 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Six Months Ended June 30, 2022 | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| AFUDC — Equity | $ | 74 | | | $ | 17 | | | $ | 15 | | | $ | 12 | | | $ | 30 | | | $ | 22 | | | $ | 4 | | | $ | 4 | |
| Non-service net periodic benefit cost | 33 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Six Months Ended June 30, 2021 | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| AFUDC — Equity | $ | 64 | | | $ | 13 | | | $ | 12 | | | $ | 14 | | | $ | 25 | | | $ | 20 | | | $ | 3 | | | $ | 2 | |
| Non-service net periodic benefit cost | 46 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)
Note 18 — Supplemental Financial Information
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Other, Net |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Three Months Ended September 30, 2021 | | | | | | | | | | | | | | | | |
| Decommissioning-related activities: | | | | | | | | | | | | | | | | | |
Net realized income on NDT funds(a) | | | | | | | | | | | | | | | | | |
| Regulatory Agreement Units | $ | 263 | | | $ | 263 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
| Non-Regulatory Agreement Units | 102 | | | 102 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Net unrealized losses on NDT funds | | | | | | | | | | | | | | | | | |
| Regulatory Agreement Units | (195) | | | (195) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Non-Regulatory Agreement Units | (88) | | | (88) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
Regulatory offset to NDT fund-related activities(b) | (38) | | | (38) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Decommissioning-related activities | 44 | | | 44 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| AFUDC — Equity | 36 | | | — | | | 10 | | | 7 | | | 7 | | | 12 | | | 9 | | | 2 | | | 1 | |
| Non-service net periodic benefit cost | 19 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
Net unrealized losses from equity investments(c) | (179) | | | (179) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, 2020 | | | | | | | | | | | | | | | | |
| Decommissioning-related activities: | | | | | | | | | | | | | | | | | |
Net realized income on NDT funds(a) | | | | | | | | | | | | | | | | | |
| Regulatory Agreement Units | $ | 50 | | | $ | 50 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
| Non-Regulatory Agreement Units | 23 | | | 23 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Net unrealized gains on NDT funds | | | | | | | | | | | | | | | | | |
| Regulatory Agreement Units | 398 | | | 398 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Non-Regulatory Agreement Units | 254 | | | 254 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
Regulatory offset to NDT fund-related activities(b) | (359) | | | (359) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Decommissioning-related activities | 366 | | | 366 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| AFUDC — Equity | 27 | | | — | | | 7 | | | 5 | | | 6 | | | 9 | | | 7 | | | 1 | | | 1 | |
| Non-service net periodic benefit cost | 15 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)
Note 18 — Supplemental Financial Information
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Other, net |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Nine Months Ended September 30, 2021 | | | | | | | | | | | | | | | | |
| Decommissioning-related activities: | | | | | | | | | | | | | | | | | |
Net realized income on NDT funds(a) | | | | | | | | | | | | | | | | | |
| Regulatory Agreement Units | $ | 698 | | | $ | 698 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
| Non-Regulatory Agreement Units | 392 | | | 392 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Net unrealized gains on NDT funds | | | | | | | | | | | | | | | | | |
| Regulatory Agreement Units | 84 | | | 84 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Non-Regulatory Agreement Units | 38 | | | 38 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
Regulatory offset to NDT fund-related activities(b) | (607) | | | (607) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Decommissioning-related activities | 605 | | | 605 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| | | | | | | | | | | | | | | | | |
| AFUDC — Equity | 99 | | | — | | | 23 | | | 19 | | | 21 | | | 36 | | | 30 | | | 4 | | | 2 | |
| Non-service net periodic benefit cost | 64 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
Net unrealized losses from equity investments(c) | (83) | | | (83) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2020 | | | | | | | | | | | | | | | | |
| Decommissioning-related activities: | | | | | | | | | | | | | | | | | |
Net realized income on NDT funds(a) | | | | | | | | | | | | | | | | | |
| Regulatory Agreement Units | $ | 127 | | | $ | 127 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
| Non-Regulatory Agreement Units | 127 | | | 127 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Net unrealized gains on NDT funds | | | | | | | | | | | | | | | | | |
| Regulatory Agreement Units | 111 | | | 111 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Non-Regulatory Agreement Units | 1 | | | 1 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
Regulatory offset to NDT fund-related activities(b) | (192) | | | (192) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Decommissioning-related activities | 174 | | | 174 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| AFUDC — Equity | 76 | | | — | | | 22 | | | 12 | | | 16 | | | 26 | | | 20 | | | 3 | | | 3 | |
| Non-service net periodic benefit cost | 38 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
__________
(a)Realized income includes interest, dividends and realized gains and losses on sales of NDT fund investments.
(b)Includes the elimination of decommissioning-related activities for the Regulatory Agreement Units except for decommissioning-related impacts that were not offset for the Byron units starting in the second quarter of 2021, including the elimination of income taxes related to all NDT fund activity for those units. With Generation's September 15, 2021 reversal of the previous decision to retire Byron, Generation resumed contractual offset for Byron as of that date. See Note 10 — Asset Retirement Obligations of the Exelon 2020 Form 10-K for additional information regarding the accounting for nuclear decommissioning and Note 8 — Nuclear Decommissioning for additional information on the contractual offset suspension for the Byron units.
(c)Net unrealized losses from equity investments that became publicly traded entities in the fourth quarter of 2020 and the first half of 2021.
Supplemental Cash Flow Information
The following tables provide additional information about material items recorded in the Registrants' Consolidated Statements of Cash Flows.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 1814 — Supplemental Financial Information
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Depreciation, amortization, and accretion |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Nine Months Ended September 30, 2021 | | | | | | | | | | | | | | | | |
Property, plant, and equipment(a) | $ | 4,505 | | | $ | 2,698 | | | $ | 721 | | | $ | 249 | | | $ | 324 | | | $ | 467 | | | $ | 204 | | | $ | 126 | | | $ | 115 | |
Amortization of regulatory assets(a) | 439 | | | — | | | 172 | | | 10 | | | 110 | | | 147 | | | 98 | | | 31 | | | 18 | |
Amortization of intangible assets, net(a) | 44 | | | 37 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
Amortization of energy contract assets and liabilities(b) | 23 | | | 23 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
Nuclear fuel(c) | 810 | | | 810 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
ARO accretion(d) | 383 | | | 383 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Total depreciation, amortization, and accretion | $ | 6,204 | | | $ | 3,951 | | | $ | 893 | | | $ | 259 | | | $ | 434 | | | $ | 614 | | | $ | 302 | | | $ | 157 | | | $ | 133 | |
| | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2020 | | | | | | | | | | | | | | | | |
Property, plant, and equipment(a) | $ | 2,831 | | | $ | 1,121 | | | $ | 689 | | | $ | 238 | | | $ | 293 | | | $ | 436 | | | $ | 191 | | | $ | 116 | | | $ | 104 | |
Amortization of regulatory assets(a) | 434 | | | — | | | 152 | | | 21 | | | 112 | | | 149 | | | 91 | | | 27 | | | 30 | |
Amortization of intangible assets, net(a) | 47 | | | 40 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
Amortization of energy contract assets and liabilities(b) | 24 | | | 22 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
Nuclear fuel(c) | 708 | | | 708 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
ARO accretion(d) | 375 | | | 375 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Total depreciation, amortization, and accretion | $ | 4,419 | | | $ | 2,266 | | | $ | 841 | | | $ | 259 | | | $ | 405 | | | $ | 585 | | | $ | 282 | | | $ | 143 | | | $ | 134 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Depreciation and amortization |
| Exelon(a) | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Six Months Ended June 30, 2022 | | | | | | | | | | | | | | | |
Property, plant, and equipment(b) | $ | 1,376 | | | $ | 511 | | | $ | 177 | | | $ | 235 | | | $ | 335 | | | $ | 145 | | | $ | 92 | | | $ | 83 | |
Amortization of regulatory assets(b) | 357 | | | 138 | | | 8 | | | 87 | | | 124 | | | 68 | | | 21 | | | 35 | |
Amortization of intangible assets, net(b) | 8 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
Amortization of energy contract assets and liabilities(c) | 3 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
Nuclear fuel(d) | 66 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
ARO accretion(e) | 44 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Total depreciation, amortization, and accretion | $ | 1,854 | | | $ | 649 | | | $ | 185 | | | $ | 322 | | | $ | 459 | | | $ | 213 | | | $ | 113 | | | $ | 118 | |
| | | | | | | | | | | | | | | |
| Six Months Ended June 30, 2021 | | | | | | | | | | | | | | | |
Property, plant, and equipment(b) | $ | 3,043 | | | $ | 480 | | | $ | 165 | | | $ | 215 | | | $ | 309 | | | $ | 135 | | | $ | 84 | | | $ | 76 | |
Amortization of regulatory assets(b) | 291 | | | 109 | | | 8 | | | 78 | | | 95 | | | 64 | | | 20 | | | 11 | |
Amortization of intangible assets, net(b) | 29 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
Amortization of energy contract assets and liabilities(c) | 13 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
Nuclear fuel(d) | 549 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
ARO accretion(e) | 255 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Total depreciation, amortization, and accretion | $ | 4,180 | | | $ | 589 | | | $ | 173 | | | $ | 293 | | | $ | 404 | | | $ | 199 | | | $ | 104 | | | $ | 87 | |
__________
(a)Exelon's amounts include amounts related to Generation prior to the separation. See Note 2 — Discontinued Operations for additional information.
(b)Included in Depreciation and amortization in the Registrants' Consolidated Statements of Operations and Comprehensive Income.
(b)(c)Included in Operating revenues or Purchased power and fuel expense in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
(c)Included in Purchased power and fuel expense in the Registrants’Exelon’s Consolidated Statements of Operations and Comprehensive Income.
(d)Included in Purchased fuel expense in Exelon's Consolidated Statement of Operations and Comprehensive Income.
(e)Included in Operating and maintenance expense in the Registrants’Exelon's Consolidated StatementsStatement of Operations and Comprehensive Income.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 1814 — Supplemental Financial Information
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Other non-cash operating activities |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Nine Months Ended September 30, 2021 | | | | | | | | | | | | | | | | |
| Pension and non-pension postretirement benefit costs | $ | 304 | | | $ | 92 | | | $ | 97 | | | $ | 5 | | | $ | 45 | | | $ | 36 | | | $ | 5 | | | $ | 2 | | | $ | 8 | |
| Allowance for credit losses | 155 | | | 59 | | | 34 | | | 36 | | | 7 | | | 18 | | | 9 | | | 3 | | | 6 | |
Other decommissioning-related activity(a) | (810) | | | (810) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
Energy-related options(b) | 45 | | | 45 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
True-up adjustments to decoupling mechanisms and formula rates(c) | (129) | | | — | | | (32) | | | (20) | | | 17 | | | (94) | | | (54) | | | (17) | | | (23) | |
| Severance costs | (67) | | | (75) | | | 1 | | | — | | | — | | | 1 | | | — | | | — | | | — | |
| | | | | | | | | | | | | | | | | |
| Long-term incentive plan | 94 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Amortization of operating ROU asset | 146 | | | 98 | | | 2 | | | — | | | 22 | | | 21 | | | 5 | | | 7 | | | 3 | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| AFUDC — Equity | (99) | | | — | | | (23) | | | (19) | | | (21) | | | (36) | | | (30) | | | (4) | | | (2) | |
| | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2020 | | | | | | | | | | | | | | | | |
| Pension and non-pension postretirement benefit costs | $ | 310 | | | $ | 89 | | | $ | 85 | | | $ | 4 | | | $ | 46 | | | $ | 52 | | | $ | 11 | | | $ | 6 | | | $ | 10 | |
| Allowance for credit losses | 130 | | | 16 | | | 23 | | | 38 | | | 12 | | | 41 | | | 24 | | | 15 | | | 2 | |
Other decommissioning-related activity(a) | (301) | | | (301) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
Energy-related options(b) | 79 | | | 79 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
True-up adjustments to decoupling mechanisms and formula rates(c) | 66 | | | — | | | 51 | | | (10) | | | 10 | | | 15 | | | (20) | | | 15 | | | 20 | |
| Severance costs | 96 | | | 88 | | | 1 | | | — | | | — | | | — | | | — | | | — | | | — | |
| Provision for excess and obsolete inventory | 119 | | | 118 | | | 1 | | | 1 | | | — | | | (1) | | | — | | | (1) | | | — | |
| Long-term incentive plan | (8) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Amortization of operating ROU asset | 185 | | | 135 | | | 1 | | | — | | | 23 | | | 21 | | | 5 | | | 6 | | | 2 | |
Deferred Prosecution Agreement payments(d) | 200 | | | — | | | 200 | | | — | | | — | | | — | | | — | | | — | | | — | |
| | | | | | | | | | | | | | | | | |
| AFUDC — Equity | (76) | | | — | | | (22) | | | (12) | | | (16) | | | (26) | | | (20) | | | (3) | | | (3) | |
| | | | | | | | | | | | | | | | | |
| |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Other non-cash operating activities |
| Exelon(a) | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Six Months Ended June 30, 2022 | | | | | | | | | | | | | | | |
| Pension and non-pension postretirement benefit costs | $ | 86 | | | $ | 30 | | | $ | (4) | | | $ | 22 | | | $ | 26 | | | $ | 4 | | | $ | 2 | | | $ | 6 | |
| Allowance for credit losses | 96 | | | 29 | | | 21 | | | 18 | | | 29 | | | 16 | | | 6 | | | 7 | |
| Other decommissioning-related activity | 36 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Energy-related options | 60 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
True-up adjustments to decoupling mechanisms and formula rates(b) | (27) | | | (75) | | | (6) | | | 32 | | | 22 | | | 7 | | | 3 | | | 12 | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Long-term incentive plan | 40 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Amortization of operating ROU asset | 38 | | | 1 | | | — | | | 14 | | | 14 | | | 4 | | | 4 | | | 2 | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| AFUDC — Equity | (74) | | | (17) | | | (15) | | | (12) | | | (30) | | | (22) | | | (4) | | | (4) | |
| | | | | | | | | | | | | | | |
| Six Months Ended June 30, 2021 | | | | | | | | | | | | | | | |
| Pension and non-pension postretirement benefit costs | $ | 196 | | | $ | 64 | | | $ | 4 | | | $ | 29 | | | $ | 24 | | | $ | 3 | | | $ | 1 | | | $ | 5 | |
| Allowance for credit losses | 100 | | | 24 | | | 17 | | | 4 | | | 9 | | | 5 | | | 2 | | | 2 | |
| Other decommissioning-related activity | (636) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Energy-related options | 20 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
True-up adjustments to decoupling mechanisms and formula rates(b) | (176) | | | (64) | | | (17) | | | (8) | | | (88) | | | (46) | | | (19) | | | (23) | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Long-term incentive plan | 62 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Amortization of operating ROU asset | 83 | | | 1 | | | — | | | 15 | | | 14 | | | 3 | | | 5 | | | 2 | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| AFUDC — Equity | (64) | | | (13) | | | (12) | | | (14) | | | (25) | | | (20) | | | (3) | | | (2) | |
__________
(a)Includes the elimination of decommissioning-related activities for the Regulatory Agreement Units except for decommissioning-related impacts that were not offset for the Byron units starting in the second quarter of 2021, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income, and income taxesExelon's amounts include amounts related to all NDT fund activity for these units. With Generation's September 15, 2021 reversal ofGeneration prior to the previous decision to retire Byron, Generation resumed contractual offset for Byron as of that date.separation. See Note 102 — Asset Retirement Obligations of the Exelon 2020 Form 10-KDiscontinued Operations for additional information regarding the accounting for nuclear decommissioning and Note 8 — Nuclear Decommissioning for additional information on the contractual offset suspension for the Byron units.information.
(b)Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations.
(c)For ComEd, reflects the true-up adjustments in regulatory assets and liabilities associated with its distribution, energy efficiency, distributed generation, and transmission formula rates. For BGE, Pepco, DPL, and ACE, reflects the change in regulatory assets and liabilities associated with their decoupling mechanisms and transmission formula rates. For PECO, reflects the change in regulatory assets and liabilities associated with its transmission formula rates. See Note 3 — Regulatory Matters of the 2021 Recast Form 10-K for additional information.
(d)See Note 15 — Commitments and Contingencies for additional information related to the Deferred Prosecution Agreement.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 1814 — Supplemental Financial Information
The following tables provide a reconciliation of cash, cash equivalents, and restricted cash reported within the Registrants’ Consolidated Balance Sheets that sum to the total of the same amounts in their Consolidated Statements of Cash Flows.
| | | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| September 30, 2021 | | | | | | | | | | | | | | | | | | |
| June 30, 2022 | | June 30, 2022 | | | | | | | | | | | | | | | |
| Cash and cash equivalents | Cash and cash equivalents | $ | 2,957 | | | $ | 1,957 | | | $ | 241 | | | $ | 344 | | | $ | 225 | | | $ | 82 | | | $ | 19 | | | $ | 13 | | | $ | 16 | | Cash and cash equivalents | $ | 816 | | | $ | 120 | | | $ | 23 | | | $ | 354 | | | $ | 278 | | | $ | 14 | | | $ | 26 | | | $ | 233 | |
| Restricted cash and cash equivalents | Restricted cash and cash equivalents | 473 | | | 62 | | | 276 | | | 8 | | | 27 | | | 71 | | | 41 | | | 26 | | | 5 | | Restricted cash and cash equivalents | 961 | | | 384 | | | 9 | | | 205 | | | 341 | | | 117 | | | 223 | | | — | |
| Restricted cash included in other long-term assets | Restricted cash included in other long-term assets | 54 | | | — | | | 44 | | | — | | | — | | | 9 | | | — | | | — | | | 9 | | Restricted cash included in other long-term assets | 59 | | | 59 | | | — | | | — | | | — | | | — | | | — | | | — | |
| Total cash, restricted cash, and cash equivalents | Total cash, restricted cash, and cash equivalents | $ | 3,484 | | | $ | 2,019 | | | $ | 561 | | | $ | 352 | | | $ | 252 | | | $ | 162 | | | $ | 60 | | | $ | 39 | | | $ | 30 | | Total cash, restricted cash, and cash equivalents | $ | 1,836 | | | $ | 563 | | | $ | 32 | | | $ | 559 | | | $ | 619 | | | $ | 131 | | | $ | 249 | | | $ | 233 | |
| | December 31, 2021 | | December 31, 2021 | |
| Cash and cash equivalents | | Cash and cash equivalents | $ | 672 | | | $ | 131 | | | $ | 36 | | | $ | 51 | | | $ | 136 | | | $ | 34 | | | $ | 28 | | | $ | 29 | |
| Restricted cash and cash equivalents | | Restricted cash and cash equivalents | 321 | | | 210 | | | 8 | | | 4 | | | 77 | | | 34 | | | 43 | | | — | |
| Restricted cash included in other long-term assets | | Restricted cash included in other long-term assets | 44 | | | 43 | | | — | | | — | | | — | | | — | | | — | | | — | |
| Cash, restricted cash, and cash equivalents from discontinued operations | | Cash, restricted cash, and cash equivalents from discontinued operations | 582 | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Total cash, restricted cash, and cash equivalents | | Total cash, restricted cash, and cash equivalents | $ | 1,619 | | | $ | 384 | | | $ | 44 | | | $ | 55 | | | $ | 213 | | | $ | 68 | | | $ | 71 | | | $ | 29 | |
| | June 30, 2021 | | June 30, 2021 | |
| Cash and cash equivalents | | Cash and cash equivalents | $ | 1,578 | | | $ | 71 | | | $ | 376 | | | $ | 368 | | | $ | 61 | | | $ | 17 | | | $ | 17 | | | $ | 11 | |
| Restricted cash and cash equivalents | | Restricted cash and cash equivalents | 379 | | | 240 | | | 8 | | | 3 | | | 42 | | | 33 | | | 5 | | | 3 | |
| Restricted cash included in other long-term assets | | Restricted cash included in other long-term assets | 52 | | | 43 | | | — | | | — | | | 9 | | | — | | | — | | | 9 | |
Total cash, restricted cash, and cash equivalents(a) | | Total cash, restricted cash, and cash equivalents(a) | $ | 2,009 | | | $ | 354 | | | $ | 384 | | | $ | 371 | | | $ | 112 | | | $ | 50 | | | $ | 22 | | | $ | 23 | |
| | December 31, 2020 | December 31, 2020 | | December 31, 2020 | |
| Cash and cash equivalents | Cash and cash equivalents | $ | 663 | | | $ | 226 | | | $ | 83 | | | $ | 19 | | | $ | 144 | | | $ | 111 | | | $ | 30 | | | $ | 15 | | | $ | 17 | | Cash and cash equivalents | $ | 432 | | | $ | 83 | | | $ | 19 | | | $ | 144 | | | $ | 111 | | | $ | 30 | | | $ | 15 | | | $ | 17 | |
| Restricted cash and cash equivalents | Restricted cash and cash equivalents | 438 | | | 89 | | | 279 | | | 7 | | | 1 | | | 39 | | | 35 | | | — | | | 3 | | Restricted cash and cash equivalents | 349 | | | 279 | | | 7 | | | 1 | | | 39 | | | 35 | | | — | | | 3 | |
| Restricted cash included in other long-term assets | Restricted cash included in other long-term assets | 53 | | | — | | | 43 | | | — | | | — | | | 10 | | | — | | | — | | | 10 | | Restricted cash included in other long-term assets | 53 | | | 43 | | | — | | | — | | | 10 | | | — | | | — | | | 10 | |
| Cash, restricted cash, and cash equivalents - Held for Sale | 12 | | | 12 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | |
| Cash, restricted cash, and cash equivalents from discontinued operations | | Cash, restricted cash, and cash equivalents from discontinued operations | 332 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Total cash, restricted cash, and cash equivalents | Total cash, restricted cash, and cash equivalents | $ | 1,166 | | | $ | 327 | | | $ | 405 | | | $ | 26 | | | $ | 145 | | | $ | 160 | | | $ | 65 | | | $ | 15 | | | $ | 30 | | Total cash, restricted cash, and cash equivalents | $ | 1,166 | | | $ | 405 | | | $ | 26 | | | $ | 145 | | | $ | 160 | | | $ | 65 | | | $ | 15 | | | $ | 30 | |
| | September 30, 2020 | | |
| Cash and cash equivalents | $ | 1,858 | | | $ | 623 | | | $ | 76 | | | $ | 242 | | | $ | 326 | | | $ | 196 | | | $ | 125 | | | $ | 26 | | | $ | 13 | | |
| Restricted cash and cash equivalents | 485 | | | 100 | | | 305 | | | 7 | | | 1 | | | 38 | | | 33 | | | — | | | 4 | | |
| Restricted cash included in other long-term assets | 137 | | | — | | | 127 | | | — | | | — | | | 10 | | | — | | | — | | | 10 | | |
| Total cash, restricted cash, and cash equivalents | $ | 2,480 | | | $ | 723 | | | $ | 508 | | | $ | 249 | | | $ | 327 | | | $ | 244 | | | $ | 158 | | | $ | 26 | | | $ | 27 | | |
| | December 31, 2019 | | |
| Cash and cash equivalents | $ | 587 | | | $ | 303 | | | $ | 90 | | | $ | 21 | | | $ | 24 | | | $ | 131 | | | $ | 30 | | | $ | 13 | | | $ | 12 | | |
| Restricted cash and cash equivalents | 358 | | | 146 | | | 150 | | | 6 | | | 1 | | | 36 | | | 33 | | | — | | | 2 | | |
| Restricted cash included in other long-term assets | 177 | | | — | | | 163 | | | — | | | — | | | 14 | | | — | | | — | | | 14 | | |
| Total cash, restricted cash, and cash equivalents | $ | 1,122 | | | $ | 449 | | | $ | 403 | | | $ | 27 | | | $ | 25 | | | $ | 181 | | | $ | 63 | | | $ | 13 | | | $ | 28 | | |
__________
(a)Exelon's amounts include amounts related to Generation prior to the separation. See Note 2 — Discontinued Operations for additional information.
For additional information on restricted cash see Note 1 — Significant Accounting Policies of the Exelon 20202021 Recast Form 10-K.
Supplemental Balance Sheet Information
The following tables provide additional information about material items recorded in the Registrants' Consolidated Balance Sheets.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 1814 — Supplemental Financial Information
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Accrued expenses |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| September 30, 2021 | | | | | | | | | | | | | | | | | |
Compensation-related accruals(a) | $ | 894 | | | $ | 318 | | | $ | 148 | | | $ | 66 | | | $ | 72 | | | $ | 108 | | | $ | 34 | | | $ | 21 | | | $ | 16 | |
| Taxes accrued | 508 | | | 222 | | | 80 | | | 61 | | | 90 | | | 98 | | | 67 | | | 16 | | | 7 | |
| Interest accrued | 415 | | | 77 | | | 65 | | | 36 | | | 39 | | | 75 | | | 37 | | | 20 | | | 15 | |
| | | | | | | | | | | | | | | | | |
| December 31, 2020 | | | | | | | | | | | | | | | | | |
Compensation-related accruals(a) | $ | 1,069 | | | $ | 426 | | | $ | 170 | | | $ | 73 | | | $ | 84 | | | $ | 109 | | | $ | 36 | | | $ | 18 | | | $ | 17 | |
| Taxes accrued | 527 | | | 229 | | | 94 | | | 16 | | | 73 | | | 117 | | | 90 | | | 18 | | | 12 | |
| Interest accrued | 331 | | | 44 | | | 109 | | | 37 | | | 46 | | | 51 | | | 26 | | | 7 | | | 12 | |
The following table provides additional information about material items recorded in the Registrants' Consolidated Balance Sheets.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Accrued expenses |
| Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| June 30, 2022 | | | | | | | | | | | | | | | |
Compensation-related accruals(a) | $ | 428 | | | $ | 109 | | | $ | 57 | | | $ | 54 | | | $ | 82 | | | $ | 26 | | | $ | 16 | | | $ | 13 | |
| Taxes accrued | 243 | | | 94 | | | 60 | | | 31 | | | 84 | | | 57 | | | 12 | | | 11 | |
| Interest accrued | 331 | | | 124 | | | 40 | | | 44 | | | 59 | | | 31 | | | 9 | | | 14 | |
| | | | | | | | | | | | | | | |
| December 31, 2021 | | | | | | | | | | | | | | | |
Compensation-related accruals(a) | $ | 596 | | | $ | 155 | | | $ | 77 | | | $ | 78 | | | $ | 113 | | | $ | 35 | | | $ | 20 | | | $ | 17 | |
| Taxes accrued | 253 | | | 94 | | | 14 | | | 53 | | | 96 | | | 88 | | | 9 | | | 11 | |
| Interest accrued | 297 | | | 116 | | | 41 | | | 44 | | | 52 | | | 28 | | | 8 | | | 11 | |
__________
(a)Primarily includes accrued payroll, bonuses and other incentives, vacation, and benefits.
19.15. Related Party Transactions (All Registrants)
Operating revenuesUtility Registrants' expense with Generation
The Utility Registrants incurred expenses from affiliates
transactions with the Generation
The following affiliate as described in the footnotes to the table presents Generation’s Operating revenues from affiliates, which arebelow prior to separation on February 1, 2022. Such expenses were primarily recorded as Purchased power from affiliates and an immaterial amount recorded as Operating and maintenance expense from affiliates at the Utility Registrants:Registrants:
| | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | 2021 | | 2020 | | 2021 | | 2020 |
| Operating revenues from affiliates: | | | | | | | |
ComEd(a)(b) | $ | 96 | | | $ | 71 | | | $ | 249 | | | $ | 241 | |
PECO(c) | 59 | | | 68 | | | 142 | | | 146 | |
BGE(d) | 65 | | | 84 | | | 195 | | | 252 | |
| PHI | 99 | | | 105 | | | 276 | | | 288 | |
Pepco(e) | 69 | | | 80 | | | 199 | | | 219 | |
DPL(f) | 25 | | | 21 | | | 63 | | | 60 | |
ACE(g) | 5 | | | 4 | | | 14 | | | 9 | |
| Other | 5 | | | 3 | | | 10 | | | 5 | |
| Total operating revenues from affiliates (Generation) | $ | 324 | | | $ | 331 | | | $ | 872 | | | $ | 932 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended June 30, | | Six Months Ended June 30, |
| | 2022 | | 2021 | | 2022 | | 2021 |
ComEd(a) | $ | — | | | $ | 78 | | | $ | 59 | | | $ | 163 | |
PECO(b) | — | | | 41 | | | 33 | | | 83 | |
BGE(c) | — | | | 58 | | | 18 | | | 130 | |
| PHI | — | | | 77 | | | 51 | | | 176 | |
Pepco(d) | — | | | 55 | | | 39 | | | 130 | |
DPL(e) | — | | | 17 | | | 10 | | | 37 | |
ACE(f) | — | | | 5 | | | 2 | | | 9 | |
__________(a)Generation hasComEd had an ICC-approved RFP contract with ComEdGeneration to provide a portion of ComEd’s electricityelectric supply requirements. GenerationComEd also sellspurchased RECs and ZECs to ComEd.from Generation.
(b)For the three and nine months ended September 30, 2021, respectively, ComEd’s Purchased powerPECO received electric supply from Generation of $94 million and $256 million is recorded as Operating revenues from ComEd of $96 million and $249 million and as Purchased power and fuel from ComEd of $2 million and $(7) million at Generation. For the three and nine months ended September 30, 2020, respectively, ComEd’s Purchased power from Generation of $71 million and$252 million is recorded as Operating revenues from ComEd of $71 million and $241 million and as Purchased power and fuel from ComEd of less than $1 million and $11 million at Generation.
(c)Generation provides electric supply to PECO under contracts executed through PECO’s competitive procurement process. In addition, Generation hasPECO had a ten-year agreement with PECOGeneration to sell solar AECs.
(d)(c)Generation providesBGE received a portion of BGE’sits energy requirements from Generation under its MDPSC-approved market-based SOS and gas commodity programs.
(e)(d)Generation providesPepco received electric supply to Pepcofrom Generation under contracts executed through Pepco's competitive procurement process approved by the MDPSC and DCPSC.
(f)(e)Generation providesDPL received a portion of DPL'sits energy requirements from Generation under its MDPSC and DPSC-approvedDEPSC approved market-based SOS commodity programs.
(g)(f)Generation providesACE received electric supply to ACEfrom Generation under contracts executed through ACE's competitive procurement process.process approved by the NJBPU.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 1915 — Related Party Transactions
PHI
PHI’s Operating revenues from affiliates are primarily with BSC for services that PHISCO provides to BSC.
Service Company Costs for Corporate Support
The Registrants receive a variety of corporate support services from BSC. Pepco, DPL, and ACE also receive corporate support services from PHISCO. See Note 1 — Significant Accounting Policies for additional information regarding BSC and PHISCO.
The following table presents the service company costs allocated to the Registrants:
| | | Operating and maintenance from affiliates | | Capitalized costs | | Operating and maintenance from affiliates | | Capitalized costs |
| | Three Months Ended September 30, | | Nine Months Ended September 30, | | Three Months Ended September 30, | | Nine Months Ended September 30, | | Three Months Ended June 30, | | Six Months Ended June 30, | | Three Months Ended June 30, | | Six Months Ended June 30, |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 | | 2022 | | 2021 | | 2022 | | 2021 |
| Exelon | Exelon | | | | | | | | | | | | | | | | | Exelon | | | | | | | | | | | | | | | | |
| BSC | BSC | | $ | 149 | | | $ | 148 | | | $ | 431 | | | $ | 390 | | BSC | | $ | 139 | | | $ | 114 | | | $ | 344 | | | $ | 249 | |
| PHISCO | PHISCO | | 18 | | | 15 | | | 54 | | | 45 | | PHISCO | | 21 | | | 17 | | | 40 | | | 36 | |
| Generation | | |
| BSC | | $ | 145 | | | $ | 133 | | | $ | 424 | | | $ | 406 | | | 43 | | | 13 | | | 76 | | | 37 | | |
| ComEd | ComEd | | ComEd | |
| BSC | BSC | | 71 | | | 65 | | | 214 | | | 204 | | | 47 | | | 49 | | | 148 | | | 133 | | BSC | | $ | 80 | | | $ | 72 | | | $ | 165 | | | $ | 143 | | | 67 | | | 45 | | | 152 | | | 102 | |
| PECO | PECO | | PECO | |
| BSC | BSC | | 41 | | | 34 | | | 120 | | | 107 | | | 12 | | | 20 | | | 57 | | | 53 | | BSC | | 47 | | | 40 | | | 96 | | | 80 | | | 20 | | | 17 | | | 56 | | | 44 | |
| BGE | BGE | | BGE | |
| BSC | BSC | | 45 | | | 38 | | | 133 | | | 120 | | | 20 | | | 30 | | | 62 | | | 88 | | BSC | | 51 | | | 45 | | | 102 | | | 88 | | | 22 | | | 20 | | | 60 | | | 43 | |
| PHI | PHI | | PHI | |
| BSC | BSC | | 40 | | | 36 | | | 116 | | | 107 | | | 27 | | | 36 | | | 88 | | | 79 | | BSC | | 46 | | | 37 | | | 96 | | | 76 | | | 30 | | | 32 | | | 76 | | | 60 | |
| PHISCO | PHISCO | | — | | | — | | | — | | | — | | | 18 | | | 15 | | | 54 | | | 45 | | PHISCO | | — | | | — | | | — | | | — | | | 21 | | | 17 | | | 40 | | | 36 | |
| Pepco | Pepco | | Pepco | |
| BSC | BSC | | 23 | | | 20 | | | 68 | | | 61 | | | 11 | | | 14 | | | 36 | | | 29 | | BSC | | 27 | | | 23 | | | 56 | | | 45 | | | 11 | | | 13 | | | 28 | | | 25 | |
| PHISCO | PHISCO | | 26 | | | 28 | | | 84 | | | 90 | | | 7 | | | 7 | | | 22 | | | 20 | | PHISCO | | 29 | | | 28 | | | 58 | | | 57 | | | 8 | | | 7 | | | 16 | | | 15 | |
| | DPL | DPL | | DPL | |
| BSC | BSC | | 14 | | | 13 | | | 43 | | | 38 | | | 10 | | | 12 | | | 29 | | | 26 | | BSC | | 17 | | | 15 | | | 35 | | | 29 | | | 9 | | | 10 | | | 23 | | | 19 | |
| PHISCO | PHISCO | | 24 | | | 24 | | | 73 | | | 73 | | | 6 | | | 4 | | | 17 | | | 13 | | PHISCO | | 25 | | | 24 | | | 49 | | | 49 | | | 7 | | | 5 | | | 13 | | | 11 | |
| | ACE | ACE | | ACE | |
| BSC | BSC | | 14 | | | 11 | | | 37 | | | 32 | | | 7 | | | 10 | | | 22 | | | 22 | | BSC | | 14 | | | 12 | | | 29 | | | 24 | | | 10 | | | 8 | | | 25 | | | 15 | |
| PHISCO | PHISCO | | 21 | | | 21 | | | 64 | | | 65 | | | 5 | | | 4 | | | 15 | | | 12 | | PHISCO | | 22 | | | 21 | | | 43 | | | 43 | | | 6 | | | 5 | | | 11 | | | 10 | |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 1915 — Related Party Transactions
Current Receivables from/Payables to affiliates
The following tables present current receivables from affiliates and current payables to affiliates:
SeptemberJune 30, 20212022
| | | | Receivables from affiliates: | | | | Receivables from affiliates: | |
| | Payables to affiliates: | | Generation | | ComEd | | PECO | | BGE | | | Pepco | | DPL | | ACE | | BSC | | PHISCO | | Other | | Total | | Payables to affiliates: | | ComEd | | PECO | | BGE | | | Pepco | | DPL | | ACE | | BSC | | PHISCO | | Other | | Total |
| Generation | | | | $ | 36 | | | $ | 9 | | | $ | — | | | | $ | — | | | $ | — | | | $ | — | | | $ | 86 | | | $ | — | | | $ | 23 | | | $ | 154 | | |
| ComEd | ComEd | | $ | 103 | | (a) | | — | | | — | | | | — | | | — | | | — | | | 49 | | | — | | | 6 | | | 158 | | ComEd | | | | $ | — | | | $ | — | | | | $ | — | | | $ | — | | | $ | — | | | $ | 57 | | | $ | — | | | $ | 8 | | | $ | 65 | |
| PECO | PECO | | 24 | | | 3 | | | 1 | | | | — | | | — | | | — | | | 25 | | | — | | | 7 | | | 60 | | PECO | | $ | — | | | — | | | | — | | | — | | | — | | | 25 | | | — | | | 4 | | | 29 | |
| BGE | BGE | | 15 | | | — | | | — | | | | — | | | — | | | — | | | 32 | | | — | | | 2 | | | 49 | | BGE | | — | | | — | | | | — | | | — | | | — | | | 28 | | | — | | | 2 | | | 30 | |
| PHI | PHI | | — | | | — | | | — | | | — | | | | — | | | — | | | — | | | 2 | | | — | | | 10 | | | 12 | | PHI | | — | | | — | | | — | | | | — | | | — | | | — | | | 5 | | | — | | | 10 | | | 15 | |
| Pepco | Pepco | | 22 | | | — | | | — | | | — | | | | | 1 | | | — | | | 15 | | | 13 | | | — | | | 51 | | Pepco | | — | | | — | | | — | | | | | — | | | 1 | | | 14 | | | 13 | | | 1 | | | 29 | |
| DPL | DPL | | 4 | | | — | | | — | | | — | | | | — | | | — | | | 9 | | | 11 | | | — | | | 24 | | DPL | | — | | | — | | | — | | | | 9 | | | — | | | 9 | | | 10 | | | 1 | | | 29 | |
| ACE | ACE | | 7 | | | — | | | — | | | — | | | | — | | | — | | | 9 | | | 9 | | | 1 | | | 26 | | ACE | | — | | | — | | | — | | | | — | | | — | | | 9 | | | 10 | | | 1 | | | 20 | |
| Other | Other | | 9 | | | 2 | | | — | | | 1 | | | | — | | | — | | | 1 | | | 2 | | | — | | | 15 | | Other | | 3 | | | — | | | — | | | | — | | | — | | | — | | | — | | | — | | | 3 | |
| Total | Total | | $ | 184 | | | $ | 41 | | | $ | 9 | | | $ | 2 | | | | $ | — | | | $ | 1 | | | $ | 1 | | | $ | 229 | | | $ | 33 | | | $ | 49 | | | $ | 549 | | Total | | $ | 3 | | | $ | — | | | $ | — | | | | $ | 9 | | | $ | — | | | $ | 1 | | | $ | 147 | | | $ | 33 | | | $ | 27 | | | $ | 220 | |
|
December 31, 20202021
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Receivables from affiliates: | | |
| Payables to affiliates: | | Generation | | ComEd | | PECO | | BGE | | | | Pepco | | DPL | | ACE | | BSC | | PHISCO | | Other | | Total |
| Generation | | | | $ | 13 | | | $ | — | | | $ | — | | | | | $ | — | | | $ | — | | | $ | — | | | $ | 72 | | | $ | — | | | $ | 22 | | | $ | 107 | |
| ComEd | | $ | 78 | | (a) | | | — | | | — | | | | | — | | | — | | | — | | | 59 | | | — | | | 9 | | | 146 | |
| PECO | | 17 | | | 1 | | | | | — | | | | | — | | | — | | | — | | | 28 | | | — | | | 4 | | | 50 | |
| BGE | | 11 | | | — | | | — | | | | | | | — | | | — | | | — | | | 47 | | | — | | | 3 | | | 61 | |
| PHI | | — | | | — | | | — | | | — | | | | | — | | | — | | | — | | | 4 | | | — | | | 11 | | | 15 | |
| Pepco | | 13 | | | 2 | | | — | | | 1 | | | | | | | — | | | — | | | 25 | | | 14 | | | — | | | 55 | |
| DPL | | 3 | | | 1 | | | — | | | — | | | | | — | | | | | — | | | 21 | | | 10 | | | 1 | | | 36 | |
| ACE | | 6 | | | — | | | — | | | — | | | | | — | | | — | | | | | 15 | | | 9 | | | 1 | | | 31 | |
| Other | | 25 | | | 5 | | | 2 | | | 2 | | | | | 2 | | | 1 | | | 6 | | | — | | | — | | | | | 43 | |
| Total | | $ | 153 | | | $ | 22 | | | $ | 2 | | | $ | 3 | | | | | $ | 2 | | | $ | 1 | | | $ | 6 | | | $ | 271 | | | $ | 33 | | | $ | 51 | | | $ | 544 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
__________
(a)As of September 30, 2021 and December 31, 2020, Generation had a contract liability with ComEd for $27 million and $50 million, respectively, that was included in Other current liabilities on Generation’s Consolidated Balance Sheets. As of September 30, 2021 and December 31, 2020, ComEd had a Current Payable to Generation of $76 million and $28 million, respectively, on its Consolidated Balance Sheets, which consisted of Generation’s Current Receivable from ComEd, partially offset by Generation’s contract liability with ComEd. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Receivables from affiliates: | | |
| Payables to affiliates: | | ComEd | | PECO | | BGE | | | | Pepco | | DPL | | ACE | | Generation | | BSC | | PHISCO | | Other | | Total |
| ComEd | | | | $ | — | | | $ | — | | | | | $ | — | | | $ | — | | | $ | — | | | $ | 41 | | | $ | 71 | | | $ | — | | | $ | 9 | | | $ | 121 | |
| PECO | | $ | — | | | | | — | | | | | — | | | — | | | — | | | 30 | | | 36 | | | — | | | 4 | | | 70 | |
| BGE | | — | | | — | | | | | | | — | | | — | | | — | | | 4 | | | 41 | | | — | | | 3 | | | 48 | |
| PHI | | — | | | 1 | | | — | | | | | — | | | — | | | 1 | | | — | | | 5 | | | — | | | 9 | | | 16 | |
| Pepco | | — | | | — | | | 1 | | | | | | | 1 | | | 1 | | | 20 | | | 21 | | | 12 | | | 3 | | | 59 | |
| DPL | | — | | | — | | | — | | | | | — | | | | | — | | | 4 | | | 17 | | | 11 | | | 1 | | | 33 | |
| ACE | | — | | | — | | | — | | | | | — | | | — | | | | | 7 | | | 13 | | | 9 | | | 2 | | | 31 | |
| Generation | | 13 | | | — | | | — | | | | | — | | | — | | | — | | | | | 102 | | | — | | | 16 | | | 131 | |
| Other | | 3 | | | — | | | — | | | | | — | | | — | | | — | | | 11 | | | — | | | — | | | | | 14 | |
| Total | | $ | 16 | | | $ | 1 | | | $ | 1 | | | | | $ | — | | | $ | 1 | | | $ | 2 | | | $ | 117 | | | $ | 306 | | | $ | 32 | | | $ | 47 | | | $ | 523 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Borrowings from Exelon/PHI intercompany money pool
To provide an additional short-term borrowing option that will generally be more favorable to the borrowing participants than the cost of external financing both Exelon and PHI operate an intercompany money pool. Generation, ComEd, PECO, and PHI Corporate participate in the Exelon money pool. Pepco, DPL, and ACE participate in the PHI intercompany money pool.
Noncurrent Receivables from/Payables tofrom affiliates
Generation has long-term payables to ComEd and PECO have noncurrent receivables with Generation as a result of the nuclear decommissioning contractual construct whereby, to the extent NDT funds are greater than the underlying ARO at the end of decommissioning, such amounts are due back to ComEd and PECO, as applicable, for payment to their respective customers. The receivables are recorded in Receivable related to Regulatory Agreement Units as of June 30, 2022 and in noncurrent Receivables from affiliates as of December 31, 2021. See Note 103 — Asset Retirement ObligationsRegulatory Matters of the Exelon 2020Combined Notes to Consolidated Financial Statements of the 2021 Recast Form 10-K for additional information.
Long-term debt to financing trusts
The following table presents Long-term debt to financing trusts:
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 1915 — Related Party Transactions
The following table presents noncurrent receivables from affiliates at ComEd and PECO which are recorded as noncurrent payables to affiliates at Generation:
| | | | | | | | | | | |
| September 30, 2021 | | December 31, 2020 |
| ComEd | $ | 2,597 | | | $ | 2,541 | |
| PECO | 546 | | | 475 | |
| | | |
Long-term debt to financing trusts
The following table presents Long-term debt to financing trusts:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| September 30, 2021 | | December 31, 2020 |
| Exelon | | ComEd | | PECO | | Exelon | | ComEd | | PECO |
| ComEd Financing III | $ | 206 | | | $ | 205 | | | $ | — | | | $ | 206 | | | $ | 205 | | | $ | — | |
| PECO Trust III | 81 | | | — | | | 81 | | | 81 | | | — | | | 81 | |
| PECO Trust IV | 103 | | | — | | | 103 | | | 103 | | | — | | | 103 | |
| Total | $ | 390 | | | $ | 205 | | | $ | 184 | | | $ | 390 | | | $ | 205 | | | $ | 184 | |
Long-term debt to affiliates
In connection with the debt obligations assumed by Exelon as part of the Constellation merger, Exelon and subsidiaries of Generation (former Constellation subsidiaries) assumed intercompany loan agreements that mirror the terms and amounts of the third-party debt obligations of Exelon, resulting in intercompany notes payable included in Long-term debt to affiliates in Generation’s Consolidated Balance Sheets and intercompany notes receivable at Exelon Corporate.
20. Planned Separation
On February 21, 2021, Exelon’s Board of Directors approved a plan to separate the Utility Registrants and Generation, creating two publicly traded companies. Under the separation plan, Exelon shareholders will retain their current shares of Exelon stock and receive a pro-rata distribution of shares of the new company’s stock in a transaction that is expected to be tax-free to Exelon and its shareholders for U.S. federal income tax purposes. The actual number of shares to be distributed to Exelon shareholders will be determined prior to closing.
Exelon is targeting to complete the separation in the first quarter of 2022, subject to final approval by Exelon’s Board of Directors, a Form 10 registration statement being declared effective by the SEC, regulatory approvals, and satisfaction of other conditions. The transaction is subject to approval by FERC, NRC, and NYPSC and receipt of a private letter ruling from the IRS and tax opinion from Exelon’s tax advisors.
On February 25, 2021, Exelon and Generation filed applications with FERC, NYPSC, and NRC seeking approvals for the separation of Generation. On March 25, 2021, Exelon filed a request for a private letter ruling with the IRS to confirm the tax-free treatment of the planned separation, which was received on September 23, 2021. On August 24, 2021, Exelon and Generation received approval from FERC for the planned separation. Exelon and Generation expect a decision from the NRC in the fourth quarter of 2021 and have requested a decision from the NYPSC before the end of 2021. Exelon and Generation cannot predict if the remaining applications will be approved as filed.
There can be no assurance that any separation transaction will ultimately occur or, if one does occur, of its terms or timing. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| June 30, 2022 | | December 31, 2021 |
| Exelon | | ComEd | | PECO | | Exelon | | ComEd | | PECO |
| ComEd Financing III | $ | 206 | | | $ | 205 | | | $ | — | | | $ | 206 | | | $ | 205 | | | $ | — | |
| PECO Trust III | 81 | | | — | | | 81 | | | 81 | | | — | | | 81 | |
| PECO Trust IV | 103 | | | — | | | 103 | | | 103 | | | — | | | 103 | |
| Total | $ | 390 | | | $ | 205 | | | $ | 184 | | | $ | 390 | | | $ | 205 | | | $ | 184 | |
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
(Dollars in millions except per share data, unless otherwise noted)
Exelon
Executive Overview
Exelon is a utility services holding company engaged in the generation, delivery, and marketing of energy through Generation and the energy distribution and transmission businesses through ComEd, PECO, BGE, Pepco, DPL, and ACE.
Exelon has elevensix reportable segments consisting of Generation’s five reportable segments (Mid-Atlantic, Midwest, New York, ERCOT, and Other Power Regions), ComEd, PECO, BGE, Pepco, DPL, and ACE. See Note 1 — Significant Accounting Policies and Note 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for additional information regarding Exelon's principal subsidiaries and reportable segments.
Exelon’s consolidated financial information includes the results of its eightseven separate operating subsidiary registrants, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE, which, along with Exelon, are collectively referred to as the Registrants. The following combined Management’s Discussion and Analysis of Financial Condition and Results of Operations is separately filed by Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE. However, none of the Registrants makes any representation as to information related solely to any of the other Registrants.
Financial Results of Operations
GAAP Results of Operations. The following table sets forth Exelon's GAAP consolidated Net Incomeincome attributable to common shareholders by Registrantfrom continuing operations and the Utility Registrants' Net income for the three and ninesix months ended SeptemberJune 30, 20212022 compared to the same period in 2020.2021. For additional information regarding the financial results for the three and ninesix months ended SeptemberJune 30, 20212022 and 20202021 see the discussions of Results of Operations by Registrant.
| | | Three Months Ended September 30, | | Favorable (unfavorable) variance | | Nine Months Ended September 30, | | Favorable (unfavorable) variance | | Three Months Ended June 30, | | Favorable (Unfavorable) Variance | | Six Months Ended June 30, | | Favorable (Unfavorable) Variance |
| | 2021 | | 2020 | | 2021 | | 2020 | | | 2022 | | 2021 | | 2022 | | 2021 | |
| Exelon | Exelon | $ | 1,203 | | | $ | 501 | | | $ | 702 | | | $ | 1,315 | | | $ | 1,604 | | | $ | (289) | | Exelon | $ | 465 | | | $ | 326 | | | $ | 139 | | | $ | 946 | | | $ | 851 | | | $ | 95 | |
| Generation | 607 | | | 49 | | | 558 | | | (247) | | | 570 | | | (817) | | |
| ComEd | ComEd | 220 | | | 196 | | | 24 | | | 609 | | | 304 | | | 305 | | ComEd | 227 | | | 192 | | | 35 | | | 415 | | | 390 | | | 25 | |
| PECO | PECO | 111 | | | 138 | | | (27) | | | 383 | | | 317 | | | 66 | | PECO | 133 | | | 104 | | | 29 | | | 339 | | | 271 | | | 68 | |
| BGE | BGE | 36 | | | 53 | | | (17) | | | 290 | | | 273 | | | 17 | | BGE | 37 | | | 45 | | | (8) | | | 234 | | | 254 | | | (20) | |
| PHI | PHI | 266 | | | 216 | | | 50 | | | 535 | | | 418 | | | 117 | | PHI | 100 | | | 141 | | | (41) | | | 230 | | | 269 | | | (39) | |
| Pepco | Pepco | 130 | | | 118 | | | 12 | | | 264 | | | 227 | | | 37 | | Pepco | 70 | | | 75 | | | (5) | | | 116 | | | 134 | | | (18) | |
| DPL | DPL | 50 | | | 27 | | | 23 | | | 135 | | | 91 | | | 44 | | DPL | 21 | | | 30 | | | (9) | | | 77 | | | 86 | | | (9) | |
| ACE | ACE | 90 | | | 75 | | | 15 | | | 141 | | | 106 | | | 35 | | ACE | 11 | | | 37 | | | (26) | | | 37 | | | 51 | | | (14) | |
Other(a) | Other(a) | (37) | | | (151) | | | 114 | | | (255) | | | (278) | | | 23 | | Other(a) | (32) | | | (156) | | | 124 | | | (272) | | | (333) | | | 61 | |
__________
(a)Primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities and other financing and investing activities.
The separation of Constellation, including Generation and its subsidiaries, meets the criteria for discontinued operations and as such, Generation's results of operations are presented as discontinued operations and have been excluded from Exelon's continuing operations for all periods presented.
Accounting rules require that certain BSC costs previously allocated to Generation be presented as part of Exelon’s continuing operations as these costs do not qualify as expenses of the discontinued operations. Such costs are included in Other in the table above. See further discussion below.
Three Months Ended SeptemberJune 30, 20212022 Compared to Three Months Ended SeptemberJune 30, 2020.2021. Net income attributable to common shareholders from continuing operations increased by $702$139 million and diluted earnings per average common share increased to $1.23 in 2021 from $0.51 in 2020 primarily due to:
•Absence of an impairmentearnings per average common share from continuing operations increased to $0.47 in the New England asset group;
•Absence of one time charges recorded2022 from $0.33 in the third quarter of 2020 associated with Generation's decision to early retire the Byron and Dresden nuclear facilitiesand Mystic Units 8 and 9, and the reversal of one-time charges resulting from the reversal of the previous decision to early retire Byron and Dresden on September 15, 2021;
•Higher mark-to-market gains;
•Higher New York ZEC revenues2021 primarily due to higher generation and an increase in ZEC prices;to:
•Higher electric distribution earnings from higher rate base and higher allowed electric distribution ROE due to an increase in treasury rates and higher rate base at ComEd; and
•The favorable impacts of the multi-year plan at BGE and regulatory rate increases at DPLPECO, BGE, and Pepco.PHI; and
•Lower BSC costs, which were previously allocated to Generation but do not qualify as expenses of the discontinued operations per the accounting rules. Such costs, on a pre-tax basis, were $99 million for the three months ended June 30, 2021.
The increases were partially offset by:
•Lower net unrealizedThe absence of favorable weather and realized gains on NDT funds;volume as a result of the CIP at ACE;
•Decommissioning-related activities that were not offset for the Byron units beginning in the second quarter of 2021 through September 15, 2021. With Generation's September 15, 2021 reversal of the previous decision to retire Byron, Generation resumed contractual offset for Byron as of that date;Higher depreciation expense at BGE and PHI;
•Accelerated depreciation and amortization associated with Generation's previous decision in the third quarter of 2020 to early retire Byron and Dresden nuclear facilities in 2021, a decision which was reversed on September 15, 2021, and Generation's decision in the third quarter of 2020 to early retire Mystic Units 8 and 9 in 2024;Higher credit loss expense at PHI; and
•Higher net unrealized and realized losses on equity investments.interest expense at Exelon Corporate.
NineSix Months Ended SeptemberJune 30, 20212022 Compared to NineSix Months Ended SeptemberJune 30, 2020.2021. Net income attributable to common shareholders from continuing operations decreasedincreased by $289$95 million and diluted earnings per average common share decreasedfrom continuing operations increased to $1.34$0.96 in 2022 from $0.87 in 2021 from $1.64 in 2020 primarily due to:
•Impacts of the February 2021 extreme cold weather event;
•Accelerated depreciation and amortization associated with Generation's previous decision in the third quarter of 2020 to early retire Byron and Dresden nuclear facilities in 2021, a decision which was reversed on September 15, 2021, and Generation's decision in the third quarter of 2020 to early retire Mystic Units 8 and 9 in 2024;
•Decommissioning-related activities that were not offset for the Byron units beginning in the second quarter of 2021 through September 15, 2021. With Generation's September 15, 2021 reversal of the previous decision to retire Byron, Generation resumed contractual offset for Byron as of that date;
•Impairments at Generation of the New England asset group, the Albany Green Energy biomass facility, and a wind project, partially offset by the absence of an impairment of the New England asset group in the third quarter of 2020; and
•The absence of a prior year one-time tax settlement.
The decreases were partially offset by:
•Higher mark-to-market gains;
•Higher net unrealized and realized gains on NDT funds;
•Absence of one time charges recorded in the third quarter of 2020 associated with Generation's decision to early retire the Byron and Dresden nuclear facilities and Mystic generating station assets, and the reversal of one-time charges;
•Lower nuclear outage days;
•Higher New York ZEC revenues due to higher generation and an increase in ZEC prices;
•Lower operating and maintenance expense at ComEd due to the payments that ComEd made in 2020 under the Deferred Prosecution Agreement;
•Higher electric distribution earnings from higher rate base and higher allowed electric distribution ROE due to an increase in treasury rates and higher rate base at ComEd;
•The favorable impacts of the multi-year plan at BGE and regulatory rate increases at Pepco, DPL,PECO, BGE, and PHI;
•Lower BSC costs presented in Exelon’s continuing operations, which were previously allocated to Generation but do not qualify as expenses of the discontinued operation per the accounting rules. Such costs, on a pre-tax basis, were $28 million for the period in 2022 prior to the separation on February 1, 2022 (January 1, 2022 to January 31, 2022) and $206 million for the six months ended June 30, 2021.
The increases were partially offset by:
•An income tax expense recorded in connection with the separation primarily due to the long-term marginal state income tax rate change, the recognition of valuation allowances against the net deferred tax assets positions for certain standalone state filing jurisdictions, and nondeductible transaction costs partially offset by a one-time impact associated with a state tax benefit;
•The absence of favorable weather and volume as a result of the CIP at ACE;
•Favorable weather conditionsHigher depreciation expense at PECO, BGE, and DPL's Delaware service territory;PHI;
•Favorable volumeHigher credit loss expense at PECO;BGE and PHI;
•Higher storm costs at PHI; and
•Lower storm costsHigher interest expense at PECOPHI and DPL due to the absence of the June 2020 and August 2020 storms, respectively.Exelon Corporate.
Adjusted (non-GAAP) Operating Earnings. In addition to net income, Exelon evaluates its operating performance using the measure of Adjusted (non-GAAP) operating earnings because management believes it represents earnings directly related to the ongoing operations of the business. Adjusted (non-GAAP) operating earnings exclude certain costs, expenses, gains and losses, and other specified items. This information is intended to enhance an investor’s overall understanding of year-to-year operating results and provide an indication of Exelon’s baseline operating performance excluding items that are considered by management to be not directly related to the ongoing operations of the business. In addition, this information is among the primary indicators management uses as a basis for evaluating performance, allocating resources, setting incentive
compensation targets, and planning and forecasting of future periods. Adjusted (non-GAAP) operating earnings is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.
The following tables provide a reconciliation between net income attributable to common shareholders from continuing operations as determined in accordance with GAAP and adjusted (non-GAAP) operating earnings for the three and ninesix months ended SeptemberJune 30, 20212022 compared to the same period in 2020.2021.
152 | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | |
| Three Months Ended June 30, |
| 2022 | | 2021 |
| (In millions, except per share data) | | | Earnings per
Diluted Share | | | | Earnings per
Diluted Share |
| Net Income Attributable to Common Shareholders from Continuing Operations | $ | 465 | | | $ | 0.47 | | | $ | 326 | | | $ | 0.33 | |
| Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $1) | — | | | — | | | 3 | | | — | |
| Cost Management Program (net of taxes of $0) | — | | | — | | | 1 | | | — | |
COVID-19 Direct Costs (net of taxes of $1)(a) | — | | | — | | | 4 | | | — | |
Acquisition Related Costs (net of taxes of $1)(b) | — | | | — | | | 2 | | | — | |
ERP System Implementation Costs (net of taxes $1)(c) | — | | | — | | | 2 | | | — | |
Separation Costs (net of taxes of $4 and $6, respectively)(d) | 10 | | | 0.01 | | | 10 | | | 0.01 | |
Income Tax-Related Adjustments (entire amount represents tax expense)(e) | (43) | | | (0.04) | | | — | | | — | |
| Adjusted (non-GAAP) Operating Earnings | $ | 433 | | | $ | 0.44 | | | $ | 348 | | | $ | 0.36 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | |
| Three Months Ended September 30, |
| 2021 | | 2020 |
| (In millions, except per share data) | | | Earnings per
Diluted Share | | | | Earnings per
Diluted Share |
| Net Income Attributable to Common Shareholders | $ | 1,203 | | | $ | 1.23 | | | $ | 501 | | | $ | 0.51 | |
| Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $192 and $62, respectively) | (559) | | | (0.57) | | | (183) | | | (0.19) | |
Unrealized (Gains) Losses Related to NDT Fund Investments (net of taxes of $70 and $161, respectively)(a) | 55 | | | 0.06 | | | (172) | | | (0.18) | |
Asset Impairments (net of taxes of $11 and $126, respectively)(b) | 33 | | | 0.03 | | | 375 | | | 0.38 | |
Plant Retirements and Divestitures (net of taxes of $71 and $111, respectively)(c) | 211 | | | 0.22 | | | 329 | | | 0.34 | |
Cost Management Program (net of taxes of $1 and $5, respectively)(d) | 6 | | | 0.01 | | | 15 | | | 0.02 | |
| Change in Environmental Liabilities (net of taxes of $1 and $6, respectively) | 4 | | | — | | | 17 | | | 0.02 | |
COVID-19 Direct Costs (net of taxes of $1 and $3, respectively)(e) | 7 | | | 0.01 | | | 10 | | | 0.01 | |
| | | | | | | |
ERP System Implementation Costs (net of taxes $1)(h) | 4 | | | — | | | — | | | — | |
Planned Separation Costs (net of taxes of $10)(i) | 27 | | | 0.03 | | | — | | | — | |
Costs Related to Suspension of Contractual Offset (net of taxes of $33)(j) | 107 | | | 0.11 | | | — | | | — | |
Asset Retirement Obligation (net of taxes of $12 and $1, respectively)(k) | (35) | | | (0.04) | | | 3 | | | — | |
Acquisition Related Costs (net of taxes of $2 and $1, respectively)(g) | 7 | | | 0.01 | | | 2 | | | — | |
Income Tax-Related Adjustments (entire amount represents tax expense)(l) | 19 | | | 0.02 | | | 62 | | | 0.06 | |
Noncontrolling Interests (net of taxes of $5 and $12, respectively)(m) | (17) | | | (0.02) | | | 57 | | | 0.06 | |
| Adjusted (non-GAAP) Operating Earnings | $ | 1,070 | | | $ | 1.09 | | | $ | 1,017 | | | $ | 1.04 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, |
| 2021 | | 2020 |
| (In millions, except per share data) | | | Earnings per
Diluted Share | | | | Earnings per
Diluted Share |
| Net Income Attributable to Common Shareholders | $ | 1,315 | | | $ | 1.34 | | | $ | 1,604 | | | $ | 1.64 | |
| Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $317 and $112, respectively) | (924) | | | (0.94) | | | (329) | | | (0.34) | |
Unrealized (Gains) Losses Related to NDT Fund Investments (net of taxes of $24 and $31, respectively)(a) | (32) | | | (0.03) | | | 8 | | | 0.01 | |
Asset Impairments (net of taxes of $135 and $134, respectively)(b) | 401 | | | 0.41 | | | 396 | | | 0.40 | |
Plant Retirements and Divestitures (net of taxes of $290 and $117, respectively)(c) | 865 | | | 0.88 | | | 348 | | | 0.36 | |
Cost Management Program (net of taxes of $2 and $11, respectively)(d) | 10 | | | 0.01 | | | 34 | | | 0.03 | |
| | | | | | | |
| Change in Environmental Liabilities (net of taxes of $2 and $6, respectively) | 6 | | | 0.01 | | | 18 | | | 0.02 | |
COVID-19 Direct Costs (net of taxes of $9 and $13, respectively)(e) | 24 | | | 0.02 | | | 37 | | | 0.04 | |
Deferred Prosecution Agreement Payments (net of taxes of $0)(f) | — | | | — | | | 200 | | | 0.20 | |
| | | | | | | |
ERP System Implementation Costs (net of taxes of $2)(h) | 10 | | | 0.01 | | | — | | | — | |
Planned Separation Costs (net of taxes of $16)(i) | 46 | | | 0.05 | | | — | | | — | |
Costs Related to Suspension of Contractual Offset (net of taxes of $45)(j) | 148 | | | 0.15 | | | — | | | — | |
Asset Retirement Obligation (net of taxes of $12 and $1, respectively)(k)) | (35) | | | (0.04) | | | 3 | | | — | |
Acquisition Related Costs (net of taxes of $5 and $1, respectively)(g) | 15 | | | 0.02 | | | 2 | | | — | |
Income Tax-Related Adjustments (entire amount represents tax expense)(l) | 15 | | | 0.02 | | | 66 | | | 0.07 | |
Noncontrolling Interests (net of taxes of $2 and $2, respectively)(m) | 16 | | | 0.02 | | | 17 | | | 0.02 | |
| Adjusted (non-GAAP) Operating Earnings | $ | 1,879 | | | $ | 1.92 | | | $ | 2,403 | | | $ | 2.46 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Six Months Ended June 30, |
| 2022 | | 2021 |
| (In millions, except per share data) | | | Earnings per
Diluted Share | | | | Earnings per
Diluted Share |
| Net Income Attributable to Common Shareholders from Continuing Operations | $ | 946 | | | $ | 0.96 | | | $ | 851 | | | $ | 0.87 | |
| Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $1) | — | | | — | | | 3 | | | — | |
| Cost Program Management (net of taxes of $0) | — | | | — | | | 1 | | | — | |
COVID-19 Direct Costs (net of taxes of $3) (a) | — | | | — | | | 5 | | | 0.01 | |
Acquisition Related Costs (net of taxes of $3)(b) | — | | | — | | | 7 | | | 0.01 | |
ERP System Implementation Costs (net of taxes of $0 and $1, respectively)(c) | 1 | | | — | | | 7 | | | 0.01 | |
Separation Costs (net of taxes of $11 and $6, respectively)(d) | 27 | | | 0.03 | | | 15 | | | 0.02 | |
Income Tax-Related Adjustments (entire amount represents tax expense)(f) | 92 | | | 0.09 | | | (2) | | | — | |
| Adjusted (non-GAAP) Operating Earnings | $ | 1,065 | | | $ | 1.08 | | | $ | 887 | | | $ | 0.91 | |
__________
Note:
Amounts may not sum due to rounding.
Unless otherwise noted, the income tax impact of each reconciling item between GAAP Net Income from Continuing Operations and Adjusted (non-GAAP) Operating Earnings is based on the marginal statutory federal and state income tax rates for each Registrant, taking into account whether the income or expense item is taxable or deductible, respectively, in whole or in part. For all items except the unrealized gains and losses related to NDT fund investments, theThe marginal statutory income tax rates for 20212022 and 20202021 ranged from 25.0%24.0% to 29.0%. Under IRS regulations, NDT fund investment returns are taxed at different rates for investments if they are in qualified or non-qualified funds. The effective tax rates for the unrealized gains and losses related to NDT fund investments were 56.2% and 48.3% for the three months ended September 30, 2021 and 2020, respectively. The effective tax rates for the unrealized gains and losses related to NDT fund investments were 42.4% and 134.1% for the nine months ended September 30, 2021 and 2020, respectively.
(a)Reflects the impact of net unrealized gains and losses on Generation’s NDT fund investments for Non-Regulatory Agreement Units.
(b)In 2021, reflects an impairment in the New England asset group, an impairment recorded as a result of the agreement to sell the Albany Green Energy biomass facility, and an impairment of a wind project at Generation. In 2020, reflects an impairment at ComEd related to the acquisition of transmission assets and an impairment in the New England asset group in the third quarter of 2020.
(c)In 2021, primarily reflects accelerated depreciation and amortization associated with Generation's decisions to early retire Byron, Dresden, and Mystic Units 8 and 9, partially offset by reversal of one-time charges resulting from the reversal of the previous decision to retire Byron and Dresden on September 15, 2021 and a gain on sale of Generation's solar business.
Depreciation for Byron and Dresden was adjusted beginning September 15, 2021 to reflect the extended useful life estimates. In 2020, primarily reflects one-time charges and accelerated depreciation and amortization expenses associated with Generation’s decisions in the third quarter of 2020 to early retire Byron and Dresden nuclear facilities in 2021 and Mystic Units 8 and 9 in 2024.
(d)Primarily represents reorganization and severance costs related to cost management programs.
(e)Represents direct costs related to COVID-19 consisting primarily of costs to acquire personal protective equipment, costs for cleaning supplies and services, and costs to hire healthcare professionals to monitor the health of employees.employees, which are recorded in Operating and maintenance expense.
(f)(b)Reflects the payments made by ComEd under the Deferred Prosecution Agreement, which ComEd entered in July 2020 with the U.S. Attorney’s Office for the Northern District of Illinois.
(g)Reflectscertain BSC costs related to the acquisition of EDF'sElectricite de France SA's (EDF's) interest in CENG, which was completed in the third quarter of 2021.2021, that were historically allocated to Constellation Energy Generation, LLC
(Generation) but are presented as part of continuing operations in Exelon’s results as these costs do not qualify as expenses of the discontinued operations per the accounting rules.
(c)Reflects costs related to a multi-year Enterprise Resource Program (ERP) system implementation.implementation, which are recorded in Operating and maintenance expense.
(i)(d)Represents costs related to the planned separation primarily comprised of system-related costs, third-party costs paid to advisors, consultants, lawyers, and other experts assisting in the planned separation, and employee-related severance costs.costs, which are recorded in Operating and maintenance expense.
(j)(e)Decommissioning-related activities forIn connection with the former ComEd and PECO units (Regulatory Agreement Units), net of applicable taxes, including realized and unrealized gains and losses on the NDT funds, depreciation of the ARC, and accretion of the decommissioning obligation, are generally offset within Exelon’s and Generation’s consolidated statements of operations. These costs reflect theseparation, Exelon recorded a one-time impact of suspension of contractual offset for the Byron units beginning in the second quarter of 2021 through September 15, 2021. With Generation's September 15, 2021 reversal of the previous decision to retire Byron, Generation resumed contractual offset for Byron as of that date.associated with a state tax benefit.
(k)(f)For Generation, reflectsIn connection with the separation, Exelon recorded an adjustmentincome tax expense primarily due to the nuclear asset obligationlong-term marginal state income tax rate change, the recognition of valuation allowances against the net deferred tax assets positions for the Non-Regulatory Agreement Units resulting from the annual update in the third quarter of 2021.certain standalone state filing jurisdictions, and nondeductible transaction costs partially offset by a one-time impact associated with a state tax benefit.
(l)Primarily reflects the adjustment to deferred income taxes due to changes in forecasted apportionment.
(m)Represents elimination from Generation’s results of the noncontrolling interests related to certain exclusion items, primarily related to unrealized gains and losses on NDT fund investments for CENG units prior to Generation's acquisition of EDF's interest in CENG on August 6, 2021 and the noncontrolling interest portion of a wind project impairment.
Significant 20212022 Transactions and Developments
Planned Separation
On February 21, 2021, Exelon’s Board of Directors approved a plan to separate the Utility Registrants and Generation, creating two publicly traded companies with (“the resources necessary to best serve customersseparation”). Exelon completed the separation on February 1, 2022. Constellation was newly formed and sustain long-term investmentincorporated in Pennsylvania on June 15, 2021 for the purpose of separation and operating excellence.holds Generation. The separation gives each company therepresented a strategic shift that would have a major effect on Exelon’s operations and financial and strategic independence to focus on its specific customer needs, while executing its core business strategy.
On February 25, 2021, Exelon and Generation filed applications with FERC, NYPSC, and NRC seeking approvals forresults. Accordingly, the separation of Generation. On March 25, 2021, Exelon filed a requestmeets the criteria for a private letter ruling with the IRS to confirm the tax-free treatmentdiscontinued operations. See Note 2 — Discontinued Operations of the plannedCombined Notes to Consolidated Financial Statements for additional information on the separation which was received on September 23, 2021. On August 24, 2021, Exelon and Generation received approval from FERC for the planned separation. Exelon and Generation expect a decision from the NRC in the fourth quarter of 2021 and have requested a decision from the NYPSC before the end of 2021. Exelon and Generation cannot predict if the remaining applications will be approved as filed.discontinued operations.
In connection with the planned separation, Exelon incurred transactionseparation costs impacting continuing operations of approximately $36$14 million and $64$16 million on a pre-tax basis for the three and nine months ended SeptemberJune 30, 2022 and 2021, respectively, and $38 million and $21 million on a pre-tax basis for the six months ended June 30, 2022 and 2021, respectively, which are recorded in Operating and maintenance expense. Total separation costs impacting continuing operations for the remainder of 2022 are not expected to be material. These costs are excluded from Adjusted (non-GAAP) Operating Earnings. The transactionseparation costs are primarily comprised of system-related costs, third-party costs paid to advisors, consultants, lawyers, and other experts assisting in the planned separation, and employee-related severance costs.
There can be no assurance that any separation transaction will ultimately occur or, if one does occur, of its terms or timing. See Note 20 — Planned Separation of the Combined Notes to Consolidated Financial Statements for additional information.
CENG Put Option
EDF had the option to sell its 49.99% equity interest in CENG to Generation exercisable beginning on January 1, 2016 and thereafter until June 30, 2022. On November 20, 2019, Generation received notice of EDF’s intention to exercise the put option and sell its 49.99% equity interest in CENG to Generation and the put automatically exercised on January 19, 2020 at the end of the sixty-day advance notice period. On August 6, 2021, Generation and EDF entered into a settlement agreement pursuant to which Generation, through a wholly owned subsidiary, purchased EDF’s equity interest in CENG for a net purchase price of $885 million, which includes, among other things, an adjustment for EDF’s share of the balance of the preferred distribution payable by CENG to
Generation. The difference between the net purchase price and EDF’s noncontrolling interest as of the closing date was recorded to Common Stock in Exelon’s Consolidated Balance Sheet and Membership Interest in Generation’s Consolidated Balance Sheet.
In connection with the settlement agreement, on August 6, 2021, Generation issued approximately $880 million under a term loan credit agreement to fund the transaction, which will expire on August 5, 2022.
See Note 2 – Mergers, Acquisitions, and Dispositions and Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.
Clean Energy Law
On September 15, 2021, the Illinois Public Act 102-0662 was signed into law by the Governor of Illinois (“Clean Energy Law”). The Clean Energy Law is designed to achieve 100% carbon-free power by 2045 to enable the state’s transition to a clean energy economy. The Clean Energy Law establishes decarbonization requirements for Illinois as well as programs to support the retention and development of emissions-free sources of electricity. Among other things, the Clean Energy Law authorizes the IPA to procure up to 54.5 million CMCs from qualifying nuclear plants for a five-year period beginning on June 1, 2022 through May 31, 2027. CMCs are credits for the carbon-free attributes of eligible nuclear power plants in PJM. The Byron, Dresden, and Braidwood nuclear plants located in Illinois will be eligible to participate in the CMC procurement process and, if awarded contracts, would be committed to operate through May 31, 2027. Selected generators will by December 3, 2021 contract directly with ComEd for the procurement of the CMCs based upon the number of MWhs produced annually by the eligible facilities, subject to specified caps and minimum performance requirements. ComEd is required to purchase CMCs from eligible nuclear facilities and all its costs of doing so will be recovered through a new rider.
Following enactment of the Clean Energy Law, Generation announced on September 15, 2021, that it has reversed its previous decision to retire Byron and Dresden given the opportunity for additional revenue. In addition, Generation no longer considers the Braidwood or LaSalle nuclear plants to be at risk for premature retirement. See Note 7 – Early Plant Retirements for additional information and Early Retirement of Generation Facilities below.
The Clean Energy Law also contains requirements associated with ComEd’s transition away from the performance-based electric distribution formula rate. The law authorizing that rate setting process sunsets at the end of 2022. The Clean Energy Law, and tariffs adopted under it, governs both the remaining reconciliations of rates set under that process and requires ComEd to file in 2023 its choice of either a general rate case or a four-year multi-year plan to set rates that take effect in 2024. If ComEd elects to file a multi-year plan, that plan would set rates for 2024 – 2027, based on forecasted revenue requirements and an ICC determined rate of return on rate base, including the cost of common equity. See Note 3 – Regulatory Matters for additional information and other features of the Clean Energy Law.
Early Retirement of Generation Facilities
In August 2020, Generation announced that it intended to retire the Byron Generating Station in September 2021, Dresden Generating Station in November 2021, and Mystic Units 8 and 9 at the expiration of the cost of service commitment in May 2024. As a result, Exelon and Generation recognized certain one-time charges in the third and fourth quarters of 2020.Further, there were ongoing annual financial impacts stemming from shortening the expected economic useful lives of these facilities, primarily related to accelerated depreciation of plant assets (including any ARC) and accelerated amortization of nuclear fuel.
Also, as a result, in the third quarter of 2020, Exelon and Generation recognized a $500 million pre-tax impairment for the New England asset group. In the second quarter of 2021, an incremental decline in value resulted in an additional pre-tax impairment charge of $350 million for the New England asset group.
Further, in the second quarter and third quarter of 2021, Exelon and Generation recorded a pre-tax charge of $53 million and $140 million, respectively for decommissioning-related activities that were not offset for the Byron units due to the inability to recognize a regulatory asset at ComEd.
All of the charges above were excluded from Exelon's and Generation’s Adjusted (non-GAAP) Operating Earnings.
On September 15, 2021, Generation reversed its previous decision to early retire Byron and Dresden and updated the expected economic useful life for both facilities to 2044 and 2046 for Byron Units 1 and 2, respectively, and to 2029 and 2031 for Dresden Units 2 and 3, respectively. Depreciation was therefore adjusted beginning September 15, 2021, to reflect these extended useful life estimates. In addition, in the third quarter of 2021, Exelon and Generation reversed approximately $81 million of severance benefit costs and $13 million of other one-time charges initially recorded in the third and fourth quarters of 2020 associated with the early retirements, which were excluded from Exelon's and Generation’s Adjusted (non-GAAP) Operating Earnings.
The following table summarizes the incremental expense for Byron, Dresden, and Mystic Units 8 and 9 and the reversal of one-time charges for Byron and Dresden recorded in the three and nine months ended September 30, 2021. For Mystic Units 8 and 9, the projected amounts for the remainder of 2021 and through the retirement date of 2024 are not expected to be material.
| | | | | | | | | | | |
| Income statement expense (pre-tax) | Three Months Ended September 30, 2021 | | Nine Months Ended September 30, 2021 |
| Depreciation and amortization | | | |
Accelerated depreciation(a) | $ | 574 | | | $ | 1,845 | |
| Accelerated nuclear fuel amortization | 42 | | | 148 | |
| Operating and maintenance | | | |
| Reversal of one-time charges | (94) | | | (94) | |
| Other charges | 4 | | | 8 | |
| | | |
Contractual offset(b) | (60) | | | (451) | |
| Total | $ | 466 | | | $ | 1,456 | |
| | | |
__________
(a)Reflects incremental accelerated depreciation of plant assets, including any ARC.
(b)Reflects contractual offset for ARO accretion, ARC depreciation, and net impacts associated with the remeasurement of the ARO for Byron and Dresden and exclude any changes in earnings in the NDT funds. Decommissioning-related activities were not offset for the Byron units starting in the second quarter of 2021 due to the inability to recognize a regulatory asset at ComEd. With Generation’s September 15, 2021 reversal of the previous decision to retire Byron, Generation resumed contractual offset for Byron as of that date. Based on the regulatory agreement with the ICC, decommissioning-related activities are offset in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income as long as the net cumulative decommissioning-related activities result in a regulatory liability at ComEd. Recognition of a regulatory asset for nuclear decommissioning-related activities at ComEd is not permissible. The offset results in an equal adjustment to the noncurrent payables to ComEd at Generation and an adjustment to the regulatory liabilities at ComEd.
See Note 7 — Early Plant Retirements, Note 8 — Nuclear Decommissioning, and Note 9 - Asset Impairments of the Combined Notes to Consolidated Financial Statements for additional information.
Impacts of the February 2021 Extreme Cold Weather Event and Texas-based Generating Assets Outages
Beginning on February 15, 2021, Generation’s Texas-based generating assets within the ERCOT market, specifically Colorado Bend II, Wolf Hollow II, and Handley, experienced outages as a result of extreme cold weather conditions. In addition, those weather conditions drove increased demand for service, dramatically increased wholesale power prices, and also increased gas prices in certain regions.
The estimated impact to Exelon’s and Generation’s Net income for the nine months ended September 30, 2021 arising from these market and weather conditions was a reduction of approximately $880 million. The estimated impact to Exelon's and Generation's Net income for the three months ended September 30, 2021 was not material. The nine months ended estimated impact includes certain charges associated with the natural gas business that may be reduced through waivers and/or recoveries from customers. Therefore, such charges are not included in the estimated full year earnings impact. Exelon and Generation estimate a reduction in Net income of approximately $670 million to $820 million for the full year 2021. The ultimate impact to Exelon’s and Generation’s consolidated financial statements may be affected by a number of factors, the impacts of customer and counterparty credit losses, any state or federal solutions to address the financial challenges caused by the event, and related litigation and contract disputes. See Note 3 — Regulatory Matters and Note 15 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.
Exelon expects to offset between $410 million and $490 million of this impact for the full year 2021 primarily at Generation through a combination of enhanced revenue opportunities, deferral of selected non-essential maintenance, and primarily one-time cost savings.
Agreement for the Sale of a Generation Biomass Facility
On April 28, 2021, Generation and ReGenerate entered into a purchase agreement, under which ReGenerate agreed to purchase Generation's interest in the Albany Green Energy biomass facility. As a result, in the second quarter of 2021, Exelon and Generation recorded a pre-tax impairment charge of $140 million which is excluded from Exelon’s and Generation’s Adjusted (non-GAAP) Operating Earnings. The sale was completed on June 30, 2021 for a net purchase price of $36 million. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information.
Utility Rates andDistribution Base Rate Case Proceedings
The Utility Registrants file base rate cases with their regulatory commissions seeking increases or decreases to their electric transmission and distribution, and gas distribution rates to recover their costs and earn a fair return on their investments. The outcomes of these regulatory proceedings impact the Utility Registrants’ current and future financial statements.
The following tables show the Utility Registrants’ completed and pending distribution base rate case proceedings in 2021.2022. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on these and other regulatory proceedings.
Completed Distribution Base Rate Case Proceedings
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Registrant/Jurisdiction | | Filing Date | | Service | | Requested Revenue Requirement (Decrease) Increase | | Approved Revenue Requirement (Decrease) Increase | | Approved ROE | | Approval Date | | Rate Effective Date |
| ComEd - Illinois | | April 16, 2020 | | Electric | | $ | (11) | | | $ | (14) | | | 8.38 | % | | December 9, 2020 | | January 1, 2021 |
| PECO - Pennsylvania | | September 30, 2020 | | Natural Gas | | 69 | | | 29 | | | 10.24 | % | | June 22, 2021 | | July 1, 2021 |
| BGE - Maryland | | May 15, 2020 (amended September 11, 2020) | | Electric | | 203 | | | 140 | | | 9.50 | % | | December 16, 2020 | | January 1, 2021 |
| | Natural Gas | | 108 | | | 74 | | | 9.65 | % | | |
| Pepco - District of Columbia | | May 30, 2019 (amended June 1, 2020) | | Electric | | 136 | | | 109 | | | 9.275 | % | | June 8, 2021 | | July 1, 2021 |
| Pepco - Maryland | | October 26, 2020 (amended March 31, 2021) | | Electric | | 104 | | | 52 | | | 9.55 | % | | June 28, 2021 | | June 28, 2021 |
| DPL - Delaware | | March 6, 2020 (amended February 2, 2021) | | Electric | | 23 | | | 14 | | | 9.60 | % | | September 15, 2021 | | October 6, 2020 |
| ACE - New Jersey | | December 9, 2020 (amended February 26, 2021) | | Electric | | 67 | | | 41 | | | 9.60 | % | | July 14, 2021 | | January 1, 2022 |
Completed Distribution Base Rate Case Proceedings
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Registrant/Jurisdiction | | Filing Date | | Service | | Requested Revenue Requirement Increase | | Approved Revenue Requirement Increase | | Approved ROE | | Approval Date | | Rate Effective Date |
| ComEd - Illinois | | April 16, 2021 | | Electric | | $ | 51 | | | $ | 46 | | | 7.36 | % | | December 1, 2021 | | January 1, 2022 |
| PECO - Pennsylvania | | March 30, 2021 | | Electric | | 246 | | | 132 | | | N/A | | November 18, 2021 | | January 1, 2022 |
| BGE - Maryland | | May 15, 2020 (amended September 11, 2020) | | Electric | | 203 | | | 140 | | | 9.50 | % | | December 16, 2020 | | January 1, 2021 |
| | Natural Gas | | 108 | | | 74 | | | 9.65 | % | | |
| Pepco - District of Columbia | | May 30, 2019 (amended June 1, 2020) | | Electric | | 136 | | | 109 | | | 9.275 | % | | June 8, 2021 | | July 1, 2021 |
| Pepco - Maryland | | October 26, 2020 (amended March 31, 2021) | | Electric | | 104 | | | 52 | | | 9.55 | % | | June 28, 2021 | | June 28, 2021 |
| DPL - Maryland | | September 1, 2021 (amended December 23, 2021) | | Electric | | 27 | | | 13 | | | 9.60 | % | | March 2, 2022 | | March 2, 2022 |
| ACE - New Jersey | | December 9, 2020 (amended February 26, 2021) | | Electric | | 67 | | | 41 | | | 9.60 | % | | July 14, 2021 | | January 1, 2022 |
Pending Distribution Base Rate Case Proceedings
| | Registrant/Jurisdiction | Registrant/Jurisdiction | | Filing Date | | Service | | Requested Revenue Requirement Increase | | Requested ROE | | Expected Approval Timing | Registrant/Jurisdiction | | Filing Date | | Service | | Requested Revenue Requirement Increase | | Requested ROE | | Expected Approval Timing |
| ComEd - Illinois | ComEd - Illinois | | April 16, 2021 | | Electric | | $ | 51 | | | 7.36 | % | | Fourth quarter of 2021 | ComEd - Illinois | | April 15, 2022 | | Electric | | $ | 199 | | | 7.85 | % | | Fourth quarter of 2022 |
| | PECO - Pennsylvania | PECO - Pennsylvania | | March 30, 2021 | | Electric | | 246 | | | 10.95 | % | | Fourth quarter of 2021 | PECO - Pennsylvania | | March 31, 2022 | | Natural Gas | | 82 | | | 10.95 | % | | Fourth quarter of 2022 |
| | DPL - Delaware | | DPL - Delaware | | January 14, 2022 (amended February 28, 2022) | | Natural Gas | | 15 | | | 10.30 | % | | First quarter of 2023 |
| DPL - Maryland | DPL - Maryland | | September 1, 2021 | | Electric | | 29 | | | 10.10 | % | | First quarter of 2022 | DPL - Maryland | | May 19, 2022 | | Electric | | 38 | | | 10.25 | % | | Fourth quarter of 2022 |
|
Transmission Formula Rates
TheFor 2022, the following total increases/(decreases) were included in the Utility Registrants' 2021 electric transmission formula rate updates. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
| | Registrant | Registrant | Initial Revenue Requirement Increase (Decrease) | Annual Reconciliation Increase | Total Revenue Requirement Increase | Allowed Return on Rate Base | Allowed ROE | Registrant | | Initial Revenue Requirement Increase | | Annual Reconciliation (Decrease) Increase | | Total Revenue Requirement Increase | | Allowed Return on Rate Base | | Allowed ROE |
| ComEd | ComEd | $ | 33 | | $ | 12 | | $ | 45 | | 8.20 | % | 11.50 | % | ComEd | | $ | 24 | | | $ | (24) | | | $ | — | | | 8.11 | % | | 11.50 | % |
| PECO | PECO | (2) | | 26 | | 24 | | 7.37 | % | 10.35 | % | PECO | | 23 | | | 16 | | | 39 | | | 7.30 | % | | 10.35 | % |
| BGE | BGE | 38 | | 27 | | 65 | | 7.35 | % | 10.50 | % | BGE | | 25 | | | (4) | | | 16 | | | 7.30 | % | | 10.50 | % |
| Pepco | Pepco | (9) | | 21 | | 12 | | 7.68 | % | 10.50 | % | Pepco | | 16 | | | 15 | | | 31 | | | 7.60 | % | | 10.50 | % |
| DPL | DPL | 19 | | 33 | | 52 | | 7.20 | % | 10.50 | % | DPL | | 9 | | | 2 | | | 11 | | | 7.09 | % | | 10.50 | % |
| ACE | ACE | 27 | | 24 | | 51 | | 7.45 | % | 10.50 | % | ACE | | 21 | | | 13 | | | 34 | | | 7.18 | % | | 10.50 | % |
Pennsylvania Corporate Income Tax Rate Change
On July 8, 2022, Pennsylvania enacted House Bill 1342, which will permanently reduce the corporate income tax rate from 9.99% to 4.99%. The tax rate will be reduced to 8.99% for the 2023 tax year. Starting with the 2024 tax year, the rate is reduced by 0.5% annually until it reaches 4.99% in 2031. As a result of the rate change, in the third quarter of 2022, Exelon and PECO will record an estimated one-time decrease to deferred income taxes of $390 million with a corresponding decrease to the deferred income taxes regulatory asset of $428 million for the amounts that are expected to be settled through future customer rates and an increase to income tax expense of $38 million (net of federal taxes), which will be excluded from Adjusted (non-GAAP) Operating Earnings. See Note 7 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.
Other Key Business Drivers and Management Strategies
The following discussion of other key business driverdrivers and management strategies includes current developments of previously disclosed matters and new issues arising during the period that may impact future financial statements. This section should be read in conjunction with ITEM 1. Business andin the 2021 Form 10-K, ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations — Other Key Business Drivers and Management Strategies in the Registrants' combined 20202021 Recast Form 10-K, and Note 1512 — Commitments and Contingencies of the Combined Notes to the Consolidated Financial Statements in this report for additional information on various environmental matters.
Power MarketsLegislative and Regulatory Developments
Complaint at FERC Seeking to Alter Capacity Market Default Offer CapsInfrastructure Investment and Jobs Act
On February 21, 2019, PJM's Independent Market Monitor (IMM) filedNovember 15, 2021, President Biden signed the $1.2 trillion Infrastructure Investment and Jobs Act (IIJA) into law. IIJA provides for approximately $550 billion in new federal spending. Categories of funding include funding for a complaint alleging thatvariety of infrastructure needs, including but not limited to: (1) power and grid reliability and resilience, (2) resilience for cybersecurity to address critical infrastructure needs, and (3) electric vehicle charging infrastructure for alternative fuel corridors. Federal agencies are in the numberprocess of performance assessment intervals useddeveloping guidelines to calculateimplement spending programs under IIJA. The time needed to develop these guidelines will vary with some limited program applications opened as early as the default offer capfirst quarter of 2022. The Registrants are analyzing the legislation and considering possible opportunities to apply for bids to supply capacityfunding, either directly or in PJM is too high, resultingpotential collaborations with state and/or local agencies and key stakeholders. The Registrants cannot predict the ultimate timing and success of securing funding from programs under IIJA.
Inflation Reduction Act
On July 27, 2022, the Inflation Reduction Act was introduced in the U.S. Senate. The bill extends tax benefits for renewable technologies like solar and wind and it creates new tax benefits for alternative clean energy sources like nuclear and hydrogen and it focuses on energy efficiency, electrification, and equity. However, the bill also implements a new 15% corporate minimum tax based on modified GAAP net income. Exelon estimates the bill could result in an overstated default offer cap that obviatesincrease in cash taxes for Exelon of approximately $300 million per year starting in 2023 if enacted as proposed. Exelon is continuing to assess the need for most sellers to seek unit-specific approvalimpacts of their offers. The IMM argued that this allows for the exercise of market power. The IMM asked FERC to require PJM to reduce the number of performance assessment intervals used to calculate the opportunity costs of a capacity supplier assuming a capacity obligation. This would, in turn, lower the default offer cap and allow the IMM to review more offers on a unit-specific basis. Several consumer advocates filed a complaint seeking similar relief several months after the IMM’s complaint. On March 18, 2021, FERC granted the complaints, finding the current estimate of performance assessment intervals to be excessive compared to the reasonably expected number of performance assessment intervals which results in an unjust and unreasonable default offer cap. FERC did not establish the number of performance assessment intervals that should be used to calculate the default offer cap and instead requested briefsbill on the matter, including alternative approaches to mitigation in the capacity market.financial statements. Exelon submitted an initialis working with legislators and reply briefs on May 3, 2021 and June 9, 2021, respectively, and an answer to briefs filed by other parties on June 24, 2021. On September 2, 2021, FERC issued an order adopting the IMM’s unit-specific avoidable cost offer review methodology and directed PJM to submit a compliance filing establishing new deadlines for offer review and related other activities leading up to the base residual auction for the 2023-2024 planning year and an additional compliance filing revising the PJM Tariff to comply with FERC’s order. Exelon filed at FERC for rehearing on this matter on October 4, 2021. Generation cannot predict the outcome of these proceedings or the financial statement impact.
Hedging Strategy
Exelon’s policy to hedge commodity risk on a ratable basis over three-year periods is intended to reduce the financial impact of market price volatility. Generation is exposed to commodity price risk associated with the unhedged portion of its electricity portfolio. Generation enters into non-derivative and derivative contracts, including financially-settled swaps, futures contracts and swap options, and physical options and physical forward contracts, all with credit-approved counterparties, to hedge this anticipated exposure. As of September 30, 2021, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York, and ERCOT reportable segments is 96%-99% for the remainder of 2021. Generation has been and will continue to be proactive in using hedging strategies to mitigate commodity price risk.
Generation procures natural gas through long-term and short-term contracts and spot-market purchases. Nuclear fuel assemblies are obtained predominantly through long-term uranium concentrate supply contracts, contracted conversion services, contracted enrichment services, or a combination thereof, and contracted fuel fabrication services. The supply markets for uranium concentrates and certain nuclear fuel services are subject to price fluctuations and availability restrictions. Approximately 60% of Generation’s uranium concentrate requirements from 2021 through 2025 are supplied by three suppliers. In the event of non-performance by these or other suppliers, Generation believes that replacement uranium concentrate can be obtained, although at prices that may be unfavorable when compared to the prices under the current supply agreements. Non-performance by these counterparties could have a material adverse impact on Exelon’s and Generation’s consolidated financial statements.
See Note 12 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements and ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for additional information.
The Utility Registrants mitigate commodity price risk through regulatory mechanisms that allow them to recover procurement costs from retail customers.
Environmental Regulation
Exelon is well positioned to support increasingly ambitious government climate policy and to partner with our customers and communities to reduce GHG emissions.
In August 2021, the Utility Registrants announced a “path to clean” goal to collectively reduce their operations-driven emissions 50% by 2030 against a 2015 baseline, and to reach net zero operations-driven emissions by 2050. This goal builds upon Exelon’s long-standing commitment to reducing our GHG emissions. The Utility Registrants “path to clean” will include efficiency and clean electricity for operations, vehicle fleet electrification, equipment and processes to reduce sulfur hexafluoride (SF6) leakage, modern natural gas infrastructure to minimize methane leaks and increase safety and reliability, and investment and collaboration to develop new technologies.
Generation produces electricity predominantly from low- and zero-carbon generating facilities (such as nuclear, hydroelectric, natural gas, wind, and solar PV) and neither owns nor operates any coal-fueled generating assets. Generation’s natural gas fired generating plants produce GHG emissions, most notably CO2. However, Generation’s owned-asset emission intensity, or rate of carbon dioxide equivalent (CO2e) emitted per unit of electricity generated, is among the lowest in the industry.
The United States has set an economy-wide target of reducing its net GHG emissions by 50-52% below 2005 levels by 2030.
Other Legislative and Regulatory Developments
FERC Supplemental Notice of Proposed Rulemaking
On April 15, 2021, FERC issued a Supplemental Notice of Proposed Rulemaking (NOPR) proposing to modify the current regulation permitting a continuous 50-basis-point ROE incentive adder for a transmission utility that joins and remains a member of a RTO. Under the NOPR, the ROE incentive adder would only be available for a period of up to three years after a transmission utility newly joins a RTO and all existing ROE incentive adders would end for transmission utilities that have been members for three or more years. The Utility Registrants’ existing transmission rates include the ROE incentive adder. Exelon submitted comments to FERC on this matter on June 25, 2021. Exelon cannot predict the outcome, but a final rule as proposed could have an adverse impact to Exelon’s and the Utility Registrants’ financial statements. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information regarding the Utility Registrants’ transmission formula rates and regulatory proceedings at FERC.
City of Chicago Franchise Agreement
ComEd has had a Franchise Agreement with the City of Chicago (the City) since 1992. The Franchise Agreement grants rights to use the public right of way to install, maintain, and operate the wires, poles, and other infrastructure required to deliver electricity to residents and businesses across the City. The Franchise Agreement became terminable on one year notice as of December 31, 2020. It now continues in effect indefinitely unless and until either party issues a notice of termination, effective one year later, or it is replaced by mutual agreement with a new franchise agreement between ComEd and the City. If either party terminates and no new agreement is reached between the parties, the parties could continue with ComEd providing electric services within the City with no franchise agreement in place. The City also has an option to terminate and purchase the ComEd system (“municipalize”), which also requires one year notice. Neither party has issued a notice of termination at this time, the City has not exercised its municipalization option, and no new agreement has been reached. Accordingly, the 1992 Franchise Agreement remains in effect at this time. In April 2021, the City invited interested parties to respond to a Request for Information (RFI) regarding the franchise for electricity delivery. Under this process, the City could choose to terminate the ComEd Franchise Agreement on one year notice and grant a franchise to another party instead. Final responses to the RFI were due on July 30, 2021, however, on July 29, 2021, the City chose to extend the final submission deadline to September 30, 2021. ComEd submitted its response to the RFI by the due date and looks forward to continuing engagement with the City about its response. While Exelon and ComEd cannot predict the ultimate outcome of the RFI and the
Franchise Agreement, fundamental changes in the agreement or other adverse actions affecting ComEd’s business in the City would require changes in their business planning models and operations and could have a material adverse impact on Exelon’s and ComEd’s consolidated financial statements. If the City were to disconnect from the ComEd system, ComEd would seek full compensation for the business and its associated property taken by the City, as well as for all damages resulting to ComEd and its system. ComEd would also seek appropriate compensation for stranded costs with FERC.
Employees
In the second quarter of 2021, Generation and PECO ratified CBAs as follows:
•Generation ratified its CBA with UGSOA, which covers 73 security officers at Three Mile Island. The CBA will expire in 2023.
•PECO ratified two CBAs with IBEW Local 614 which covers 1,140 operations employees and 185 customer service employees, respectively. Both CBAs expire in 2026.
In the third quarter of 2021, Generation ratified its CBA with the National Union of Nuclear Security Officers, which covers 88 security officers at Braidwood. The CBA will expire in 2024.legislation.
Critical Accounting Policies and Estimates
Management of each of the Registrants makes a number of significant estimates, assumptions, and judgments in the preparation of its financial statements. At SeptemberJune 30, 2021,2022, the Registrants’ critical accounting policies and estimates had not changed significantly from December 31, 2020.2021. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Critical Accounting Policies and Estimates in the Registrants' 20202021 Recast Form 10-K for further information.
Results of Operations by Registrant
Results of Operations — Generation
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended
September 30, | | (Unfavorable)
Favorable
Variance | | Nine Months Ended
September 30, | |
Favorable
(Unfavorable)
Variance |
| 2021 | | 2020 | | | 2021 | | 2020 | |
| Operating revenues | $ | 4,406 | | | $ | 4,659 | | | $ | (253) | | | $ | 14,117 | | | $ | 13,272 | | | $ | 845 | |
| Operating expenses | | | | | | | | | | | |
| Purchased power and fuel | 1,546 | | | 2,314 | | | 768 | | | 8,103 | | | 6,961 | | | (1,142) | |
| Operating and maintenance | 938 | | | 1,737 | | | 799 | | | 3,413 | | | 4,188 | | | 775 | |
| Depreciation and amortization | 866 | | | 558 | | | (308) | | | 2,735 | | | 1,161 | | | (1,574) | |
| Taxes other than income taxes | 115 | | | 118 | | | 3 | | | 354 | | | 364 | | | 10 | |
| Total operating expenses | 3,465 | | | 4,727 | | | 1,262 | | | 14,605 | | | 12,674 | | | (1,931) | |
| | | | | | | | | | | |
| Gain on sales of assets and businesses | 65 | | | — | | | 65 | | | 144 | | | 12 | | | 132 | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| Operating income (loss) | 1,006 | | | (68) | | | 1,074 | | | (344) | | | 610 | | | (954) | |
| Other income and (deductions) | | | | | | | | | | | |
| Interest expense, net | (77) | | | (80) | | | 3 | | | (225) | | | (277) | | | 52 | |
| Other, net | (115) | | | 367 | | | (482) | | | 561 | | | 199 | | | 362 | |
| Total other income and (deductions) | (192) | | | 287 | | | (479) | | | 336 | | | (78) | | | 414 | |
| Income (loss) before income taxes | 814 | | | 219 | | | 595 | | | (8) | | | 532 | | | (540) | |
| Income taxes | 177 | | | 100 | | | (77) | | | 108 | | | 41 | | | (67) | |
| Equity in losses of unconsolidated affiliates | (4) | | | (2) | | | (2) | | | (6) | | | (6) | | | — | |
| Net income (loss) | 633 | | | 117 | | | 516 | | | (122) | | | 485 | | | (607) | |
| Net income (loss) attributable to noncontrolling interests | 26 | | | 68 | | | (42) | | | 125 | | | (85) | | | 210 | |
| Net income (loss) attributable to membership interest | $ | 607 | | | $ | 49 | | | $ | 558 | | | $ | (247) | | | $ | 570 | | | $ | (817) | |
Three Months Ended September 30, 2021 Compared to Three Months Ended September 30, 2020. Net income attributable to membership interest increased by $558 million primarily due to:
•Absence of an impairment in the New England asset group;
•Absence of one time charges recorded in the third quarter of 2020 associated with Generation's decision to early retire the Byron and Dresden nuclear facilities and Mystic Units 8 and 9, and the
reversal of one-time charges resulting from the reversal of the previous decision to early retire Byron and Dresden on September 15, 2021;
•Higher mark-to-market gains; and
•Higher New York ZEC revenues due to higher generation and an increase in ZEC prices.
The increases were partially offset by:
•Lower net unrealized and realized gains on NDT funds;
•Decommissioning-related activities that were not offset for the Byron units beginning in the second quarter of 2021 through September 15, 2021. With Generation's September 15, 2021 reversal of the previous decision to retire Byron, Generation resumed contractual offset for Byron as of that date;
•Accelerated depreciation and amortization associated with Generation's previous decision in the third quarter of 2020 to early retire Byron and Dresden nuclear facilities in 2021, a decision which was reversed on September 15, 2021, and Generation's decision in the third quarter of 2020 to early retire Mystic Units 8 and 9 in 2024; and
•Higher net unrealized and realized losses on equity investments.
Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020.Net income attributable to membership interest decreased by $817 million primarily due to:
•Impacts of the February 2021 extreme cold weather event;
•Accelerated depreciation and amortization associated with Generation's previous decision in the third quarter of 2020 to early retire Byron and Dresden nuclear facilities in 2021, a decision which was reversed on September 15, 2021, and Generation's decision in the third quarter of 2020 to early retire Mystic Units 8 and 9 in 2024;
•Decommissioning-related activities that were not offset for the Byron units beginning in the second quarter of 2021 through September 15, 2021. With Generation's September 15, 2021 reversal of the previous decision to retire Byron, Generation resumed contractual offset for Byron as of that date;
•Impairments of the New England asset group, the Albany Green Energy biomass facility at Generation, and a wind project at Generation, partially offset by the absence of an impairment of the New England asset group in the third quarter of 2020; and
•The absence of a prior year one-time tax settlement.
The decreases were partially offset by:
•Higher mark-to-market gains;
•Higher net unrealized and realized gains on NDT funds;
•Absence of one time charges recorded in the third quarter of 2020 associated with Generation's decision to early retire the Byron and Dresden nuclear facilities and Mystic Units 8 and 9, and the reversal of one-time charges resulting from the reversal of the previous decision to early retire Byron and Dresden on September 15, 2021;
•Lower nuclear outage days; and
•Higher New York ZEC revenues due to higher generation and an increase in ZEC prices.
Operating revenues. The basis for Generation's reportable segments is the integrated management of its electricity business that is located in different geographic regions, and largely representative of the footprints of ISO/RTO and/or NERC regions, which utilize multiple supply sources to provide electricity through various distribution channels (wholesale and retail). Generation's hedging strategies and risk metrics are also aligned
with these same geographic regions. Generation's five reportable segments are Mid-Atlantic, Midwest, New York, ERCOT, and Other Power Regions. See Note 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for additional information on these reportable segments.
The following business activities are not allocated to a region and are reported under Other: natural gas, as well as other miscellaneous business activities that are not significant to overall operating revenues or results of operations.
For the three and nine months ended September 30, 2021 compared to 2020, Operating revenues by region were as follows:
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| Three Months Ended
September 30, | | Variance | | % Change(a) | | Nine Months Ended
September 30, | | Variance | | % Change(a) |
| 2021 | | 2020 | | | 2021 | | 2020 | |
Mid-Atlantic(b) | $ | 1,272 | | | $ | 1,313 | | | $ | (41) | | | (3.1) | % | | $ | 3,527 | | | $ | 3,561 | | | $ | (34) | | | (1.0) | % |
Midwest(c) | 985 | | | 1,043 | | | (58) | | | (5.6) | % | | 2,945 | | | 3,007 | | | (62) | | | (2.1) | % |
| New York | 455 | | | 406 | | | 49 | | | 12.1 | % | | 1,173 | | | 1,061 | | | 112 | | | 10.6 | % |
| ERCOT | 358 | | | 330 | | | 28 | | | 8.5 | % | | 890 | | | 754 | | | 136 | | | 18.0 | % |
| Other Power Regions | 1,260 | | | 1,109 | | | 151 | | | 13.6 | % | | 3,729 | | | 2,984 | | | 745 | | | 25.0 | % |
| Total electric revenues | 4,330 | | | 4,201 | | | 129 | | | 3.1 | % | | 12,264 | | | 11,367 | | | 897 | | | 7.9 | % |
| Other | 711 | | | 421 | | | 290 | | | 68.9 | % | | 2,811 | | | 1,667 | | | 1,144 | | | 68.6 | % |
| Mark-to-market (losses) gains | (635) | | | 37 | | | (672) | | | | | (958) | | | 238 | | | (1,196) | | | |
| Total Operating revenues | $ | 4,406 | | | $ | 4,659 | | | $ | (253) | | | (5.4) | % | | $ | 14,117 | | | $ | 13,272 | | | $ | 845 | | | 6.4 | % |
__________
(a)% Change in mark-to-market is not a meaningful measure.
(b)Includes results of transactions with PECO, BGE, Pepco, DPL, and ACE.
(c)Includes results of transactions with ComEd.
Supply Sources. Generation’s supply sources by region are summarized below:
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| Three Months Ended
September 30, | | Variance | | % Change | | Nine Months Ended
September 30, | | Variance | | % Change |
| Supply Source (GWhs) | 2021 | | 2020 | | | 2021 | | 2020 | |
Nuclear Generation(a) | | | | | | | | | | | | | | | |
| Mid-Atlantic | 13,753 | | | 13,679 | | | 74 | | | 0.5 | % | | 40,203 | | | 39,630 | | | 573 | | | 1.4 | % |
| Midwest | 23,909 | | | 24,471 | | | (562) | | | (2.3) | % | | 70,363 | | | 71,929 | | | (1,566) | | | (2.2) | % |
| New York | 7,188 | | | 6,734 | | | 454 | | | 6.7 | % | | 21,323 | | | 19,296 | | | 2,027 | | | 10.5 | % |
| Total Nuclear Generation | 44,850 | | | 44,884 | | | (34) | | | (0.1) | % | | 131,889 | | | 130,855 | | | 1,034 | | | 0.8 | % |
| Fossil and Renewables | | | | | | | | | | | | | | | |
| Mid-Atlantic | 491 | | | 304 | | | 187 | | | 61.5 | % | | 1,675 | | | 1,864 | | | (189) | | | (10.1) | % |
| Midwest | 177 | | | 196 | | | (19) | | | (9.7) | % | | 763 | | | 852 | | | (89) | | | (10.4) | % |
| New York | — | | | 1 | | | (1) | | | (100.0) | % | | 1 | | | 3 | | | (2) | | | (66.7) | % |
| ERCOT | 4,670 | | | 4,394 | | | 276 | | | 6.3 | % | | 10,250 | | | 10,658 | | | (408) | | | (3.8) | % |
| Other Power Regions | 2,409 | | | 2,794 | | | (385) | | | (13.8) | % | | 7,641 | | | 8,905 | | | (1,264) | | | (14.2) | % |
| Total Fossil and Renewables | 7,747 | | | 7,689 | | | 58 | | | 0.8 | % | | 20,330 | | | 22,282 | | | (1,952) | | | (8.8) | % |
| Purchased Power | | | | | | | | | | | | | | | |
| Mid-Atlantic | 4,565 | | | 8,252 | | | (3,687) | | | (44.7) | % | | 12,123 | | | 17,924 | | | (5,801) | | | (32.4) | % |
| Midwest | 77 | | | 71 | | | 6 | | | 8.5 | % | | 386 | | | 595 | | | (209) | | | (35.1) | % |
| | | | | | | | | | | | | | | |
| ERCOT | 595 | | | 1,104 | | | (509) | | | (46.1) | % | | 2,626 | | | 3,351 | | | (725) | | | (21.6) | % |
| Other Power Regions | 13,585 | | | 14,512 | | | (927) | | | (6.4) | % | | 38,778 | | | 37,981 | | | 797 | | | 2.1 | % |
| Total Purchased Power | 18,822 | | | 23,939 | | | (5,117) | | | (21.4) | % | | 53,913 | | | 59,851 | | | (5,938) | | | (9.9) | % |
| Total Supply/Sales by Region | | | | | | | | | | | | | | | |
Mid-Atlantic(b) | 18,809 | | | 22,235 | | | (3,426) | | | (15.4) | % | | 54,001 | | | 59,418 | | | (5,417) | | | (9.1) | % |
Midwest(b) | 24,163 | | | 24,738 | | | (575) | | | (2.3) | % | | 71,512 | | | 73,376 | | | (1,864) | | | (2.5) | % |
| New York | 7,188 | | | 6,735 | | | 453 | | | 6.7 | % | | 21,324 | | | 19,299 | | | 2,025 | | | 10.5 | % |
| ERCOT | 5,265 | | | 5,498 | | | (233) | | | (4.2) | % | | 12,876 | | | 14,009 | | | (1,133) | | | (8.1) | % |
| Other Power Regions | 15,994 | | | 17,306 | | | (1,312) | | | (7.6) | % | | 46,419 | | | 46,886 | | | (467) | | | (1.0) | % |
| Total Supply/Sales by Region | 71,419 | | | 76,512 | | | (5,093) | | | (6.7) | % | | 206,132 | | | 212,988 | | | (6,856) | | | (3.2) | % |
__________
(a)Includes the proportionate share of output where Generation has an undivided ownership interest in jointly-owned generating plants. Includes the total output for fully owned plants and the total output for CENG prior to the acquisition of EDF’s interest on August 6, 2021 as CENG was fully consolidated. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information on Generation’s acquisition of EDF’s interest in CENG.
(b)Includes affiliate sales to PECO, BGE, Pepco, DPL, and ACE in the Mid-Atlantic region and affiliate sales to ComEd in the Midwest region.
Nuclear Fleet Capacity Factor. The following table presents nuclear fleet operating data for the Generation-operated plants, which reflects ownership percentage of stations operated by Exelon, excluding Salem, which is operated by PSEG. The nuclear fleet capacity factor presented in the table is defined as the ratio of the actual output of a plant over a period of time to its output if the plant had operated at full average annual mean capacity for that time period. Generation considers capacity factor to be a useful measure to analyze the nuclear fleet performance between periods. Generation has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, these measures are not a presentation defined under
GAAP and may not be comparable to other companies’ presentations or be more useful than the GAAP information provided elsewhere in this report.
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| Three Months Ended
September 30, | | Nine Months Ended
September 30, |
| 2021 | | 2020 | | 2021 | | 2020 |
| Nuclear fleet capacity factor | 96.0 | % | | 96.0 | % | | 95.0 | % | | 95.1 | % |
| Refueling outage days | 22 | | | 17 | | | 172 | | | 203 | |
| Non-refueling outage days | — | | | 4 | | | 10 | | | 15 | |
ZEC Prices. Generation is compensated through state programs for the carbon-free attributes of its nuclear generation. ZEC prices have a significant impact on Operating revenues. The following table presents the average ZEC prices ($/MWh) for each of Generation's major regions in which state programs have been enacted. Prices reflect the weighted average price for the various delivery periods within each calendar year.
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| | Three Months Ended
September 30, | | Variance | | % Change | | Nine Months Ended
September 30, | | Variance | | % Change |
| State (Region) | | 2021 | | 2020 | | | 2021 | | 2020 | |
| New Jersey (Mid-Atlantic) | | $ | 10.00 | | | $ | 10.00 | | | $ | — | | | — | % | | $ | 10.00 | | | $ | 10.00 | | | $ | — | | | — | % |
| Illinois (Midwest) | | 16.50 | | | 16.50 | | | — | | | — | % | | 16.50 | | | 16.50 | | | — | | | — | % |
| New York (New York) | | 21.38 | | | 19.59 | | | 1.79 | | | 9.1 | % | | 20.78 | | | 19.59 | | | 1.19 | | | 6.1 | % |
Capacity Prices. Generation participates in capacity auctions in each of its major regions, except ERCOT which does not have a capacity market. Generation also incurs capacity costs associated with load served, except in ERCOT. Capacity prices have a significant impact on Generation's operating revenues and purchased power and fuel. The following table presents the average capacity prices ($/MW Day) for each of Generation's major regions. Prices reflect the weighted average price for the various auction periods within each calendar year.
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| | Three Months Ended
September 30, | | Variance | | % Change | | Nine Months Ended
September 30, | | Variance | | % Change |
| Location (Region) | | 2021 | | 2020 | | | 2021 | | 2020 | |
| Eastern Mid-Atlantic Area Council (Mid-Atlantic and Midwest) | | $ | 165.73 | | | $ | 187.87 | | | $ | (22.14) | | | (11.8) | % | | $ | 178.03 | | | $ | 159.50 | | | $ | 18.53 | | | 11.6 | % |
| ComEd (Midwest) | | 195.55 | | | 188.12 | | | 7.43 | | | 3.9 | % | | 191.42 | | | 194.22 | | | (2.80) | | | (1.4) | % |
| Rest of State (New York) | | 160.44 | | | 89.30 | | | 71.14 | | | 79.7 | % | | 94.12 | | | 54.32 | | | 39.80 | | | 73.3 | % |
| Southeast New England (Other) | | 154.37 | | | 176.67 | | | (22.30) | | | (12.6) | % | | 166.76 | | | 200.69 | | | (33.93) | | | (16.9) | % |
Electricity Prices. The price of electricity has a significant impact on Generation's operating revenues and purchased power cost. The following table presents the average day-ahead around-the-clock price ($/MWh) for each of Generation's major regions.
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| | Three Months Ended
September 30, | | Variance | | % Change | | Nine Months Ended
September 30, | | Variance | | % Change |
| Location (Region) | | 2021 | | 2020 | | | 2021 | | 2020 | |
| PJM West (Mid-Atlantic) | | $ | 41.77 | | | $ | 22.75 | | | $ | 19.02 | | | 83.6 | % | | $ | 33.70 | | | $ | 20.24 | | | $ | 13.46 | | | 66.5 | % |
| ComEd (Midwest) | | 39.68 | | | 20.98 | | | 18.70 | | | 89.1 | % | | 31.76 | | | 18.57 | | | 13.19 | | | 71.0 | % |
| Central (New York) | | 36.27 | | | 19.53 | | | 16.74 | | | 85.7 | % | | 26.58 | | | 16.33 | | | 10.25 | | | 62.8 | % |
| North (ERCOT) | | 42.67 | | | 27.14 | | | 15.53 | | | 57.2 | % | | 182.23 | | | 21.83 | | | 160.40 | | | 734.8 | % |
Southeast Massachusetts (Other)(a) | | 45.23 | | | 22.95 | | | 22.28 | | | 97.1 | % | | 41.54 | | | 21.26 | | | 20.28 | | | 95.4 | % |
__________
(a)Reflects New England, which comprises the majority of the activity in the Other region.
For the three and nine months ended September 30, 2021 compared to 2020, changes in Operating revenues by region were approximately as follows:
| | | | | | | | | | | | | | | | | | | | |
| | | | | | |
| Variance | % Change(a) | Three Months Ended
September 30, 2021 | Variance | % Change(a) | Nine Months Ended
September 30, 2021 |
| Mid-Atlantic | $ | (41) | | (3.1) | % | • unfavorable wholesale load revenue of $(185) primarily due to lower volumes; partially offset by
• favorable settled economic hedges of $120 due to settled prices relative to hedged prices
• favorable retail load revenue of $20 primarily due to higher prices | $ | (34) | | (1.0) | % | • unfavorable wholesale load revenue of $(370) primarily due to lower volumes; partially offset by
• favorable settled economic hedges of $305 due to settled prices relative to hedged prices
• favorable retail load revenue of $35 primarily due to higher prices |
| Midwest | (58) | | (5.6) | % | • unfavorable settled economic hedges of $(185) due to settled prices relative to hedged prices; partially offset by
• favorable net wholesale load and generation revenue of $120 due to higher load volumes and higher prices, partially offset by decreased generation due to higher nuclear outage days | (62) | | (2.1) | % | • unfavorable settled economic hedges of $(375) due to settled prices relative to hedged prices; partially offset by
• favorable net wholesale load and generation revenue of $315 primarily due to higher prices, partially offset by decreased generation due to higher nuclear outage days |
| New York | 49 | | 12.1 | % | • favorable nuclear generation revenue of $20 primarily due to lower outage days and higher prices
• favorable ZEC revenue of $25 due to higher prices and higher nuclear generation
| 112 | | 10.6 | % | • favorable nuclear generation revenue of $40 primarily due to lower outage days and higher prices
• favorable ZEC revenue of $65 due to higher prices and higher nuclear generation |
| ERCOT | 28 | | 8.5 | % | • favorable settled economic hedges of $65 due to settled prices relative to hedged prices; partially offset by
• unfavorable wholesale load revenue of $(15) primarily due to lower volumes | 136 | | 18.0 | % | • favorable retail load revenue of $120 primarily due to higher prices in part due to the February 2021 extreme cold weather event |
| Other Power Regions | 151 | | 13.6 | % | • favorable retail load revenue of $175 due to higher prices and higher volumes
• favorable settled economic hedges of $110 due to settled prices relative to hedged prices; partially offset by
• unfavorable wholesale load revenue of $(155) primarily due to lower volumes | 745 | | 25.0 | % | • favorable settled economic hedges of $520 due to settled prices relative to hedged prices
• favorable retail load revenue of $400 due to higher prices and higher volumes; partially offset by
• unfavorable wholesale load revenue of $(205) primarily due to lower volumes |
| Other | 290 | | 68.9 | % | • favorable gas revenue of $250 primarily due to higher prices | 1,144 | | 68.6 | % | • favorable gas revenue of $1,060 primarily due to higher prices in part due to the February 2021 extreme cold weather event
|
Mark-to-market(b) | (672) | | | • losses on economic hedging activities of $(635) in 2021 compared to gains of $37 in 2020 | (1,196) | | | • losses on economic hedging activities of $(958) in 2021 compared to gains of $238 in 2020 |
| Total | $ | (253) | | (5.4) | % | | $ | 845 | | 6.4 | % | |
__________
(a)% Change in mark-to-market is not a meaningful measure.
(b)See Note 12 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on mark-to-market gains and losses.
Purchased power and fuel. See Operating revenues above for discussion of Generation's reportable segments and hedging strategies and for supplemental statistical data, including supply sources by region, nuclear fleet capacity factor, capacity prices, and electricity prices.
The following business activities are not allocated to a region and are reported under Other: natural gas, as well as other miscellaneous business activities that are not significant to overall purchased power and fuel expense or results of operations, and accelerated nuclear fuel amortization associated with nuclear decommissioning.
For the three and nine months ended September 30, 2021 compared to 2020, Purchased power and fuel by region were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended
September 30, | | Variance | | % Change(a) | | Nine Months Ended
September 30, | | Variance | | % Change(a) |
| 2021 | | 2020 | | | 2021 | | 2020 | |
Mid-Atlantic(b) | $ | 702 | | | $ | 722 | | | $ | 20 | | | 2.8 | % | | $ | 1,815 | | | $ | 1,878 | | | $ | 63 | | | 3.4 | % |
Midwest(c) | 330 | | | 293 | | | (37) | | | (12.6) | % | | 930 | | | 829 | | | (101) | | | (12.2) | % |
| New York | 109 | | | 121 | | | 12 | | | 9.9 | % | | 293 | | | 336 | | | 43 | | | 12.8 | % |
| ERCOT | 179 | | | 183 | | | 4 | | | 2.2 | % | | 1,812 | | | 429 | | | (1,383) | | | (322.4) | % |
| Other Power Regions | 1,049 | | | 884 | | | (165) | | | (18.7) | % | | 3,165 | | | 2,446 | | | (719) | | | (29.4) | % |
| Total electric purchased power and fuel | 2,369 | | | 2,203 | | | (166) | | | (7.5) | % | | 8,015 | | | 5,918 | | | (2,097) | | | (35.4) | % |
| Other | 566 | | | 329 | | | (237) | | | (72.0) | % | | 2,288 | | | 1,277 | | | (1,011) | | | (79.2) | % |
| Mark-to-market gains | (1,389) | | | (218) | | | 1,171 | | | | | (2,200) | | | (234) | | | 1,966 | | | |
| Total purchased power and fuel | $ | 1,546 | | | $ | 2,314 | | | $ | 768 | | | 33.2 | % | | $ | 8,103 | | | $ | 6,961 | | | $ | (1,142) | | | (16.4) | % |
__________
(a)% Change in mark-to-market is not a meaningful measure.
(b)Includes results of transactions with PECO, BGE, Pepco, DPL, and ACE.
(c)Includes results of transactions with ComEd.
For the three and nine months ended September 30, 2021 compared to 2020, changes in Purchased power and fuel by region were approximately as follows:
| | | | | | | | | | | | | | | | | | | | |
| | | | | | |
| Variance | % Change(a) | Three Months Ended
September 30, 2021 | Variance | % Change(a) | Nine Months Ended
September 30, 2021 |
| Mid-Atlantic | $ | 20 | | 2.8 | % | • no significant changes
| $ | 63 | | 3.4 | % | • favorable purchased power and net capacity impact of $45 primarily due to lower load and higher capacity prices earned partially offset by lower cleared capacity volumes
• favorable settlement of economic hedges of $40 due to settled prices relative to hedged prices |
| Midwest | (37) | | (12.6) | % | • unfavorable purchased power of $(35) primarily due to lower nuclear generation due to higher nuclear outage days, higher energy prices, and higher load | (101) | | (12.2) | % | • unfavorable purchased power and net capacity impact of $(140) primarily due to lower nuclear generation due to higher nuclear outage days, higher energy prices, lower cleared capacity volumes, and lower capacity prices |
| New York | 12 | | 9.9 | % | • no significant changes
| 43 | | 12.8 | % | • favorable settlement of economic hedges of $70 due to settled prices relative to hedged prices; partially offset by
• unfavorable purchased power and net capacity impact of $(35) primarily due to higher energy prices partially offset by higher capacity prices earned |
| ERCOT | 4 | | 2.2 | % | • favorable purchased power of $85 primarily due to a favorable recovery related to the February 2021 extreme cold weather event and lower load; partially offset by
• unfavorable settlement of economic hedges of $(75) due to settled prices relative to hedged prices
| (1,383) | | (322.4) | % | • unfavorable purchased power of $(750) primarily due to higher energy prices primarily during the February 2021 extreme cold weather event
• unfavorable settlement of economic hedges of $(460) due to settled prices relative to hedged prices
• unfavorable fuel cost of $(150) primarily due to higher gas prices |
| Other Power Regions | (165) | | (18.7) | % | • unfavorable purchased power and net capacity impact of $(190) primarily due to lower generation, higher energy prices, and lower cleared capacity volumes; partially offset by
• favorable settlement of economic hedges of $45 due to settled prices relative to hedged prices | (719) | | (29.4) | % | • unfavorable purchased power and net capacity impact of $(680) primarily due to higher load, lower generation, higher energy prices, lower cleared capacity volumes, and lower capacity prices
• unfavorable RPS expense of $(55) primarily due to higher prices and higher load
• unfavorable fuel cost of $(40) primarily due to higher gas prices; partially offset by
• favorable settlement of economic hedges of $80 due to settled prices relative to hedged prices |
| Other | (237) | | (72.0) | % | • unfavorable net gas purchase costs and settlement of economic hedges of $(190)
• unfavorable accelerated nuclear fuel amortization associated with announced early plant retirements of $(20) | (1,011) | | (79.2) | % | • unfavorable net gas purchase costs and settlement of economic hedges of $(830)
• unfavorable accelerated nuclear fuel amortization associated with announced early plant retirements of $(125) |
Mark-to-market(b) | 1,171 | | | • gains on economic hedging activities of $1,389 in 2021 compared to gains of $218 in 2020 | 1,966 | | | • gains on economic hedging activities of $2,200 in 2021 compared to gains of $234 in 2020 |
| Total | $ | 768 | | 33.2 | % | | $ | (1,142) | | (16.4) | % | |
__________
(a)% Change in mark-to-market is not a meaningful measure.
(b)See Note 12 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on mark-to-market gains and losses.
The changes in Operating and maintenance expenseconsisted of the following:
| | | | | | | | | | | |
| Three Months Ended
September 30, 2021 | | Nine Months Ended September 30, 2021 |
| | (Decrease) Increase | | Increase (Decrease) |
| Asset impairments | $ | (456) | | | $ | 23 | |
Plant retirements and divestitures(a) | (314) | | | (706) | |
| ARO update | (49) | | | (49) | |
| Labor, other benefits, contracting, and materials | (25) | | | (29) | |
| Change in environmental liabilities | (18) | | | (18) | |
| Cost management program | (12) | | | (24) | |
| Corporate allocations | (8) | | | (19) | |
| Credit loss expense | 3 | | | 46 | |
| Acquisition related costs | 6 | | | 17 | |
| Separation costs | 16 | | | 25 | |
| Nuclear refueling outage costs, including the co-owned Salem plants | 17 | | | (70) | |
| Other | 41 | | | 29 | |
| Total decrease | $ | (799) | | | $ | (775) | |
__________
(a)Primarily reflects contractual offset of accelerated depreciation and amortization associated with Generation's previous decision to early retire the Byron and Dresden nuclear facilities. See Note 8 — Nuclear Decommissioning of the Combined Notes to Consolidated Financial Statements for additional information.
Depreciation and amortization expense increased for the three and nine months ended September 30, 2021 compared to the same period in 2020, primarily due to the accelerated depreciation and amortization associated with Generation's previous decision to early retire the Byron and Dresden nuclear facilities. This decision was reversed on September 15, 2021 and depreciation for Byron and Dresden was adjusted beginning September 15, 2021 to reflect the extended useful life estimates. A portion of this accelerated depreciation and amortization is offset in Operating and maintenance expense.
Gain on sales of assets and businessesincreased for the three and nine months ended September 30, 2021 compared to the same period in 2020, primarily due to gains on sales of equity investments that became publicly traded entities in the fourth quarter of 2020 and the first half of 2021, and additionally increased for the nine months ended September 30, 2021 compared to the same period in 2020, due to a gain on sale of Generation's solar business.
Interest expense, net decreased for the nine months ended September 30, 2021 compared to the same period in 2020, primarily due to mark-to-market gains related to the EGR IV interest swaps entered into in December 2020 and decreases in interest rates. See Note 17 — Debt and Credit Agreements of the Exelon 2020 Form 10-K for additional information on the interest swaps.
Other, net decreased for the three months ended September 30, 2021 compared to the same period in 2020 and increased for the nine months ended September 30, 2021 compared to the same period in 2020, due to activity described in the table below:
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended
September 30, | | Nine Months Ended
September 30, |
| 2021 | | 2020 | | 2021 | | 2020 |
Net unrealized (losses) gains on NDT funds(a) | $ | (94) | |
| $ | 254 | | | $ | 33 | | | $ | 1 | |
Net realized gains on sale of NDT funds(a) | 101 | | | — | | | 349 | | | 58 | |
Interest and dividend income on NDT funds(a) | 26 | | | 23 | | | 73 | | | 69 | |
Contractual elimination of income tax expense(b) | 11 | | | 89 | | | 150 | | | 46 | |
Net unrealized losses from equity investments(c) | (179) | | | — | | | (83) | | | — | |
| Other | 20 | | | 1 | | | 39 | | | 25 | |
| Total other, net | $ | (115) | | | $ | 367 | | | $ | 561 | | | $ | 199 | |
__________
(a)Unrealized (losses) gains, realized gains, and interest and dividend income on the NDT funds are associated with the Non-Regulatory Agreement Units.
(b)Contractual elimination of income tax expense is associated with the income taxes on the NDT funds of the Regulatory Agreement units.
(c)Net unrealized losses from equity investments that became publicly traded entities in the fourth quarter of 2020 and the first half of 2021.
Effective income tax rates were 21.7% and 45.7% for the three months ended September 30, 2021 and 2020, respectively, and (1,350.0)% and 7.7% for the nine months ended September 30, 2021 and 2020, respectively. See Note 10 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.
Net income attributable to noncontrolling interests decreased for the three months ended September 30, 2021 compared to the same period in 2020, primarily due to lower net gains on NDT fund investments for CENG prior to Generation's acquisition of EDF's interest in CENG on August 6, 2021, and the noncontrolling portion of a wind project impairment, and increased for the nine months ended September 30, 2021 compared to the same period in 2020, primarily due to higher net gains on NDT fund investments for CENG prior to Generation's acquisition of EDF's interest in CENG on August 6, 2021, partially offset by the noncontrolling portion of a wind project impairment.
Results of Operations — ComEd
| | | Three Months Ended
September 30, | | Favorable
(Unfavorable)
Variance | | Nine Months Ended
September 30, | | Favorable
(Unfavorable)
Variance | | Three Months Ended
June 30, | | Favorable
(Unfavorable)
Variance | | Six Months Ended
June 30, | | Favorable
(Unfavorable)
Variance |
| | 2021 | | 2020 | | 2021 | | 2020 | | | 2022 | | 2021 | | 2022 | | 2021 | |
| Operating revenues | Operating revenues | $ | 1,789 | | | $ | 1,643 | | | $ | 146 | | | $ | 4,840 | | | $ | 4,499 | | | $ | 341 | | Operating revenues | $ | 1,425 | | | $ | 1,517 | | | $ | (92) | | | $ | 3,158 | | | $ | 3,052 | | | $ | 106 | |
| Operating expenses | Operating expenses | | Operating expenses | |
| Purchased power | Purchased power | 703 | | | 606 | | | (97) | | | 1,728 | | | 1,557 | | | (171) | | Purchased power | 283 | | | 500 | | | 217 | | | 921 | | | 1,025 | | | 104 | |
| Operating and maintenance | Operating and maintenance | 330 | | | 321 | | | (9) | | | 969 | | | 1,173 | | | 204 | | Operating and maintenance | 338 | | | 323 | | | (15) | | | 689 | | | 639 | | | (50) | |
| Depreciation and amortization | Depreciation and amortization | 304 | | | 294 | | | (10) | | | 893 | | | 841 | | | (52) | | Depreciation and amortization | 328 | | | 296 | | | (32) | | | 649 | | | 589 | | | (60) | |
| Taxes other than income taxes | Taxes other than income taxes | 91 | | | 81 | | | (10) | | | 243 | | | 227 | | | (16) | | Taxes other than income taxes | 90 | | | 77 | | | (13) | | | 185 | | | 153 | | | (32) | |
| Total operating expenses | Total operating expenses | 1,428 | | | 1,302 | | | (126) | | | 3,833 | | | 3,798 | | | (35) | | Total operating expenses | 1,039 | | | 1,196 | | | 157 | | | 2,444 | | | 2,406 | | | (38) | |
| | Loss on sales of assets | | Loss on sales of assets | (2) | | | — | | | (2) | | | (2) | | | — | | | (2) | |
| Operating income | Operating income | 361 | | | 341 | | | 20 | | | 1,007 | | | 701 | | | 306 | | Operating income | 384 | | | 321 | | | 63 | | | 712 | | | 646 | | | 66 | |
| Other income and (deductions) | Other income and (deductions) | | | | | | | | | | | | Other income and (deductions) | | | | | | | | | | | |
| Interest expense, net | Interest expense, net | (98) | | | (95) | | | (3) | | | (292) | | | (287) | | | (5) | | Interest expense, net | (104) | | | (98) | | | (6) | | | (204) | | | (193) | | | (11) | |
| Other, net | Other, net | 13 | | | 10 | | | 3 | | | 35 | | | 32 | | | 3 | | Other, net | 13 | | | 15 | | | (2) | | | 26 | | | 22 | | | 4 | |
| Total other income and (deductions) | Total other income and (deductions) | (85) | | | (85) | | | — | | | (257) | | | (255) | | | (2) | | Total other income and (deductions) | (91) | | | (83) | | | (8) | | | (178) | | | (171) | | | (7) | |
| Income before income taxes | Income before income taxes | 276 | | | 256 | | | 20 | | | 750 | | | 446 | | | 304 | | Income before income taxes | 293 | | | 238 | | | 55 | | | 534 | | | 475 | | | 59 | |
| Income taxes | Income taxes | 56 | | | 60 | | | 4 | | | 141 | | | 142 | | | 1 | | Income taxes | 66 | | | 46 | | | (20) | | | 119 | | | 85 | | | (34) | |
| Net income | Net income | $ | 220 | | | $ | 196 | | | $ | 24 | | | $ | 609 | | | $ | 304 | | | $ | 305 | | Net income | $ | 227 | | | $ | 192 | | | $ | 35 | | | $ | 415 | | | $ | 390 | | | $ | 25 | |
|
Three Months Ended SeptemberJune 30, 20212022 Compared to Three Months Ended SeptemberJune 30, 2020.2021. Net income increased by $24$35 million as compared to the same period in 2020,2021, primarily due to increasedincreases in electric distribution formula rate earnings (reflecting the impacts of higher rate base and higher allowed electric distribution ROE due to an increase in treasury rates)rates and the impacts of higher rate base).
NineSix Months Ended SeptemberJune 30, 20212022 Compared to NineSix Months Ended SeptemberJune 30, 2020.2021. Net incomeincreased by $305$25 million as compared to the same period in 2020,2021, primarily due to increases in electric distribution formula rate earnings (reflecting the impacts of higher rate base and higher allowed electric distribution ROE due to an increase in treasury rates)rates and payments that ComEd madethe impacts of higher rate base) partially offset by the voluntary customer refund related to the ICC investigation of matters identified in 2020 under the Deferred Prosecution Agreement. See Note 15 -12 — Commitments and Contingencies of the Combined Notes to the Consolidated Financial Statements for additional information related to the Deferred Prosecution Agreement.information.
The changes in Operating revenues consisted of the following:
| | | Three Months Ended
September 30, 2021 | | Nine Months Ended
September 30, 2021 | | Three Months Ended
June 30, 2022 | | Six Months Ended
June 30, 2022 |
| | Increase | | Increase | | Increase (Decrease) | | Increase (Decrease) |
| Distribution | Distribution | $ | 25 | | | $ | 98 | | Distribution | $ | 65 | | | $ | 110 | |
| Transmission | Transmission | 10 | | | 14 | | Transmission | 17 | | | 38 | |
| Energy efficiency | Energy efficiency | 10 | | | 34 | | Energy efficiency | 14 | | | 20 | |
| Other | Other | 8 | | | 20 | | Other | — | | | 3 | |
| | | 53 | | | 166 | | | 96 | | | 171 | |
| Regulatory required programs | Regulatory required programs | 93 | | | 175 | | Regulatory required programs | (188) | | | (65) | |
| Total increase | Total increase | $ | 146 | | | $ | 341 | | Total increase | $ | (92) | | | $ | 106 | |
Revenue Decoupling. The demand for electricity is affected by weather conditions and customer usage. Operating revenues are not impacted by abnormal weather, usage per customer, or number of customers as a result of the revenue decoupling mechanisms as allowed byimplemented pursuant to FEJA.
Distribution Revenue. EIMA and FEJA provide for a performance-based formula rate, which requires an annual reconciliation of the revenue requirement in effect to the actual costs that the ICC determines are prudently and reasonably incurred in a given year. Electric distribution revenue varies from year to year based upon fluctuations in the underlying costs, (e.g., severe weather and storm restoration), investments being recovered, and allowed ROE. Electric distribution revenue increased for the three and ninesix months ended SeptemberJune 30, 20212022 as
compared to the same period in 2020,2021, due to higher allowed ROE due to an increase in treasury rates, and the impact of a higher rate base.base, and higher fully recoverable costs.
Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered, and the highest daily peak load, which is updated annually in January based on the prior calendar year. Generally, increases/decreases in the highest daily peak load will result in higher/lower transmission revenue. Transmission revenue increased for the three and ninesix months ended SeptemberJune 30, 20212022 as compared to the same periodsperiod in 20202021 primarily due to the impact of a higher rate base.base and higher fully recoverable costs.
Energy Efficiency Revenue. FEJA provides for a performance-based formula rate, which requires an annual reconciliation of the revenue requirement in effect to the actual costs that the ICC determines are prudently and reasonably incurred in a given year. UnderUnder FEJA, energy efficiency revenue varies from year to year based upon fluctuationsfluctuations in the underlying costs, investments being recovered, and allowed ROE. Energy efficiency revenue remained relatively consistentincreased for the three and six months ended SeptemberJune 30, 20212022 as compared to the same period in 2020. Energy efficiency revenue increased during the nine months ended September 30, 2021, as compared to the same period in 2020, primarily due to increased regulatory asset amortization, which is fully recoverable.
Other Revenue primarily includes assistance provided to other utilities through mutual assistance programs. Other revenue increasedremained relatively the same for the three and ninesix months ended SeptemberJune 30, 20212022 as compared to the same period in 2020, which primarily reflects mutual assistance revenues associated with storm restoration efforts.2021.
Regulatory Required Programs represents revenues collected under approved riders to recover costs incurred for regulatory programs such as recoveries under the credit loss expense tariff, environmental costs associated with MGP sites, Energy Transition Assistance Charge ("ETAC"), and costs related to electricity, ZEC, CMC, and REC procurement. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information regarding CMCs. ETAC is a retail customer surcharge collected by electric utilities operating in Illinois established by CEJA and remitted to an Illinois state agency for programs to support clean energy jobs and training. The riders are designed to provide full and current cost recovery. The costs of these programs are included in Purchased power expense, Operating and maintenance expense, Depreciation and amortization expense and Taxes other than income. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries as ComEd remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation from competitive suppliers, ComEd either acts as the billing agent or the competitive supplier separately bills its own customers, and therefore ComEd does not record Operating revenues or Purchased power expense related to the electricity. For customers that choose to purchase electric generation from ComEd, ComEd is permitted to recover the electricity, ZEC, CMC, and REC procurement costs without mark-up and therefore records equal and offsetting amounts in Operating revenues and Purchased power expense related to the electricity, ZECs, CMCs, and RECs.
See Note 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ComEd's revenue disaggregation.
The increasedecrease of $97$217 million and of $171$104 million for the three and ninesix months ended SeptemberJune 30, 20212022 compared to the same period in 2020, respectively,2021, in Purchased power expenseis offset in Operating revenues as part of regulatory required programs.
The changes in Operating and maintenance expense consisted of the following:
| | | Three Months Ended
September 30, 2021 | | Nine Months Ended
September 30, 2021 | | Three Months Ended
June 30, 2022 | | Six Months Ended
June 30, 2022 |
| | Increase (Decrease) | | (Decrease) Increase | | (Decrease) Increase | | (Decrease) Increase |
Deferred Prosecution Agreement payments(a) | $ | — | | | $ | (200) | | |
| | Storm-related costs | Storm-related costs | 4 | | | (10) | | Storm-related costs | $ | (1) | | | $ | — | |
| Pension and non-pension postretirement benefits expense | Pension and non-pension postretirement benefits expense | 1 | | | 3 | | Pension and non-pension postretirement benefits expense | (7) | | | (14) | |
| Labor, other benefits, contracting and materials | Labor, other benefits, contracting and materials | (4) | | | 6 | | Labor, other benefits, contracting and materials | 9 | | | 11 | |
| | BSC costs | BSC costs | 6 | | | 11 | | BSC costs | 9 | | | 22 | |
| Other(b)(a) | Other(b)(a) | (3) | | | (25) | | Other(b)(a) | 4 | | | 26 | |
| | 4 | | | (215) | | | 14 | | | 45 | |
Regulatory required programs(c)(b) | Regulatory required programs(c)(b) | 5 | | | 11 | | Regulatory required programs(c)(b) | 1 | | | 5 | |
| Total increase (decrease) | $ | 9 | | | $ | (204) | | |
| Total increase | | Total increase | $ | 15 | | | $ | 50 | |
__________
(a)For the six months ended June 30, 2022, the increase is primarily due to the voluntary customer refund related to the ICC investigation of matters identified in the Deferred Prosecution Agreement. See Note 15 -12 — Commitments and Contingenciesof the Combined Notes to the Consolidated Financial Statements for additional information.
(b)Primarily reflects the absence of an impairment chargeinformation related to the acquisition of transmission assets in 2020.Deferred Prosecution Agreement.
(c)(b)ComEd is allowed to recover from or refund to customers the difference between its annual credit loss expense and the amounts collected in rates annually through a rider mechanism.
The changes in Depreciation and amortization expense consisted of the following:
| | | Three Months Ended
September 30, 2021 | | Nine Months Ended
September 30, 2021 | | Three Months Ended
June 30, 2022 | | Six Months Ended
June 30, 2022 |
| | Increase (Decrease) | | Increase | | Increase | | Increase |
Depreciation and amortization(a) | Depreciation and amortization(a) | $ | 12 | | | $ | 36 | | Depreciation and amortization(a) | $ | 19 | | | $ | 33 | |
Regulatory asset amortization(b) | Regulatory asset amortization(b) | (2) | | | 16 | | Regulatory asset amortization(b) | 13 | | | 27 | |
| | Total increase | Total increase | $ | 10 | | | $ | 52 | | Total increase | $ | 32 | | | $ | 60 | |
__________
(a)Reflects ongoing capital expenditures.
(b)Includes amortization of ComEd's energy efficiency formula rate regulatory assetasset.
Taxes other than income taxes increased by $13 million and amortizationby $32 million for the three and six months ended June 30, 2022, respectively, compared to the same period in 2021, primarily due to taxes related to the August 2020 storm regulatory asset.ETAC, which is recovered through Operating revenues.
Effective income tax rates were 20.3%22.5% and 23.4%19.3% for the three months ended SeptemberJune 30, 20212022 and 2020,2021, respectively, and 18.8%22.3% and 31.8%17.9% for the ninesix months ended SeptemberJune 30, 20212022 and 2020,2021, respectively. See Note 107 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
Results of Operations — PECO
| | | Three Months Ended
September 30, | | Favorable
(Unfavorable)
Variance | | Nine Months Ended
September 30, | | Favorable
(Unfavorable)
Variance | | Three Months Ended
June 30, | | Favorable
(Unfavorable)
Variance | | Six Months Ended
June 30, | | Favorable
(Unfavorable)
Variance |
| | 2021 | | 2020 | | 2021 | | 2020 | | | 2022 | | 2021 | | 2022 | | 2021 | |
| Operating revenues | Operating revenues | $ | 818 | | | $ | 813 | | | $ | 5 | | | $ | 2,399 | | | $ | 2,306 | | | $ | 93 | | Operating revenues | $ | 816 | | | $ | 693 | | | $ | 123 | | | $ | 1,863 | | | $ | 1,582 | | | $ | 281 | |
| Operating expenses | Operating expenses | | Operating expenses | |
| Purchased power and fuel | Purchased power and fuel | 277 | | | 269 | | | (8) | | | 800 | | | 768 | | | (32) | | Purchased power and fuel | 283 | | | 207 | | | (76) | | | 689 | | | 523 | | | (166) | |
| Operating and maintenance | Operating and maintenance | 263 | | | 251 | | | (12) | | | 706 | | | 742 | | | 36 | | Operating and maintenance | 215 | | | 209 | | | (6) | | | 463 | | | 443 | | | (20) | |
| Depreciation and amortization | Depreciation and amortization | 86 | | | 85 | | | (1) | | | 259 | | | 259 | | | — | | Depreciation and amortization | 93 | | | 87 | | | (6) | | | 185 | | | 173 | | | (12) | |
| Taxes other than income taxes | Taxes other than income taxes | 51 | | | 53 | | | 2 | | | 143 | | | 131 | | | (12) | | Taxes other than income taxes | 48 | | | 49 | | | 1 | | | 95 | | | 92 | | | (3) | |
| Total operating expenses | Total operating expenses | 677 | | | 658 | | | (19) | | | 1,908 | | | 1,900 | | | (8) | | Total operating expenses | 639 | | | 552 | | | (87) | | | 1,432 | | | 1,231 | | | (201) | |
| | Operating income | Operating income | 141 | | | 155 | | | (14) | | | 491 | | | 406 | | | 85 | | Operating income | 177 | | | 141 | | | 36 | | | 431 | | | 351 | | | 80 | |
| Other income and (deductions) | Other income and (deductions) | | | | | | | | | | | | Other income and (deductions) | | | | | | | | | | | |
| Interest expense, net | Interest expense, net | (40) | | | (39) | | | (1) | | | (119) | | | (108) | | | (11) | | Interest expense, net | (43) | | | (42) | | | (1) | | | (84) | | | (80) | | | (4) | |
| Other, net | Other, net | 7 | | | 6 | | | 1 | | | 20 | | | 12 | | | 8 | | Other, net | 8 | | | 7 | | | 1 | | | 16 | | | 12 | | | 4 | |
| Total other income and (deductions) | Total other income and (deductions) | (33) | | | (33) | | | — | | | (99) | | | (96) | | | (3) | | Total other income and (deductions) | (35) | | | (35) | | | — | | | (68) | | | (68) | | | — | |
| Income before income taxes | Income before income taxes | 108 | | | 122 | | | (14) | | | 392 | | | 310 | | | 82 | | Income before income taxes | 142 | | | 106 | | | 36 | | | 363 | | | 283 | | | 80 | |
| Income taxes | Income taxes | (3) | | | (16) | | | (13) | | | 9 | | | (7) | | | (16) | | Income taxes | 9 | | | 2 | | | (7) | | | 24 | | | 12 | | | (12) | |
| | Net income | Net income | $ | 111 | | | $ | 138 | | | $ | (27) | | | $ | 383 | | | $ | 317 | | | $ | 66 | | Net income | $ | 133 | | | $ | 104 | | | $ | 29 | | | $ | 339 | | | $ | 271 | | | $ | 68 | |
Three Months Ended SeptemberJune 30, 20212022 Compared to Three Months Ended SeptemberJune 30, 2020. Net income decreased by $27 million primarily due to an increase in storm cost activity, net of tax repair deductions.
Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020. 2021. Net income increased by $66$29 million, primarily due to favorable weather, an increaseincreases in electric and gas distribution rates.
Six Months Ended June 30, 2022 Compared to Six Months Ended June 30, 2021. Net income increased by $68 million, primarily due to increases in electric volume, and a decrease in storm cost activity, net of tax repair deductions.gas distribution rates.
The changes in Operating revenues consisted of the following:
| | | Three Months Ended
September 30, 2021 | | Nine Months Ended
September 30, 2021 | | Three Months Ended
June 30, 2022 | | Six Months Ended
June 30, 2022 |
| | Increase (Decrease) | | Increase (Decrease) | | (Decrease) Increase | | (Decrease) Increase |
| | Electric | | Gas | | Total | | Electric | | Gas | | Total | | Electric | | Gas | | Total | | Electric | | Gas | | Total |
| Weather | Weather | $ | (7) | | | $ | (7) | | | $ | (14) | | | $ | 17 | | | $ | 17 | | | $ | 34 | | Weather | $ | (1) | | | $ | (1) | | | $ | (2) | | | $ | (5) | | | $ | (5) | | | $ | (10) | |
| Volume | Volume | 2 | | | 7 | | | 9 | | | 19 | | | — | | | 19 | | Volume | (2) | | | 4 | | | 2 | | | 4 | | | 10 | | | 14 | |
| Pricing | Pricing | 2 | | | 4 | | | 6 | | | (1) | | | (1) | | | (2) | | Pricing | 32 | | | 6 | | | 38 | | | 65 | | | 23 | | | 88 | |
| Transmission | Transmission | 4 | | | — | | | 4 | | | 7 | | | — | | | 7 | | Transmission | 3 | | | — | | | 3 | | | 8 | | | — | | | 8 | |
| Other | Other | — | | | — | | | — | | | (1) | | | — | | | (1) | | Other | 6 | | | 1 | | | 7 | | | 11 | | | 4 | | | 15 | |
| | 1 | | | 4 | | | 5 | | | 41 | | | 16 | | | 57 | | | 38 | | | 10 | | | 48 | | | 83 | | | 32 | | | 115 | |
| Regulatory required programs | Regulatory required programs | 3 | | | (3) | | | — | | | 46 | | | (10) | | | 36 | | Regulatory required programs | 58 | | | 17 | | | 75 | | | 95 | | | 71 | | | 166 | |
| Total increase | Total increase | $ | 4 | | | $ | 1 | | | $ | 5 | | | $ | 87 | | | $ | 6 | | | $ | 93 | | Total increase | $ | 96 | | | $ | 27 | | | $ | 123 | | | $ | 178 | | | $ | 103 | | | $ | 281 | |
Weather. The demand for electricity and natural gas is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and natural gas businesses, very cold weather in winter months are referred to as “favorable weather conditions” because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. During the three months ended SeptemberJune 30, 20212022 compared to the same period in 2020,2021, Operating revenues related to weather fell due to unfavorable weather.remained relatively consistent. During the ninesix months ended SeptemberJune 30, 20212022 compared to the same period in 2020,2021, Operating revenues related to weather increaseddecreased by the impact of favorableunfavorable weather conditions in PECO's service territory.
Heating and cooling degree-days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree-days for a 30-year period in PECO's service territory. The changes in heating and cooling degree-days in
PECO’s service territory for the three and ninesix months ended SeptemberJune 30, 20212022 compared to the same period in 20202021 and normal weather consisted of the following:
| | Heating and Cooling Degree-Days | | | Normal | | % Change | |
Three Months Ended
September 30, | 2021 | | 2020 | From 2020 | | 2021 vs. Normal | |
| | | Three Months Ended June 30, | | | | % Change |
| PECO Service Territory | | PECO Service Territory | 2022 | | 2021 | Normal | 2022 vs. 2021 | | 2022 vs. Normal |
| | Heating Degree-Days | Heating Degree-Days | 4 | | 37 | | 25 | | (89.2) | % | | (84.0) | % | Heating Degree-Days | 385 | | 404 | | 424 | | (4.7) | % | | (9.2) | % |
| Cooling Degree-Days | Cooling Degree-Days | 1,094 | | 1,128 | | 1,013 | | (3.0) | % | | 8.0 | % | Cooling Degree-Days | 434 | | 418 | | 391 | | 3.8 | % | | 11.0 | % |
| | Normal | | % Change | | Six Months Ended June 30, | | | % Change |
| Nine Months Ended September 30, | 2021 | | 2020 | | From 2020 | | 2021 vs. Normal | |
| | | 2022 | | 2021 | | Normal | | 2022 vs. 2021 | | 2022 vs. Normal |
| Heating Degree-Days | Heating Degree-Days | 2,710 | | | 2,594 | | 2,865 | | 4.5 | % | | (5.4) | % | Heating Degree-Days | 2,613 | | | 2,706 | | 2,840 | (3.4) | % | | (8.0) | % |
| Cooling Degree-Days | Cooling Degree-Days | 1,517 | | | 1,504 | | 1,402 | | 0.9 | % | | 8.2 | % | Cooling Degree-Days | 435 | | | 423 | | 392 | | 2.8 | % | | 11.0 | % |
Volume. Electric volume, exclusive of the effects of weather, for the three and ninesix months ended SeptemberJune 30, 2021,2022, compared to the same period in 2020, increased on a net basis due to an increase in overall usage for customers further increased by customer growth.2021, remained relatively consistent. Natural gas volume for the three and ninesix months ended SeptemberJune 30, 20212022 compared to the same period in 2020,2021, increased due to retail load growth.
| | Electric Retail Deliveries to Customers (in GWhs) | Electric Retail Deliveries to Customers (in GWhs) | Three Months Ended
September 30, | | % Change | | Weather - Normal % Change(b) | | Nine Months Ended September 30, | | % Change | | Weather - Normal % Change(b) | Electric Retail Deliveries to Customers (in GWhs) | Three Months Ended
June 30, | | % Change | | Weather - Normal % Change(b) | | Six Months Ended June 30, | | % Change | | Weather - Normal % Change(b) |
| 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 | |
| Residential | Residential | 4,318 | | 4,477 | | (3.6) | % | | (1.4) | % | | 11,201 | | 10,874 | | 3.0 | % | | 1.0 | % | Residential | 3,060 | | 3,116 | | (1.8) | % | | (1.1) | % | | 6,818 | | 6,883 | | (0.9) | % | | 0.1 | % |
| Small commercial & industrial | Small commercial & industrial | 2,157 | | 2,017 | | 6.9 | % | | 7.7 | % | | 5,796 | | 5,493 | | 5.5 | % | | 3.9 | % | Small commercial & industrial | 1,813 | | 1,758 | | 3.1 | % | | 3.0 | % | | 3,750 | | 3,639 | | 3.1 | % | | 3.2 | % |
| Large commercial & industrial | Large commercial & industrial | 3,880 | | 3,791 | | 2.3 | % | | 2.7 | % | | 10,627 | | 10,393 | | 2.3 | % | | 1.8 | % | Large commercial & industrial | 3,416 | | 3,475 | | (1.7) | % | | (1.8) | % | | 6,748 | | 6,747 | | — | % | | — | % |
| Public authorities & electric railroads | Public authorities & electric railroads | 155 | | 145 | | 6.9 | % | | 7.2 | % | | 425 | | 407 | | 4.4 | % | | 4.3 | % | Public authorities & electric railroads | 135 | | 121 | | 11.6 | % | | 11.9 | % | | 317 | | 270 | | 17.4 | % | | 17.7 | % |
Total electric retail deliveries(a) | Total electric retail deliveries(a) | 10,510 | | 10,430 | | 0.8 | % | | 2.0 | % | | 28,049 | | 27,167 | | 3.2 | % | | 2.0 | % | Total electric retail deliveries(a) | 8,424 | | 8,470 | | (0.5) | % | | (0.4) | % | | 17,633 | | 17,539 | | 0.5 | % | | 1.0 | % |
| | | As of September 30, | | As of June 30, |
| Number of Electric Customers | Number of Electric Customers | 2021 | | 2020 | Number of Electric Customers | 2022 | | 2021 |
| Residential | Residential | 1,514,836 | | 1,505,080 | Residential | 1,521,728 | | 1,513,456 |
| Small commercial & industrial | Small commercial & industrial | 155,006 | | 154,183 | Small commercial & industrial | 155,484 | | 154,842 |
| Large commercial & industrial | Large commercial & industrial | 3,108 | | 3,105 | Large commercial & industrial | 3,114 | | 3,108 |
| Public authorities & electric railroads | Public authorities & electric railroads | 10,271 | | 10,149 | Public authorities & electric railroads | 10,386 | | 10,285 |
| Total | Total | 1,683,221 | | 1,672,517 | Total | 1,690,712 | | 1,681,691 |
__________
(a)Reflects delivery volumes from customers purchasing electricity directly from PECO and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges.
(b)Reflects the change in delivery volumes assuming normalized weather based on the historical 30-year average.
| | Natural Gas Deliveries to Customers (in mmcf) | Natural Gas Deliveries to Customers (in mmcf) | Three Months Ended
September 30, | | % Change | | Weather - Normal % Change(b) | | Nine Months Ended
September 30, | | % Change | | Weather - Normal % Change(b) | Natural Gas Deliveries to Customers (in mmcf) | Three Months Ended
June 30, | | % Change | | Weather - Normal % Change(b) | | Six Months Ended
June 30, | | % Change | | Weather - Normal % Change(b) |
| 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 | |
| Residential | Residential | 2,244 | | 2,121 | | 5.8 | % | | 8.2 | % | | 27,945 | | 25,867 | | 8.0 | % | | 0.8 | % | Residential | 5,206 | | 5,027 | | 3.6 | % | | 4.9 | % | | 26,043 | | 25,701 | | 1.3 | % | | 4.4 | % |
| Small commercial & industrial | Small commercial & industrial | 1,926 | | 2,157 | | (10.7) | % | | (11.7) | % | | 15,217 | | 13,020 | | 16.9 | % | | 7.5 | % | Small commercial & industrial | 3,638 | | 3,121 | | 16.6 | % | | 17.2 | % | | 14,184 | | 13,291 | | 6.7 | % | | 8.4 | % |
| Large commercial & industrial | Large commercial & industrial | 4 | | 9 | | (55.6) | % | | 1.3 | % | | 13 | | 20 | | (35.0) | % | | 7.7 | % | Large commercial & industrial | 4 | | 2 | | 100.0 | % | | 12.6 | % | | 14 | | 9 | | 55.6 | % | | 11.4 | % |
| Transportation | Transportation | 5,356 | | 5,269 | | 1.7 | % | | 5.0 | % | | 18,474 | | 17,553 | | 5.2 | % | | 4.0 | % | Transportation | 5,707 | | 5,468 | | 4.4 | % | | 5.7 | % | | 13,346 | | 13,118 | | 1.7 | % | | 2.7 | % |
Total natural gas retail deliveries(a) | Total natural gas retail deliveries(a) | 9,530 | | 9,556 | | (0.3) | % | | 2.0 | % | | 61,649 | | 56,460 | | 9.2 | % | | 3.3 | % | Total natural gas retail deliveries(a) | 14,555 | | 13,618 | | 6.9 | % | | 8.0 | % | | 53,587 | | 52,119 | | 2.8 | % | | 5.0 | % |
| | | | As of September 30, | | As of June 30, |
| Number of Natural Gas Customers | Number of Natural Gas Customers | 2021 | | 2020 | Number of Natural Gas Customers | 2022 | | 2021 |
| Residential | Residential | 495,752 | | 490,158 | Residential | 499,678 | | 494,895 |
| Small commercial & industrial | Small commercial & industrial | 44,435 | | 44,138 | Small commercial & industrial | 44,726 | | 44,450 |
| Large commercial & industrial | Large commercial & industrial | 6 | | 5 | Large commercial & industrial | 10 | | 6 |
| Transportation | Transportation | 670 | | 715 | Transportation | 659 | | 677 |
| Total | Total | 540,863 | | 535,016 | Total | 545,073 | | 540,028 |
__________
(a)Reflects delivery volumes from customers purchasing natural gas directly from PECO and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges.
(b)Reflects the change in delivery volumes assuming normalized weather based on the historical 30-year average.
Pricing for the three and ninesix months ended SeptemberJune 30, 20212022 compared to the same period in 2020 remained relatively consistent.2021 increased primarily due to increases in electric and gas distribution rates charged to customers.
Transmission Revenue. Under a FERC-approvedFERC approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered.
Other revenue primarily includes revenue related to late payment charges. Other revenue for the three and six months ended June 30, 2022 compared to the same period in 2021 increased primarily due to revenue related to late payment charges.
Regulatory Required Programs represents revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency, PGC, and the GSA. The riders are designed to provide full and current cost recovery as well as a return. The costs of these programs are included in Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense, and Income taxes. Customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers. Customer choice programs do not impact the volume of deliveries as PECO remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation or natural gas from competitive suppliers, PECO either acts as the billing agent or the competitive supplier separately bills its own customers and therefore PECO does not record Operating revenues or Purchased power and fuel expense related to the electricity and/or natural gas. For customers that choose to purchase electric generation or natural gas from PECO, PECO is permitted to recover the electricity, natural gas, and REC procurement costs without mark-up and therefore records equal and offsetting amounts in Operating revenues and Purchased power and fuel expense related to the electricity, natural gas, and RECs.
Other revenue which primarily includes revenue related to late payment charges. Other revenues for the three and nine months ended September 30, 2021 compared to the same period in 2020, remained relatively consistent.
See Note 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of PECO's revenue disaggregation.
The increase of $8$76 million and the increase of $32$166 million for the three and ninesix months ended SeptemberJune 30, 20212022 compared to the same period in 2020,2021, respectively, in Purchased power and fuel expense isexpense partiallyis offset in Operating revenues as part of regulatory required programs.
The changes in Operating and maintenance expense consisted of the following:
| | | | | | | | | | | |
| Three Months Ended
September 30, 2021 | | Nine Months Ended
September 30, 2021 |
| Increase (Decrease) | | Increase (Decrease) |
Storm-related costs(a) | $ | 5 | | | (54) | |
| Credit loss expense | 10 | | | (2) | |
| Regulatory Required Programs | (6) | | | (7) | |
| BSC costs | 5 | | | 12 | |
| Labor, other benefits, contracting and materials | (4) | | | 19 | |
| Pension and non-pension post retirement benefit expense | — | | | 1 | |
| Other | 2 | | | (5) | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| Total increase (decrease) | $ | 12 | | | $ | (36) | |
__________ | | | | | | | | | | | |
| Three Months Ended
June 30, 2022 | | Six Months Ended
June 30, 2022 |
| Increase (Decrease) | | Increase (Decrease) |
| BSC costs | $ | 7 | | | $ | 16 | |
| Credit loss expense | 1 | | | 5 | |
| Storm-related costs | 1 | | | 3 | |
| Pension and non-pension post retirement benefit expense | (3) | | | (4) | |
| Labor, other benefits, contracting and materials | (6) | | | (8) | |
| Other | 4 | | | 3 | |
| 4 | | | 15 | |
| Regulatory required programs | 2 | | | 5 | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| Total increase | $ | 6 | | | $ | 20 | |
(a) YTD primarily reflects the absence of costs in 2021 due to the June and August 2020 storms.
The changes in Depreciation and amortization expense consisted of the following:
| | | Three Months Ended September 30, 2021 | | Nine Months Ended
September 30, 2021 | | Three Months Ended June 30, 2022 | | Six Months Ended
June 30, 2022 |
| | Increase (Decrease) | | Increase (Decrease) | | Increase | | Increase |
Depreciation and amortization(a) | Depreciation and amortization(a) | $ | 6 | | | $ | 11 | | Depreciation and amortization(a) | $ | 6 | | | $ | 12 | |
| Regulatory asset amortization | Regulatory asset amortization | (5) | | | (11) | | Regulatory asset amortization | — | | | — | |
| | Total increase | Total increase | $ | 1 | | | $ | — | | Total increase | $ | 6 | | | $ | 12 | |
__________
(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.
Interest expense, net increasedincreased $1 million and $11$4 million for the three and ninesix months ended SeptemberJune 30, 20212022 compared to the same period in 2020, respectively,2021, primarily due to the issuance of debt in March 2021 and June 2020.2022.
Effective income tax rates were (2.8)%6.3% and (13.1)%1.9% for the three months ended SeptemberJune 30, 20212022 and 20202021 respectively, and 2.3%6.6% and (2.3)%4.2% for the ninefor the six months ended SeptemberJune 30, 20212022 and 2020,2021, respectively. See Note 107 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
Results of Operations — BGE
| | | Three Months Ended
September 30, | | Favorable
(Unfavorable)
Variance | | Nine Months Ended
September 30, | | Favorable
(Unfavorable)
Variance | | Three Months Ended
June 30, | | Favorable
(Unfavorable)
Variance | | Six Months Ended
June 30, | | Favorable
(Unfavorable)
Variance |
| | 2021 | | 2020 | | 2021 | | 2020 | | | 2022 | | 2021 | | 2022 | | 2021 | |
| Operating revenues | Operating revenues | $ | 770 | | | $ | 731 | | | $ | 39 | | | $ | 2,426 | | | $ | 2,284 | | | $ | 142 | | Operating revenues | $ | 786 | | | $ | 682 | | | $ | 104 | | | $ | 1,940 | | | $ | 1,656 | | | $ | 284 | |
| Operating expenses | Operating expenses | | Operating expenses | |
| Purchased power and fuel | Purchased power and fuel | 290 | | | 250 | | | (40) | | | 840 | | | 731 | | | (109) | | Purchased power and fuel | 289 | | | 219 | | | (70) | | | 743 | | | 550 | | | (193) | |
| Operating and maintenance | Operating and maintenance | 205 | | | 191 | | | (14) | | | 595 | | | 567 | | | (28) | | Operating and maintenance | 205 | | | 193 | | | (12) | | | 423 | | | 390 | | | (33) | |
| Depreciation and amortization | Depreciation and amortization | 142 | | | 133 | | | (9) | | | 434 | | | 405 | | | (29) | | Depreciation and amortization | 152 | | | 141 | | | (11) | | | 322 | | | 293 | | | (29) | |
| Taxes other than income taxes | Taxes other than income taxes | 72 | | | 68 | | | (4) | | | 211 | | | 200 | | | (11) | | Taxes other than income taxes | 71 | | | 67 | | | (4) | | | 148 | | | 139 | | | (9) | |
| Total operating expenses | Total operating expenses | 709 | | | 642 | | | (67) | | | 2,080 | | | 1,903 | | | (177) | | Total operating expenses | 717 | | | 620 | | | (97) | | | 1,636 | | | 1,372 | | | (264) | |
| | Operating income | Operating income | 61 | | | 89 | | | (28) | | | 346 | | | 381 | | | (35) | | Operating income | 69 | | | 62 | | | 7 | | | 304 | | | 284 | | | 20 | |
| Other income and (deductions) | Other income and (deductions) | | | | | | | | | | | | Other income and (deductions) | | | | | | | | | | | |
| Interest expense, net | Interest expense, net | (36) | | | (34) | | | (2) | | | (103) | | | (99) | | | (4) | | Interest expense, net | (36) | | | (34) | | | (2) | | | (71) | | | (67) | | | (4) | |
| Other, net | Other, net | 7 | | | 6 | | | 1 | | | 23 | | | 17 | | | 6 | | Other, net | 5 | | | 9 | | | (4) | | | 11 | | | 16 | | | (5) | |
| Total other income and (deductions) | Total other income and (deductions) | (29) | | | (28) | | | (1) | | | (80) | | | (82) | | | 2 | | Total other income and (deductions) | (31) | | | (25) | | | (6) | | | (60) | | | (51) | | | (9) | |
| Income before income taxes | Income before income taxes | 32 | | | 61 | | | (29) | | | 266 | | | 299 | | | (33) | | Income before income taxes | 38 | | | 37 | | | 1 | | | 244 | | | 233 | | | 11 | |
| Income taxes | Income taxes | (4) | | | 8 | | | 12 | | | (24) | | | 26 | | | 50 | | Income taxes | 1 | | | (8) | | | (9) | | | 10 | | | (21) | | | (31) | |
| Net income | Net income | $ | 36 | | | $ | 53 | | | $ | (17) | | | $ | 290 | | | $ | 273 | | | $ | 17 | | Net income | $ | 37 | | | $ | 45 | | | $ | (8) | | | $ | 234 | | | $ | 254 | | | $ | (20) | |
|
Three Months Ended SeptemberJune 30, 20212022 Compared to Three Months Ended SeptemberJune 30, 2020.2021. Net income decreased by $17$8 million primarily relateddue to an increase in depreciation and amortization expense, and an increase in various expenses, partially offset by favorable impacts of the multi-year plan.
Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020.Net income increased by $17 million primarily due to favorable impacts of the multi-year plan, partially offset by an increase in depreciation and amortization expense and an increase in storm costs. plans. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on the three-year electric and natural gas distribution multi-year plan.plans.
Six Months Ended June 30, 2022 Compared to Six Months Ended June 30, 2021. Net income decreased $20 million primarily due to an increase in depreciation expense and credit loss expense, partially offset by favorable impacts of the multi-year plans. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on the three-year electric and natural gas distribution multi-year plans.
The changes in Operating revenues consisted of the following:
| | | Three Months Ended
September 30, 2021 | | Nine Months Ended
September 30, 2021 | | Three Months Ended
June 30, 2022 | | Six Months Ended
June 30, 2022 |
| | Increase (Decrease) | | Increase (Decrease) | | Increase | | Increase |
| | Electric | | Gas | | Total | | Electric | | Gas | | Total | | Electric | | Gas | | Total | | Electric | | Gas | | Total |
| Distribution | Distribution | $ | 1 | | | $ | 1 | | | $ | 2 | | | $ | 7 | | | $ | 2 | | | $ | 9 | | Distribution | $ | 17 | | | $ | 5 | | | $ | 22 | | | $ | 31 | | | $ | 15 | | | $ | 46 | |
| Transmission | Transmission | (6) | | | — | | | (6) | | | 23 | | | — | | | 23 | | Transmission | 2 | | | — | | | 2 | | | 7 | | | — | | | 7 | |
| Other | Other | 7 | | | — | | | 7 | | | 5 | | | 1 | | | 6 | | Other | 3 | | | 2 | | | 5 | | | 10 | | | 5 | | | 15 | |
| | 2 | | | 1 | | | 3 | | | 35 | | | 3 | | | 38 | | | 22 | | | 7 | | | 29 | | | 48 | | | 20 | | | 68 | |
| Regulatory required programs | Regulatory required programs | 29 | | | 7 | | | 36 | | | 70 | | | 34 | | | 104 | | Regulatory required programs | 50 | | | 25 | | | 75 | | | 128 | | | 88 | | | 216 | |
| Total increase | Total increase | $ | 31 | | | $ | 8 | | | $ | 39 | | | $ | 105 | | | $ | 37 | | | $ | 142 | | Total increase | $ | 72 | | | $ | 32 | | | $ | 104 | | | $ | 176 | | | $ | 108 | | | $ | 284 | |
Revenue Decoupling. The demand for electricity and natural gas is affected by weather and customer usage. However, Operating revenues are not impacted by abnormal weather or usage per customer as a result of a bill stabilizationmonthly rate adjustment (BSA) that provides for a fixed distribution chargerevenue per customer by customer class. While Operating revenues are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers.
| | | | As of September 30, | | As of June 30, |
| Number of Electric Customers | Number of Electric Customers | 2021 | | 2020 | Number of Electric Customers | 2022 | | 2021 |
| Residential | Residential | 1,194,254 | | | 1,187,498 | | Residential | 1,200,397 | | | 1,192,135 | |
| Small commercial & industrial | Small commercial & industrial | 114,814 | | | 114,038 | | Small commercial & industrial | 115,769 | | | 114,682 | |
| Large commercial & industrial | Large commercial & industrial | 12,584 | | | 12,428 | | Large commercial & industrial | 12,721 | | | 12,528 | |
| Public authorities & electric railroads | Public authorities & electric railroads | 268 | | | 267 | | Public authorities & electric railroads | 267 | | | 267 | |
| Total | Total | 1,321,920 | | | 1,314,231 | | Total | 1,329,154 | | | 1,319,612 | |
| | | As of September 30, | | As of June 30, |
| Number of Natural Gas Customers | Number of Natural Gas Customers | 2021 | | 2020 | Number of Natural Gas Customers | 2022 | | 2021 |
| Residential | Residential | 649,745 | | | 644,872 | | Residential | 653,409 | | | 647,534 | |
| Small commercial & industrial | Small commercial & industrial | 38,216 | | | 38,173 | | Small commercial & industrial | 38,227 | | | 38,223 | |
| Large commercial & industrial | Large commercial & industrial | 6,167 | | | 6,083 | | Large commercial & industrial | 6,211 | | | 6,132 | |
| Total | Total | 694,128 | | | 689,128 | | Total | 697,847 | | | 691,889 | |
Distribution Revenue increased for the three and ninesix months ended SeptemberJune 30, 2021,2022, compared to the same period in 2020,2021, due to customer growth.favorable impacts of the multi-year plans.
Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue decreasedincreased for the three and six months ended SeptemberJune 30, 2021,2022, compared to the same period in 2020,2021, primarily due to decreasesincreases in Operating and maintenance expense recoveries in 2021. Transmission revenue increased for the nine months ended September 30, 2021, compared to the same period in 2020, primarily due to the reduction in revenue in 2020 due to the settlement agreement of ongoing transmission related income tax regulatory liabilities.capital investments.
Other Revenue includes revenue related to late payment charges, mutual assistance, off-system sales, and service application fees. Other revenue increased for both the three and ninesix months ended SeptemberJune 30, 2021,2022, compared to the same period in 2020, as BGE had temporarily suspended customer disconnections for non-payment and temporarily ceased new2021, primarily due to an increase in late fees for customers in 2020 which has resumed in 2021.charged to customers.
Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as conservation, demand response, STRIDE, and the POLR mechanism. The riders are designed to provide full and current cost recovery, as well as a return in certain instances. The costs of these programs are included in Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers. Customer choice programs do not impact the volume of deliveries as BGE remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation or natural gas from competitive suppliers, BGE either acts as the billing agent or the competitive supplier separately bills its own customers, and therefore BGE does not record Operating revenues or Purchased power and fuel expense related to the electricity and/or natural gas. For customers that choose to purchase electric generation or natural gas from BGE, BGE is permitted to recover the electricity and natural gas procurement costs from customers and therefore records the amounts related to the electricity and/or natural gas in Operating revenues and Purchased power and fuel expense. BGE recovers electricity and natural gas procurement costs from customers with a slight mark-up.
See Note 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of BGE's revenue disaggregation.
The increase of $40$70 million and $109$193 million for t thehe three and ninesix months ended SeptemberJune 30, 20212022 compared to the same period in 2020,2021, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.
The changes in Operating and maintenance expense consisted of the following:
| | | Three Months Ended
September 30, 2021 | | Nine Months Ended
September 30, 2021 | | Three Months Ended
June 30, 2022 | | Six Months Ended
June 30, 2022 |
| | | Increase (Decrease) | | Increase (Decrease) | | Increase (Decrease) | | Increase (Decrease) |
| Labor, other benefits, contracting, and materials | Labor, other benefits, contracting, and materials | $ | 3 | | | $ | 5 | | Labor, other benefits, contracting, and materials | $ | 5 | | | $ | 7 | |
| Storm-related costs | Storm-related costs | 3 | | | 10 | | Storm-related costs | (2) | | | (1) | |
| Pension and non-pension postretirement benefits expense | Pension and non-pension postretirement benefits expense | — | | | 1 | | Pension and non-pension postretirement benefits expense | (3) | | | (6) | |
| BSC costs | BSC costs | 7 | | | 13 | | BSC costs | 6 | | | 14 | |
| Credit loss expense | Credit loss expense | 1 | | | (5) | | Credit loss expense | — | | | 14 | |
| Other | Other | (2) | | | (1) | | Other | 5 | | | 2 | |
| | 12 | | | 23 | | | 11 | | | 30 | |
| Regulatory required programs | Regulatory required programs | 2 | | | 5 | | Regulatory required programs | 1 | | | 3 | |
| | Total increase | Total increase | $ | 14 | | | $ | 28 | | Total increase | $ | 12 | | | $ | 33 | |
|
The changes in Depreciation and amortization expense consisted of the following:
| | | Three Months Ended
September 30, 2021 | | Nine Months Ended
September 30, 2021 | | Three Months Ended
June 30, 2022 | | Six Months Ended
June 30, 2022 |
| | Increase (Decrease) | | Increase (Decrease) | | Increase | | Increase |
Depreciation and amortization(a) | Depreciation and amortization(a) | $ | 12 | | | $ | 31 | | Depreciation and amortization(a) | $ | 9 | | | $ | 19 | |
| Regulatory required programs | | Regulatory required programs | 1 | | | 8 | |
| Regulatory asset amortization | Regulatory asset amortization | 1 | | | 1 | | Regulatory asset amortization | 1 | | | 2 | |
| Regulatory required programs | (4) | | | (3) | | |
| | Total increase | Total increase | $ | 9 | | | $ | 29 | | Total increase | $ | 11 | | | $ | 29 | |
__________
(a)Depreciation and amortizationamortization increased primarily due to ongoing capital expenditures.
Taxes other than income taxesincreased by $4 million and $9 million for the three and ninesix months ended SeptemberJune 30, 20212022, respectively, compared to the same period in 2020,2021, primarily due to higherincreased property taxes.
Effective income tax rates were (12.5)%2.6% and 13.1%(21.6)% for the three months ended SeptemberJune 30, 20212022 and 2020,2021, respectively, and 4.1% and (9.0)% and 8.7% forfor the ninesix months ended SeptemberJune 30, 20212022 and 2020,2021, respectively. The change is primarily due to decreases in the multi-year plan which resulted in the acceleration of certainplans' accelerated income tax benefits and the April 24, 2020 settlement agreement of ongoing transmission related income tax regulatory liabilities.in 2022 as compared to 2021. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on the three-year electric and natural gas distribution multi-year plan, Note 3 — Regulatory Matters of the 2020 Exelon Form 10-K for additional information on the April 24, 2020 settlement agreement,plans and Note 107 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
Results of Operations — PHI
PHI’s Results of Operations include the results of its three reportable segments, Pepco, DPL, and ACE. PHI also has a business services subsidiary, PHISCO, which provides a variety of support services and the costs are directly charged or allocated to the applicable subsidiaries. Additionally, the results of PHI’s corporate operations include interest costs from various financing activities. All material intercompany accounts and transactions have been eliminated in consolidation. The following table sets forth PHI's GAAP consolidated Net income, by Registrant, for the three and ninesix months ended SeptemberJune 30, 20212022 compared to the same period in 2020.2021. See the Results of Operations for Pepco, DPL, and ACE for additional information.
| | | Three Months Ended
September 30, | | Favorable Variance | | Nine Months Ended
September 30, | | Favorable Variance | | Three Months Ended
June 30, | | (Unfavorable) Variance | | Six Months Ended June 30, | | (Unfavorable) Favorable Variance |
| | 2021 | | 2020 | | 2021 | | 2020 | | | 2022 | | 2021 | | 2022 | | 2021 | |
| PHI | PHI | $ | 266 | | | $ | 216 | | | $ | 50 | | | $ | 535 | | | $ | 418 | | | $ | 117 | | PHI | $ | 100 | | | $ | 141 | | | $ | (41) | | | $ | 230 | | | $ | 269 | | | $ | (39) | |
| Pepco | Pepco | 130 | | | 118 | | | 12 | | | 264 | | | 227 | | | 37 | | Pepco | 70 | | | 75 | | | (5) | | | 116 | | | 134 | | | (18) | |
| DPL | DPL | 50 | | | 27 | | | 23 | | | 135 | | | 91 | | | 44 | | DPL | 21 | | | 30 | | | (9) | | | 77 | | | 86 | | | (9) | |
| ACE | ACE | 90 | | | 75 | | | 15 | | | 141 | | | 106 | | | 35 | | ACE | 11 | | | 37 | | | (26) | | | 37 | | | 51 | | | (14) | |
Other(a) | Other(a) | (4) | | | (4) | | | — | | | (5) | | | (6) | | | 1 | | Other(a) | (2) | | | (1) | | | (1) | | | — | | | (2) | | | 2 | |
___________________
(a)Primarily includes eliminating and consolidating adjustments, PHI's corporate operations, shared service entities, and other financing and investing activities.
Three Months Ended SeptemberJune 30, 20212022 Compared to Three Months Ended SeptemberJune 30, 2020.2021. Net incomeIncome decreased by $41 million increasedprimarily due to the absence of favorable weather and volume as a result of the CIP at ACE, an increase in credit loss expense at Pepco, higher contracting costs partially due to timing of maintenance projects at Pepco, depreciation and amortization expense, and the timing of excess deferred tax amortization at ACE, partially offset by $50favorable impacts as a result of Pepco's Maryland and District of Columbia multi-year plans and higher electric distribution rates at DPL and ACE.
Six Months Ended June 30, 2022 Compared to Six Months Ended June 30, 2021. Net Income decreased by $39 million primarily due to higher distribution rates, customer growththe absence of favorable weather and volume as a result of the CIP at Pepco, higher transmission revenues due toACE, an increase in capital investments in ACE's service territories, and a decrease in storm costs due to the August 2020 storms in Delaware at DPL, partially offset by an increase in depreciation and amortization expense at Pepco.
Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020. Net income increased by $117 million primarily due to higher distribution rates, higher transmission revenues due to an increase in capital investments in DPL's and ACE's service territories, higher distribution revenues due to an increase in volume in ACE's service territory, favorable weather conditions in DPL's Delaware service territory, customer growth at Pepco a decrease inand DPL, credit loss expense at Pepco and DPL, and a decrease in stormhigher contracting costs partially due to the August 2020 storms in Delawaretiming of maintenance projects at DPL, partially offset by an increase inPepco, depreciation and amortization expense, interest expense, and timing of excess deferred tax amortization at Pepco.Pepco and ACE, partially offset by favorable impacts as a result of Pepco's Maryland and District of Columbia multi-year plans and higher electric distribution rate at DPL and ACE.
Results of Operations — Pepco
| | | Three Months Ended September 30, | | Favorable (Unfavorable) Variance | | Nine Months Ended September 30, | | Favorable (Unfavorable) Variance | | Three Months Ended June 30, | | Favorable (Unfavorable) Variance | | Six Months Ended June 30, | | Favorable (Unfavorable) Variance |
| | 2021 | | 2020 | | | 2021 | | 2020 | | 2022 | | 2021 | | | 2022 | | 2021 | |
| Operating revenues | Operating revenues | $ | 660 | | | $ | 611 | | | $ | 49 | | | $ | 1,736 | | | $ | 1,650 | | | $ | 86 | | Operating revenues | $ | 581 | | | $ | 523 | | | $ | 58 | | | $ | 1,195 | | | $ | 1,076 | | | $ | 119 | |
| | Operating expenses | Operating expenses | | Operating expenses | |
| Purchased power | Purchased power | 172 | | | 163 | | | (9) | | | 471 | | | 467 | | | (4) | | Purchased power | 162 | | | 133 | | | (29) | | | 375 | | | 298 | | | (77) | |
| Operating and maintenance | Operating and maintenance | 120 | | | 106 | | | (14) | | | 341 | | | 336 | | | (5) | | Operating and maintenance | 128 | | | 113 | | | (15) | | | 260 | | | 221 | | | (39) | |
| Depreciation and amortization | Depreciation and amortization | 104 | | | 96 | | | (8) | | | 302 | | | 282 | | | (20) | | Depreciation and amortization | 105 | | | 96 | | | (9) | | | 213 | | | 199 | | | (14) | |
| Taxes other than income taxes | Taxes other than income taxes | 105 | | | 100 | | | (5) | | | 282 | | | 279 | | | (3) | | Taxes other than income taxes | 92 | | | 87 | | | (5) | | | 186 | | | 177 | | | (9) | |
| Total operating expenses | Total operating expenses | 501 | | | 465 | | | (36) | | | 1,396 | | | 1,364 | | | (32) | | Total operating expenses | 487 | | | 429 | | | (58) | | | 1,034 | | | 895 | | | (139) | |
| | Operating income | Operating income | 159 | | | 146 | | | 13 | | | 340 | | | 286 | | | 54 | | Operating income | 94 | | | 94 | | | — | | | 161 | | | 181 | | | (20) | |
| Other income and (deductions) | Other income and (deductions) | | | | | | | | | | | | Other income and (deductions) | | | | | | | | | | | |
| Interest expense, net | Interest expense, net | (35) | | | (35) | | | — | | | (104) | | | (103) | | | (1) | | Interest expense, net | (38) | | | (35) | | | (3) | | | (74) | | | (69) | | | (5) | |
| Other, net | Other, net | 12 | | | 10 | | | 2 | | | 37 | | | 28 | | | 9 | | Other, net | 13 | | | 13 | | | — | | | 26 | | | 25 | | | 1 | |
| Total other income and (deductions) | Total other income and (deductions) | (23) | | | (25) | | | 2 | | | (67) | | | (75) | | | 8 | | Total other income and (deductions) | (25) | | | (22) | | | (3) | | | (48) | | | (44) | | | (4) | |
| Income before income taxes | Income before income taxes | 136 | | | 121 | | | 15 | | | 273 | | | 211 | | | 62 | | Income before income taxes | 69 | | | 72 | | | (3) | | | 113 | | | 137 | | | (24) | |
| Income taxes | Income taxes | 6 | | | 3 | | | (3) | | | 9 | | | (16) | | | (25) | | Income taxes | (1) | | | (3) | | | (2) | | | (3) | | | 3 | | | 6 | |
| Net income | Net income | $ | 130 | | | $ | 118 | | | $ | 12 | | | $ | 264 | | | $ | 227 | | | $ | 37 | | Net income | $ | 70 | | | $ | 75 | | | $ | (5) | | | $ | 116 | | | $ | 134 | | | $ | (18) | |
Three Months Ended SeptemberJune 30, 2021 2022Compared to Three Months Ended SeptemberJune 30, 2020.2021. Net Income decreased by$5 million primarily due to an increase in depreciation expense, credit loss expense, and higher contracting costs partially due to timing of maintenance projects, partially offset by the favorable impacts of the Maryland and District of Columbia multi-year plans.
Six Months Ended June 30, 2022 Compared to Six Months Ended June 30, 2021. Net income increaseddecreased by $12$18 million primarily due to higher distribution rates and customer growth, partially offset by an increase in depreciation and amortization expense.
Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020.Net income increased by $37 million primarily due to higher distribution rates, customer growth, a decrease inexpense, credit loss expense, storm costs, higher contracting costs partially due to timing of maintenance projects, and decreases in various operating expenses,timing of excess deferred tax amortization, partially offset by an increase in depreciationthe favorable impacts of the Maryland and amortization expense.District of Columbia multi-year plans.
The changes in Operating revenues consisted of the following:
| | | Three Months Ended
September 30, 2021 | | Nine Months Ended September 30, 2021 | | Three Months Ended
June 30, 2022 | | Six Months Ended June 30, 2022 |
| | Increase | | Increase | | Increase | | Increase |
| Distribution | Distribution | $ | 18 | | | $ | 23 | | Distribution | $ | 20 | | | $ | 26 | |
| Transmission | Transmission | 6 | | | 28 | | Transmission | 5 | | | 8 | |
| Other | Other | 4 | | | 3 | | Other | 4 | | | — | |
| | 28 | | | 54 | | | 29 | | | 34 | |
| Regulatory required programs | Regulatory required programs | 21 | | | 32 | | Regulatory required programs | 29 | | | 85 | |
| Total increase | Total increase | $ | 49 | | | $ | 86 | | Total increase | $ | 58 | | | $ | 119 | |
Revenue Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from electric distribution in both Maryland and the District of Columbia are not impacted by abnormal weather or usage per customer as a result of a bill stabilization adjustment (BSA) that provides for a fixed distribution charge per customer by customer class. While Operating revenues are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers.
| | | As of September 30, | | As of June 30, |
| Number of Electric Customers | Number of Electric Customers | 2021 | | 2020 | Number of Electric Customers | 2022 | | 2021 |
| Residential | Residential | 839,574 | | | 828,578 | | Residential | 850,569 | | | 837,744 | |
| Small commercial & industrial | Small commercial & industrial | 53,849 | | | 53,813 | | Small commercial & industrial | 54,349 | | | 53,669 | |
| Large commercial & industrial | Large commercial & industrial | 22,586 | | | 22,485 | | Large commercial & industrial | 22,771 | | | 22,579 | |
| Public authorities & electric railroads | Public authorities & electric railroads | 179 | | | 167 | | Public authorities & electric railroads | 194 | | | 178 | |
| Total | Total | 916,188 | | | 905,043 | | Total | 927,883 | | | 914,170 | |
Distribution Revenue increased for both the three and ninesix months ended SeptemberJune 30, 20212022 compared to the same period in 20202021 primarily due to higher distribution rates that became effective infavorable impacts of the Maryland and District of Columbia in Q3 2021 and customer growth.multi-year plans.
Transmission Revenues.Revenue Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue increased for the three and six months ended SeptemberJune 30, 20212022, compared to the same period in 2020,2021, primarily due to increases in underlying costs. Transmission revenue increased for the nine months ended September 30, 2021, compared to the same period in 2020, primarily due to the reduction in revenue in 2020 due to the settlement agreement of ongoing transmission related income tax regulatory liabilitiescapital investment and increases in underlying costs.
Other Revenue includes rental revenue, revenue related to late payment charges, mutual assistance revenues, and recoveries of other taxes.
Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, DC PLUG, and SOS procurement and administrative costs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Purchased power expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries, as Pepco remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation from competitive suppliers, Pepco either acts as the billing agent or the competitive supplier separately bills its own customers, and therefore, Pepco does not record Operating revenues or Purchased power expense related to the electricity. For customers that choose to purchase electric generation from Pepco, Pepco is permitted to recover the electricity and REC procurement costs from customers and therefore records the amounts related to the electricity and RECs in Operating revenues and Purchased power expense. Pepco recovers electricity and REC procurement costs from customers with a slight mark-up.
See Note 5 -— Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of Pepco's revenue disaggregation.
The increase of $9$29 million and $4$77 million for the three and ninesix months ended SeptemberJune 30, 2021, respectively2022 compared to the same period in 2020,2021, respectively, in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs.
The changes in Operating and maintenance expense consisted of the following:
| | | | | | | | | | | |
| Three Months Ended
June 30, 2022 | | Six Months Ended June 30, 2022 |
| Increase (Decrease) | | Increase |
| BSC and PHISCO Costs | $ | 7 | | | $ | 11 | |
Labor, other benefits, contracting and materials(a) | 6 | | | 9 | |
| Credit loss expense | 5 | | | 9 | |
| Storm-related costs | — | | | 6 | |
| | | |
| | | |
| | | |
| Other | (5) | | | 2 | |
| 13 | | | 37 | |
| | | |
| Regulatory required programs | 2 | | | 2 | |
| Total increase | $ | 15 | | | $ | 39 | |
__________
(a) Primarily reflects higher contracting costs partially due to timing of maintenance projects.
The changes in Operating and maintenance expense consisted of the following:
| | | | | | | | | | | |
| Three Months Ended
September 30, 2021 | | Nine Months Ended September 30, 2021 |
| Increase (Decrease) | | Increase (Decrease) |
| Storm-related costs | $ | 5 | | | $ | 5 | |
| BSC and PHISCO costs | 2 | | | 1 | |
| Credit loss expense | — | | | (4) | |
| Pension and non-pension postretirement benefits expense | (1) | | | (3) | |
| Labor, other benefits, contracting and materials | (2) | | | (13) | |
| | | |
| | | |
| Other | 6 | | | 14 | |
| 10 | | | — | |
| | | |
| Regulatory required programs | 4 | | | 5 | |
| Total increase | $ | 14 | | | $ | 5 | |
The changes in Depreciation and amortization expense consisted of the following:
| | | Three Months Ended
September 30, 2021 | | Nine Months Ended September 30, 2021 | | Three Months Ended
June 30, 2022 | | Six Months Ended June 30, 2022 |
| | Increase (Decrease) | | Increase (Decrease) | | Increase | | Increase (Decrease) |
Depreciation and amortization(a) | Depreciation and amortization(a) | $ | 5 | | | $ | 13 | | Depreciation and amortization(a) | $ | 6 | | | $ | 11 | |
| Regulatory asset amortization | Regulatory asset amortization | (3) | | | (10) | | Regulatory asset amortization | 2 | | | (3) | |
| Regulatory required programs | Regulatory required programs | 6 | | | 17 | | Regulatory required programs | 1 | | | 6 | |
| Total increase | Total increase | $ | 8 | | | $ | 20 | | Total increase | $ | 9 | | | $ | 14 | |
___________________
(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.
Effective income tax rates were 4.4%(1.4)% and 2.5%(4.2)% for the three months ended SeptemberJune 30, 20212022 and 2020,2021, respectively, and 3.3%(2.7)% and (7.6)%2.2% for the ninesix months ended SeptemberJune 30, 2022 and 2021, and 2020, respectively. For the nineThe three months ended SeptemberJune 30, 2021, the2022 change is primarily due to the April 24, 2020 settlement agreementacceleration of ongoing transmission relatedcertain income tax regulatory liabilities, partially offset bybenefits as a result of the Maryland and District of Columbia multi-year plan which resulted inplans. The six months ended June 30, 2022 change is primarily due to the acceleration of certain income tax benefits.benefits as a result of the Maryland and District of Columbia multi-year plans, partially offset with the timing of excess deferred tax amortization. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial StatementsStatement for additional information on the three-year electric distribution multi-year plan, Note 3 — Regulatory Matters of the 2020 Exelon Form 10-K for additional information on the April 24, 2020 settlement agreement,plans and Note 107 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
Results of Operations — DPL
| | | Three Months Ended September 30, | | Favorable (Unfavorable) Variance | | Nine Months Ended September 30, | | Favorable (Unfavorable) Variance | | Three Months Ended June 30, | | Favorable (Unfavorable) Variance | | Six Months Ended June 30, | | Favorable (Unfavorable) Variance |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 | |
| Operating revenues | Operating revenues | $ | 360 | | | $ | 337 | | | $ | 23 | | | $ | 1,040 | | | $ | 954 | | | $ | 86 | | Operating revenues | $ | 332 | | | $ | 298 | | | $ | 34 | | | $ | 763 | | | $ | 680 | | | $ | 83 | |
| Operating expenses | Operating expenses | | Operating expenses | |
| Purchased power and fuel | Purchased power and fuel | 138 | | | 131 | | | (7) | | | 402 | | | 379 | | | (23) | | Purchased power and fuel | 135 | | | 108 | | | (27) | | | 324 | | | 263 | | | (61) | |
| Operating and maintenance | Operating and maintenance | 87 | | | 101 | | | 14 | | | 249 | | | 272 | | | 23 | | Operating and maintenance | 88 | | | 80 | | | (8) | | | 181 | | | 164 | | | (17) | |
| Depreciation and amortization | Depreciation and amortization | 53 | | | 48 | | | (5) | | | 157 | | | 143 | | | (14) | | Depreciation and amortization | 56 | | | 51 | | | (5) | | | 113 | | | 104 | | | (9) | |
| Taxes other than income taxes | Taxes other than income taxes | 17 | | | 16 | | | (1) | | | 50 | | | 49 | | | (1) | | Taxes other than income taxes | 17 | | | 16 | | | (1) | | | 35 | | | 33 | | | (2) | |
| Total operating expenses | Total operating expenses | 295 | | | 296 | | | 1 | | | 858 | | | 843 | | | (15) | | Total operating expenses | 296 | | | 255 | | | (41) | | | 653 | | | 564 | | | (89) | |
| | Operating income | Operating income | 65 | | | 41 | | | 24 | | | 182 | | | 111 | | | 71 | | Operating income | 36 | | | 43 | | | (7) | | | 110 | | | 116 | | | (6) | |
| Other income and (deductions) | Other income and (deductions) | | | | | | | | | | | | Other income and (deductions) | | | | | | | | | | | |
| Interest expense, net | Interest expense, net | (15) | | | (15) | | | — | | | (47) | | | (47) | | | — | | Interest expense, net | (17) | | | (16) | | | (1) | | | (33) | | | (30) | | | (3) | |
| Other, net | Other, net | 3 | | | 2 | | | 1 | | | 9 | | | 7 | | | 2 | | Other, net | 4 | | | 4 | | | — | | | 6 | | | 6 | | | — | |
| Total other income and (deductions) | Total other income and (deductions) | (12) | | | (13) | | | 1 | | | (38) | | | (40) | | | 2 | | Total other income and (deductions) | (13) | | | (12) | | | (1) | | | (27) | | | (24) | | | (3) | |
| Income before income taxes | Income before income taxes | 53 | | | 28 | | | 25 | | | 144 | | | 71 | | | 73 | | Income before income taxes | 23 | | | 31 | | | (8) | | | 83 | | | 92 | | | (9) | |
| Income taxes | Income taxes | 3 | | | 1 | | | (2) | | | 9 | | | (20) | | | (29) | | Income taxes | 2 | | | 1 | | | (1) | | | 6 | | | 6 | | | — | |
| Net income | Net income | $ | 50 | | | $ | 27 | | | $ | 23 | | | $ | 135 | | | $ | 91 | | | $ | 44 | | Net income | $ | 21 | | | $ | 30 | | | $ | (9) | | | $ | 77 | | | $ | 86 | | | $ | (9) | |
Three Months Ended SeptemberJune 30, 20212022 Compared to Three Months Ended SeptemberJune 30, 20202021. Net income decreased $9 million primarily due to an increase in depreciation expense and various operating expenses partially offset by higher electric distribution rates.
Six Months Ended June 30, 2022 Compared to Six Months Ended June 30, 2021. Net income increased by $23decreased $9 million primarily due to higher electric distribution rates and a decrease in storm costs due to the August 2020 storms in Delaware.
Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020. Net income increased by $44 million primarily due to higher electric distribution rates, a decrease in storm costs due to the August 2020 storms in Delaware, higher transmission revenues due to an increase in capital investments, a decrease in credit loss expense, depreciation expense, and favorable weather conditions at DPL's Delawarevarious operating expenses, partially offset by higher electric service territories.distribution rates.
The changes in Operating revenues consisted of the following:
| | | Three Months Ended
September 30, 2021 | | Nine Months Ended
September 30, 2021 | | Three Months Ended
June 30, 2022 | | Six Months Ended
June 30, 2022 |
| | (Decrease) Increase | | Increase (Decrease) | | (Decrease) Increase | | (Decrease) Increase |
| | Electric | | Gas | | Total | | Electric | | Gas | | Total | | Electric | | Gas | | Total | | Electric | | Gas | | Total |
| Weather | Weather | $ | — | | | $ | (2) | | | $ | (2) | | | $ | 4 | | | $ | — | | | $ | 4 | | Weather | $ | (1) | | | $ | — | | | $ | (1) | | | $ | (1) | | | $ | — | | | $ | (1) | |
| Volume | Volume | (2) | | | 1 | | | (1) | | | — | | | (1) | | | (1) | | Volume | (1) | | | 2 | | | 1 | | | 3 | | | 3 | | | 6 | |
| Distribution | Distribution | 11 | | | (1) | | | 10 | | | 20 | | | 1 | | | 21 | | Distribution | 5 | | | 1 | | | 6 | | | 10 | | | 3 | | | 13 | |
| Transmission | Transmission | 5 | | | — | | | 5 | | | 33 | | | — | | | 33 | | Transmission | (1) | | | — | | | (1) | | | 2 | | | — | | | 2 | |
| Other | — | | | 1 | | | 1 | | | 1 | | | — | | | 1 | | |
| | | 14 | | | (1) | | | 13 | | | 58 | | | — | | | 58 | | | 2 | | | 3 | | | 5 | | | 14 | | | 6 | | | 20 | |
| Regulatory required programs | Regulatory required programs | 9 | | | 1 | | | 10 | | | 27 | | | 1 | | | 28 | | Regulatory required programs | 18 | | | 11 | | | 29 | | | 43 | | | 20 | | | 63 | |
| Total increase | Total increase | $ | 23 | | | $ | — | | | $ | 23 | | | $ | 85 | | | $ | 1 | | | $ | 86 | | Total increase | $ | 20 | | | $ | 14 | | | $ | 34 | | | $ | 57 | | | $ | 26 | | | $ | 83 | |
Revenue Decoupling.The demand for electricity is affected by weather and customer usage. However, Operating revenues from electric distribution in Maryland are not impacted by abnormal weather or usage per customer as a result of a bill stabilization adjustment (BSA) that provides for a fixed distribution charge per customer by customer class. While Operating revenues from electric distribution customers in Maryland are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers.
Weather. The demand for electricity and natural gas in Delaware is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and natural gas businesses, very cold weather in winter months are referred to as "favorable weather conditions” because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces
demand. During the three and six months ended SeptemberJune 30, 20212022 compared to the same period in 2020,2021, Operating revenues related to weather decreased due to the impact of unfavorable weather conditions in DPL's Delaware natural gas service territory. During the nine months ended September 30, 2021 compared to the same period in 2020, Operating revenues related to weather increased due to the impact of favorable weather conditions in DPL's Delaware electric service territory.remained relatively consistent.
Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 20-year period in DPL's Delaware electric service territory and a 30-year period in DPL's Delaware natural gas service territory. The changes in heating and cooling degree days in DPL’s Delaware service territory for the three and ninesix months ended SeptemberJune 30, 20212022 compared to same period in 20202021 and normal weather consisted of the following:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | Three Months Ended June 30, | | % Change |
| Delaware Electric Service Territory | Delaware Electric Service Territory | | | % Change | Delaware Electric Service Territory | 2022 | | 2021 | | Normal | | 2022 vs. 2021 | | 2022 vs. Normal |
| Three Months Ended September 30, | 2021 | | 2020 | | Normal | | 2021 vs. 2020 | | 2021 vs. Normal | |
| Heating Degree-Days | Heating Degree-Days | 11 | | | 55 | | | 29 | | | (80.0) | % | | (62.1) | % | Heating Degree-Days | 441 | | | 480 | | | 471 | | | (8.1) | % | | (6.4) | % |
| Cooling Degree-Days | Cooling Degree-Days | 969 | | | 961 | | | 894 | | | 0.8 | % | | 8.4 | % | Cooling Degree-Days | 328 | | | 361 | | | 336 | | | (9.1) | % | | (2.4) | % |
| | | | | % Change | | Six Months Ended June 30, | | % Change |
| Nine Months Ended September 30, | 2021 | | 2020 | | Normal | | 2021 vs. 2020 | | 2021 vs. Normal | |
| | | 2022 | | 2021 | | Normal | | 2022 vs. 2021 | | 2022 vs. Normal |
| Heating Degree-Days | Heating Degree-Days | 2,848 | | | 2,664 | | | 2,993 | | | 6.9 | % | | (4.8) | % | Heating Degree-Days | 2,796 | | | 2,838 | | | 2,951 | | | (1.5) | % | | (5.3) | % |
| Cooling Degree-Days | Cooling Degree-Days | 1,333 | | | 1,260 | | | 1,228 | | | 5.8 | % | | 8.6 | % | Cooling Degree-Days | 331 | | | 364 | | | 336 | | | (9.1) | % | | (1.5) | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | Three Months Ended June 30, | | % Change |
| Delaware Natural Gas Service Territory | Delaware Natural Gas Service Territory | | | % Change | Delaware Natural Gas Service Territory | 2022 | | 2021 | | Normal | | 2022 vs. 2021 | | 2022 vs. Normal |
| Three Months Ended September 30, | 2021 | | 2020 | | Normal | | 2021 vs. 2020 | | 2021 vs. Normal | |
| Heating Degree-Days | Heating Degree-Days | 11 | | | 55 | | | 38 | | | (80.0) | % | | (71.1) | % | Heating Degree-Days | 441 | | | 480 | | | 492 | | | (8.1) | % | | (10.4) | % |
| | | | | % Change | | Six Months Ended June 30, | | % Change |
| Nine Months Ended September 30, | 2021 | | 2020 | | Normal | | 2021 vs. 2020 | | 2021 vs. Normal | |
| | | 2022 | | 2021 | | Normal | | 2022 vs. 2021 | | 2022 vs. Normal |
| Heating Degree-Days | Heating Degree-Days | 2,848 | | | 2,664 | | | 3,025 | | | 6.9 | % | | (5.9) | % | Heating Degree-Days | 2,796 | | | 2,838 | | | 2,993 | | | (1.5) | % | | (6.6) | % |
Volume, exclusive of the effects of weather, remained relatively consistent for the three and nine months ended SeptemberJune 30, 20212022 compared to the same period in 2020.2021 and increased for the six months ended June 30, 2022 compared to the same period in2021 primarily due to customer growth and usage.
| | Electric Retail Deliveries to Delaware Customers (in GWhs) | Electric Retail Deliveries to Delaware Customers (in GWhs) | Three Months Ended
September 30, | | % Change | | Weather - Normal % Change(b) | | Nine Months Ended
September 30, | | % Change | | Weather - Normal % Change(b) | Electric Retail Deliveries to Delaware Customers (in GWhs) | Three Months Ended
June 30, | | % Change | | Weather - Normal % Change(b) | | Six Months Ended
June 30, | | % Change | | Weather - Normal % Change(b) |
| 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 | |
| Residential | Residential | 973 | | | 1,028 | | | (5.4) | % | | (5.1) | % | | 2,530 | | | 2,474 | | | 2.3 | % | | (0.3) | % | Residential | 675 | | | 703 | | | (4.0) | % | | (1.7) | % | | 1,570 | | | 1,557 | | | 0.8 | % | | 1.6 | % |
| Small commercial & industrial | Small commercial & industrial | 412 | | | 373 | | | 10.5 | % | | 10.8 | % | | 1,111 | | | 943 | | | 17.8 | % | | 16.3 | % | Small commercial & industrial | 337 | | | 357 | | | (5.6) | % | | (4.8) | % | | 706 | | | 699 | | | 1.0 | % | | 1.4 | % |
| Large commercial & industrial | Large commercial & industrial | 860 | | | 775 | | | 11.0 | % | | 11.2 | % | | 2,359 | | | 2,408 | | | (2.0) | % | | (2.5) | % | Large commercial & industrial | 773 | | | 810 | | | (4.6) | % | | (4.2) | % | | 1,538 | | | 1,499 | | | 2.6 | % | | 2.8 | % |
| Public authorities & electric railroads | Public authorities & electric railroads | 7 | | | 6 | | | 16.7 | % | | 21.6 | % | | 26 | | | 23 | | | 13.0 | % | | 11.0 | % | Public authorities & electric railroads | 8 | | | 10 | | | (20.0) | % | | (19.9) | % | | 17 | | | 19 | | | (10.5) | % | | (7.9) | % |
Total electric retail deliveries(a) | Total electric retail deliveries(a) | 2,252 | | | 2,182 | | | 3.2 | % | | 3.6 | % | | 6,026 | | | 5,848 | | | 3.0 | % | | 1.5 | % | Total electric retail deliveries(a) | 1,793 | | | 1,880 | | | (4.6) | % | | (3.5) | % | | 3,831 | | | 3,774 | | | 1.5 | % | | 2.0 | % |
189 | | | | | | | | | | | |
| As of June 30, |
| Number of Total Electric Customers (Maryland and Delaware) | 2022 | | 2021 |
| Residential | 479,728 | | | 475,061 | |
| Small commercial & industrial | 63,574 | | | 62,880 | |
| Large commercial & industrial | 1,222 | | | 1,213 | |
| Public authorities & electric railroads | 598 | | | 607 | |
| Total | 545,122 | | | 539,761 | |
| | | | | | | | | | | |
| As of September 30, |
| Number of Total Electric Customers (Maryland and Delaware) | 2021 | | 2020 |
| Residential | 476,008 | | | 471,875 | |
| Small commercial & industrial | 62,990 | | | 62,291 | |
| Large commercial & industrial | 1,215 | | | 1,234 | |
| Public authorities & electric railroads | 605 | | | 610 | |
| Total | 540,818 | | | 536,010 | |
___________________
(a)Reflects delivery volumes from customers purchasing electricity directly from DPL and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges.
(b)Reflects the change in delivery volumes assuming normalized weather based on the historical 20-year average.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Natural Gas Retail Deliveries to Delaware Customers (in mmcf) | Three Months Ended
September 30, | | % Change | | Weather - Normal % Change(b) | | Nine Months Ended
September 30, | | % Change | | Weather - Normal % Change(b) |
| 2021 | | 2020 | | | | 2021 | | 2020 | | |
| Residential | 399 | | | 441 | | | (9.5) | % | | 8.8 | % | | 5,507 | | | 5,256 | | | 4.8 | % | | (1.2) | % |
| Small commercial & industrial | 352 | | | 339 | | | 3.8 | % | | 13.9 | % | | 2,647 | | | 2,567 | | | 3.1 | % | | (2.2) | % |
| Large commercial & industrial | 395 | | | 402 | | | (1.7) | % | | (1.8) | % | | 1,247 | | | 1,265 | | | (1.4) | % | | (1.6) | % |
| Transportation | 1,303 | | | 1,231 | | | 5.8 | % | | 7.2 | % | | 4,997 | | | 4,811 | | | 3.9 | % | | 2.3 | % |
Total natural gas deliveries(a) | 2,449 | | | 2,413 | | | 1.5 | % | | 6.9 | % | | 14,398 | | | 13,899 | | | 3.6 | % | | 0.3 | % |
131
| | | | | | | | | | | |
| As of September 30, |
| Number of Delaware Natural Gas Customers | 2021 | | 2020 |
| Residential | 127,740 | | | 126,659 | |
| Small commercial & industrial | 9,935 | | | 9,885 | |
| Large commercial & industrial | 21 | | | 17 | |
| Transportation | 158 | | | 160 | |
| Total | 137,854 | | | 136,721 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Natural Gas Retail Deliveries to Delaware Customers (in mmcf) | Three Months Ended
June 30, | | % Change | | Weather - Normal % Change(b) | | Six Months Ended
June 30, | | % Change | | Weather - Normal % Change(b) |
| 2022 | | 2021 | | | | 2022 | | 2021 | | |
| Residential | 983 | | | 713 | | | 37.9 | % | | 44.6 | % | | 5,436 | | | 5,107 | | | 6.4 | % | | 6.3 | % |
| Small commercial & industrial | 570 | | | 430 | | | 32.6 | % | | 39.2 | % | | 2,550 | | | 2,295 | | | 11.1 | % | | 12.0 | % |
| Large commercial & industrial | 402 | | | 393 | | | 2.3 | % | | 2.3 | % | | 863 | | | 853 | | | 1.2 | % | | 1.1 | % |
| Transportation | 1,444 | | | 1,470 | | | (1.8) | % | | (0.7) | % | | 3,650 | | | 3,694 | | | (1.2) | % | | (0.7) | % |
Total natural gas deliveries(a) | 3,399 | | | 3,006 | | | 13.1 | % | | 16.3 | % | | 12,499 | | | 11,949 | | | 4.6 | % | | 4.9 | % |
| | | | | | | | | | | |
| As of June 30, |
| Number of Delaware Natural Gas Customers | 2022 | | 2021 |
| Residential | 128,715 | | | 127,503 | |
| Small commercial & industrial | 10,068 | | | 9,953 | |
| Large commercial & industrial | 16 | | | 18 | |
| Transportation | 157 | | | 158 | |
| Total | 138,956 | | | 137,632 | |
__________
(a)Reflects delivery volumes from customers purchasing natural gas directly from DPL and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges.
(b)Reflects the change in delivery volumes assuming normalized weather based on the historical 30-year average.
Distribution Revenue increased for the three and six months ended SeptemberJune 30, 20212022 compared to the same period in 2020 primarily due to higher electric distribution rates in Delaware that became effective in October 2020. Distribution revenue increased for the nine months ended September 30, 2021 compared to the same period in 2020 primarily due to higher electric distribution rates in Maryland that became effective in July 2020March 2022, higher Distribution System Improvement Charge (DSIC) rates in Delaware that became effective in January 2022, and higher approved electric distribution rates in Delaware that became effective in October 2020.September 2021.
Transmission Revenues. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue increasedremained relatively consistent for the three months ended SeptemberJune 30, 20212022 compared to the same period in 2020, 2021. Transmission revenue increased for the six months ended June 30, 2022 compared to the same period in 2021,primarily due to increases in underlying costs. Transmission revenue increased for the nine months ended September 30, 2021, compared to the same period in 2020, primarily due to the reduction in revenue in 2020 due to the settlement agreement of ongoing transmission related income tax regulatory liabilities and increases in underlying costs and capital investments.
Other Revenue includes rental revenue, revenue related to late payment charges, mutual assistance revenues, and recoveries of other taxes.
Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, DE Renewable Portfolio Standards, SOS procurement and administrative costs, and GCR costs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Purchased power
and fuel expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. CustomersAll customers have the choice to purchase electricity from competitive electric generation suppliers; however, only certain commercial and industrial customers have the choice to purchase natural gas from competitive natural gas suppliers. Customer choice programs do not impact the volume of deliveries as DPL remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation or natural gas from competitive suppliers, DPL either acts as the billing agent or the competitive supplier separately bills its own customers, and therefore DPL does not record Operating revenues or Purchased power and fuel expense related to the electricity.electricity and/or natural gas. For customers that choose to purchase electric generation or natural gas from DPL, DPL is permitted to recover the electricity, natural gas, and REC procurement costs from customers with a slight mark-up and therefore records the amounts related to the electricity, natural gas, and RECs in Operating revenues and Purchased power and fuel expense. DPL recovers electricity and REC procurement costs from customers with a slight mark-up, and natural gas costs without mark-up and records the amount in Operating revenues and Purchased power and fuel expense.mark-up.
See Note 5 -— Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of DPL's revenue disaggregation.
The increase of $7$27 million and $23$61 million for the three and ninesix months ended SeptemberJune 30, 2021,2022, compared to the same period in 2020,2021, respectively, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.
The changes in Operating and maintenance expense consisted of the following:
| | | Three Months Ended
September 30, 2021 | | Nine Months Ended
September 30, 2021 | | Three Months Ended
June 30, 2022 | | Six Months Ended
June 30, 2022 |
| | (Decrease) Increase | | (Decrease) Increase | | Increase (Decrease) | | Increase |
| BSC and PHISCO costs | | BSC and PHISCO costs | $ | 4 | | | $ | 7 | |
| Credit loss expense | | Credit loss expense | 2 | | | 4 | |
| Storm-related costs | Storm-related costs | $ | (16) | | | $ | (20) | | Storm-related costs | — | | | 3 | |
| Pension and non-pension postretirement benefits expense | (1) | | | (2) | | |
| Credit loss expense | (1) | | | (7) | | |
| | Labor, other benefits, contracting and materials | Labor, other benefits, contracting and materials | 2 | | | (1) | | Labor, other benefits, contracting and materials | 2 | | | 1 | |
| BSC and PHISCO costs | 3 | | | 5 | | |
| Other | Other | (1) | | | 3 | | Other | (1) | | | — | |
| | (14) | | | (22) | | | 7 | | | 15 | |
| Regulatory required programs | Regulatory required programs | — | | | (1) | | Regulatory required programs | 1 | | | 2 | |
| Total decrease | $ | (14) | | | $ | (23) | | |
| Total increase | | Total increase | $ | 8 | | | $ | 17 | |
The changes in Depreciation and amortization expense consisted of the following:
| | | Three Months Ended
September 30, 2021 | | Nine Months Ended
September 30, 2021 | | Three Months Ended
June 30, 2022 | | Six Months Ended
June 30, 2022 |
| | Increase | | Increase (Decrease) | | Increase | | Increase (Decrease) |
Depreciation and amortization(a) | Depreciation and amortization(a) | $ | 3 | | | $ | 10 | | Depreciation and amortization(a) | $ | 5 | | | $ | 9 | |
| Regulatory asset amortization | Regulatory asset amortization | — | | | (1) | | Regulatory asset amortization | — | | | (1) | |
| Regulatory required programs | Regulatory required programs | 2 | | | 5 | | Regulatory required programs | — | | | 1 | |
| Total increase | Total increase | $ | 5 | | | $ | 14 | | Total increase | $ | 5 | | | $ | 9 | |
___________________
(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.
Effective income tax rates were 5.7%8.7% and 3.6%3.2% for the three months ended SeptemberJune 30, 20212022 and 2020,2021, respectively, and 6.3%7.2% and (28.2)%6.5% for the ninesix months ended SeptemberJune 30, 2022 and 2021, and 2020, respectively. For the nine months ended September 30, 2021, compared to the same period in 2020, the change is primarily due to the April 24, 2020 settlement agreement of ongoing transmission related income tax regulatory liabilities. See Note 3 — Regulatory Matters of the 2020 Exelon Form 10-K for additional information on the April 24, 2020 settlement agreement, and Note 107 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
Results of Operations — ACE
| | | Three Months Ended September 30, | | Favorable (Unfavorable) Variance | | Nine Months Ended September 30, | | Favorable (Unfavorable) Variance | | Three Months Ended June 30, | | (Unfavorable)Favorable Variance | | Six Months Ended June 30, | | Favorable (Unfavorable) Variance |
| | 2021 | | 2020 | | 2021 | | 2020 | | | 2022 | | 2021 | | 2022 | | 2021 | |
| Operating revenues | Operating revenues | $ | 451 | | | $ | 420 | | | $ | 31 | | | $ | 1,080 | | | $ | 952 | | | $ | 128 | | Operating revenues | $ | 309 | | | $ | 319 | | | $ | (10) | | | $ | 658 | | | $ | 629 | | | $ | 29 | |
| | Operating expenses | Operating expenses | | Operating expenses | |
| Purchased power | Purchased power | 230 | | | 211 | | | (19) | | | 541 | | | 469 | | | (72) | | Purchased power | 123 | | | 154 | | | 31 | | | 301 | | | 311 | | | 10 | |
| Operating and maintenance | Operating and maintenance | 81 | | | 77 | | | (4) | | | 231 | | | 238 | | | 7 | | Operating and maintenance | 86 | | | 73 | | | (13) | | | 170 | | | 150 | | | (20) | |
| Depreciation and amortization | Depreciation and amortization | 46 | | | 48 | | | 2 | | | 133 | | | 134 | | | 1 | | Depreciation and amortization | 72 | | | 40 | | | (32) | | | 118 | | | 87 | | | (31) | |
| Taxes other than income taxes | Taxes other than income taxes | 2 | | | 2 | | | — | | | 6 | | | 6 | | | — | | Taxes other than income taxes | 2 | | | 2 | | | — | | | 4 | | | 4 | | | — | |
| Total operating expenses | Total operating expenses | 359 | | | 338 | | | (21) | | | 911 | | | 847 | | | (64) | | Total operating expenses | 283 | | | 269 | | | (14) | | | 593 | | | 552 | | | (41) | |
| Gain on sales of assets | — | | | — | | | — | | | — | | | 2 | | | (2) | | |
| | Operating income | Operating income | 92 | | | 82 | | | 10 | | | 169 | | | 107 | | | 62 | | Operating income | 26 | | | 50 | | | (24) | | | 65 | | | 77 | | | (12) | |
| Other income and (deductions) | Other income and (deductions) | | | | | | | | | | | | Other income and (deductions) | | | | | | | | | | | |
| Interest expense, net | Interest expense, net | (14) | | | (15) | | | 1 | | | (43) | | | (45) | | | 2 | | Interest expense, net | (17) | | | (14) | | | (3) | | | (32) | | | (29) | | | (3) | |
| Other, net | Other, net | 1 | | | 1 | | | — | | | 3 | | | 5 | | | (2) | | Other, net | 2 | | | — | | | 2 | | | 5 | | | 2 | | | 3 | |
| Total other income and (deductions) | Total other income and (deductions) | (13) | | | (14) | | | 1 | | | (40) | | | (40) | | | — | | Total other income and (deductions) | (15) | | | (14) | | | (1) | | | (27) | | | (27) | | | — | |
| Income before income taxes | Income before income taxes | 79 | | | 68 | | | 11 | | | 129 | | | 67 | | | 62 | | Income before income taxes | 11 | | | 36 | | | (25) | | | 38 | | | 50 | | | (12) | |
| Income taxes | Income taxes | (11) | | | (7) | | | 4 | | | (12) | | | (39) | | | (27) | | Income taxes | — | | | (1) | | | (1) | | | 1 | | | (1) | | | (2) | |
| Net income | Net income | $ | 90 | | | $ | 75 | | | $ | 15 | | | $ | 141 | | | $ | 106 | | | $ | 35 | | Net income | $ | 11 | | | $ | 37 | | | $ | (26) | | | $ | 37 | | | $ | 51 | | | $ | (14) | |
Three Months Ended SeptemberJune 30, 20212022 Compared to Three Months Ended SeptemberJune 30, 2020.2021. Net income decreased by $26 million primarily due to the absence of favorable weather and volume as a result of the CIP, an increase in depreciation expense, various operating expenses, and timing of excess deferred tax amortization, partially offset by increases in distribution rates.
Six Months Ended June 30, 2022 Compared to Six Months Ended June 30, 2021. Net income increaseddecreased by $15$14 million primarily due to higher distribution ratesthe absence of favorable weather and higher transmission revenues due tovolume as a result of the CIP, an increase in capital investments.
Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020. Net income increaseddepreciation expense, various operating expenses, and timing of excess deferred tax amortization, partially offset by $35 million primarily due to higherincreases in distribution rates, higher distribution revenues due to an increase in volume in ACE's service territory, and higher transmission revenues due to an increase in capital investments.rates.
The changes in Operating revenues consisted of the following:
| | | Three Months Ended
September 30, 2021 | | Nine Months Ended September 30, 2021 | | Three Months Ended
June 30, 2022 | | Six Months Ended June 30, 2022 |
| | (Decrease) Increase | | Increase (Decrease) | | (Decrease) Increase | | (Decrease) Increase |
| Weather | Weather | $ | (3) | | | $ | — | | Weather | $ | (3) | | | $ | (3) | |
| Volume | Volume | 3 | | | 19 | | Volume | (13) | | | (11) | |
| Distribution | Distribution | 4 | | | 3 | | Distribution | 8 | | | 20 | |
| Transmission | Transmission | 10 | | | 46 | | Transmission | (3) | | | 3 | |
| Other | (1) | | | (1) | | |
| | | 13 | | | 67 | | | (11) | | | 9 | |
| | Regulatory required programs | Regulatory required programs | 18 | | | 61 | | Regulatory required programs | 1 | | | 20 | |
| Total increase | $ | 31 | | | $ | 128 | | |
| Total (decrease) increase | | Total (decrease) increase | $ | (10) | | | $ | 29 | |
Revenue Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from electric distribution in New Jersey are not impacted by abnormal weather or usage per customer as a result of the Conservation Incentive Program (CIP)CIP which became effective, prospectively, in the third quarter of 2021. The CIP compares current distribution revenues by customer class to approved target revenues established in ACE’s most recent distribution base rate case. The CIP is calculated annually, and recovery is subject to certain conditions, including an earnings test and ceilings on customer rate increases. While Operating revenues are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers. See Note 3 — Regulatory Matters of the Combined Notes to the Consolidated Financial Statements for additional information.
Weather.Prior to the third quarter of 2021, the demand for electricity was affected by weather conditions. With respect to the electric business, very warm weather in summer months and very cold weather in winter months are referred to as “favorable weather conditions” because these weather conditions result in increased deliveries of electricity. Conversely, mild weather reduces demand. During the three and six months ended SeptemberJune 30, 20212022 compared to the same period in 2020,2021, Operating revenues related to weather decreased due to the absence of favorable impacts in the thirdfirst and second quarter of 20212022 as a result of the CIP. During the nine months ended September 30, 2021 compared to the same period in 2020, Operating revenues related to weather remained relatively consistent.
Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 20-year period in ACE’s service territory. The changes in heating and cooling degree days in ACE’s service territory for the ninethree and six months ended SeptemberJune 30, 20212022 compared to same period in 20202021 and normal weather consisted of the following:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | Three Months Ended June 30, | | Normal | | % Change |
| Heating and Cooling Degree-Days | Heating and Cooling Degree-Days | | % Change | Heating and Cooling Degree-Days | 2022 | | 2021 | | 2022 vs. 2021 | | 2022 vs. Normal |
| | | Nine Months Ended September 30, | 2021 | | 2020 | | Normal | | 2021 vs. 2020 | | 2021 vs. Normal | |
| Heating Degree-Days | Heating Degree-Days | 2,884 | | | 2,618 | | | 3,042 | | | 10.2 | % | | (5.2) | % | Heating Degree-Days | 533 | | | 525 | | | 540 | | | 1.5 | % | | (1.3) | % |
| Cooling Degree-Days | Cooling Degree-Days | 1,246 | | | 1,300 | | | 1,165 | | | (4.2) | % | | 7.0 | % | Cooling Degree-Days | 275 | | | 321 | | | 305 | | | (14.3) | % | | (9.8) | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Six Months Ended June 30, | | Normal | | % Change |
| Heating and Cooling Degree-Days | 2022 | | 2021 | | | 2022 vs. 2021 | | 2022 vs. Normal |
| Heating Degree-Days | 2,969 | | | 2,873 | | | 2,994 | | | 3.3 | % | | (0.8) | % |
| Cooling Degree-Days | 277 | | | 325 | | | 305 | | | (14.8) | % | | (9.2) | % |
Volume, exclusive of the effects of weather, increaseddecreased for the ninethree and six months ended SeptemberJune 30, 20212022 compared to the same period in 2020, primarily2021, due to customer growththe absence of favorable impacts in the first and usage.second quarter of 2022 as a result of the CIP.
| | Electric Retail Deliveries to Customers (in GWhs) | Electric Retail Deliveries to Customers (in GWhs) | | Nine Months Ended
September 30, | | % Change | | Weather - Normal % Change(b) | Electric Retail Deliveries to Customers (in GWhs) | Three Months Ended
June 30, | | % Change | | Weather - Normal % Change(b) | | Six Months Ended
June 30, | | % Change | | Weather - Normal % Change(b) |
| 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 | |
| Residential | Residential | | 3,443 | | | 3,193 | | | 7.8 | % | | 7.1 | % | Residential | 859 | | | 975 | | | (11.9) | % | | (9.7) | % | | 1,777 | | | 1,903 | | | (6.6) | % | | (6.0) | % |
| Small commercial & industrial | Small commercial & industrial | | 1,073 | | | 967 | | | 11.0 | % | | 11.1 | % | Small commercial & industrial | 362 | | | 333 | | | 8.7 | % | | 9.7 | % | | 701 | | | 638 | | | 9.9 | % | | 9.7 | % |
| Large commercial & industrial | Large commercial & industrial | | 2,351 | | | 2,287 | | | 2.8 | % | | 3.1 | % | Large commercial & industrial | 808 | | | 761 | | | 6.2 | % | | 6.7 | % | | 1,511 | | | 1,477 | | | 2.3 | % | | 2.3 | % |
| Public authorities & electric railroads | Public authorities & electric railroads | | 33 | | | 33 | | | — | % | | 0.7 | % | Public authorities & electric railroads | 11 | | | 11 | | | — | % | | (5.8) | % | | 25 | | | 24 | | | 4.2 | % | | 0.6 | % |
Total electric retail deliveries(a) | Total electric retail deliveries(a) | | 6,900 | | | 6,480 | | | 6.5 | % | | 6.3 | % | Total electric retail deliveries(a) | 2,040 | | | 2,080 | | | (1.9) | % | | (0.5) | % | | 4,014 | | | 4,042 | | | (0.7) | % | | (0.5) | % |
| | | As of September 30, | | As of June 30, |
| Number of Electric Customers | Number of Electric Customers | 2021 | | 2020 | Number of Electric Customers | 2022 | | 2021 |
| Residential | Residential | 499,775 | | | 497,222 | | Residential | 501,494 | | | 499,436 | |
| Small commercial & industrial | Small commercial & industrial | 61,838 | | | 61,521 | | Small commercial & industrial | 62,291 | | | 61,836 | |
| Large commercial & industrial | Large commercial & industrial | 3,209 | | | 3,305 | | Large commercial & industrial | 3,085 | | | 3,243 | |
| Public authorities & electric railroads | Public authorities & electric railroads | 707 | | | 694 | | Public authorities & electric railroads | 726 | | | 707 | |
| Total | Total | 565,529 | | | 562,742 | | Total | 567,596 | | | 565,222 | |
___________________
(a)Reflects delivery volumes from customers purchasing electricity directly from ACE and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges.
(b)Reflects the change in delivery volumes assuming normalized weather based on the historical 20-year average.
Distribution Revenue increased for the three and ninesix months ended SeptemberJune 30, 20212022 compared to the same period in 20202021 due tohigher distribution rates.rates that became effective in January 2022.
Transmission Revenues. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue increaseddecreased for thethree months ended SeptemberJune 30, 20212022 compared to the same period in 2020,2021, primarily due to decreases in underlying costs, partially offset by increases in capital investment. Transmission revenue increased for the ninesix months ended SeptemberJune 30, 2021 2022 compared to the same period in 2020,2021, primarily due to the reduction in revenue in 2020 due to the settlement agreement of ongoing transmission related income tax regulatory liabilities and increasesan increase in capital investment.
Other Revenue includes rental revenue, service connection fees, and mutual assistance revenues.
Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, Societal Benefits Charge, Transition Bonds, and BGS procurement and administrative costs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Purchased power expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries, as ACE remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation from competitive suppliers, ACE either acts as the billing agent or the competitive supplier separately bills its own customers, and therefore, ACE does not record Operating revenues or Purchased power expense related to the electricity. For customers that choose to purchase electric generation from ACE, ACE is permitted to recover the electricity, ZEC, and REC procurement costs without mark-up and therefore records equal and offsetting amounts in Operating revenues and Purchased power expense related to the electricity, ZECs, and RECs.
See Note 5 -— Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ACE's revenue disaggregation.
The increasedecrease of $19$31 million and $72$10 million for the three and ninesix months ended SeptemberJune 30, 20212022 compared to the same period in 2020,2021, respectively, in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs.
The changes in Operating and maintenance expense consisted of the following:
| | | Three Months Ended
September 30, 2021 | | Nine Months Ended September 30, 2021 | | Three Months Ended
June 30, 2022 | | Six Months Ended June 30, 2022 |
| | Increase (Decrease) | | Increase (Decrease) | | Increase | | Increase |
| Labor, other benefits, contracting and materials | | Labor, other benefits, contracting and materials | $ | 4 | | | $ | 4 | |
| BSC and PHISCO costs | BSC and PHISCO costs | $ | 2 | | | $ | 4 | | BSC and PHISCO costs | 3 | | | 4 | |
| Labor, other benefits, contracting and materials | 2 | | | (2) | | |
| Pension and non-pension postretirement benefits expense | — | | | (1) | | |
| Storm-related costs | | Storm-related costs | 1 | | | 2 | |
| Credit loss expense | | Credit loss expense | 1 | | | — | |
| | Storm-related costs | (2) | | | (5) | | |
| Other | Other | (3) | | | (2) | | Other | 1 | | | 3 | |
| | (1) | | | (6) | | | 10 | | | 13 | |
| Regulatory required programs(a) | Regulatory required programs(a) | 5 | | | (1) | | Regulatory required programs(a) | 3 | | | 7 | |
| Total increase (decrease) | $ | 4 | | | $ | (7) | | |
| Total increase | | Total increase | $ | 13 | | | $ | 20 | |
___________________
(a)ACE is allowed to recover from or refund to customers the difference between its annual credit loss expense and the amounts collected in rates annually through the Societal Benefits Charge.
The changes in Depreciation and amortization expense consisted of the following:
| | | Three Months Ended
September 30, 2021 | | Nine Months Ended September 30, 2021 | | Three Months Ended
June 30, 2022 | | Six Months Ended June 30, 2022 |
| | Increase (Decrease) | | Increase (Decrease) | | Increase | | Increase |
Depreciation and amortization(a) | Depreciation and amortization(a) | $ | 4 | | | $ | 11 | | Depreciation and amortization(a) | $ | 4 | | | $ | 7 | |
| Regulatory asset amortization | Regulatory asset amortization | — | | | (1) | | Regulatory asset amortization | — | | | 1 | |
Regulatory required programs | Regulatory required programs | (6) | | | (11) | | Regulatory required programs | 28 | | | 23 | |
| Total decrease | $ | (2) | | | $ | (1) | | |
| Total increase | | Total increase | $ | 32 | | | $ | 31 | |
___________________
(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.
(b)Regulatory required programs increased primarily due to the regulatory asset amortization of the PPA termination obligation which is fully offset in Operating revenues.
Effective income tax rates were (13.9)%0.0% and (10.3)(2.8)% for the three months ended SeptemberJune 30, 20212022 and 2020,2021, respectively, and (9.3)%2.6% and (58.2)(2.0)% for the ninesix months ended SeptemberJune 30, 2022 and 2021, respectively. The three and 2020, respectively. For the ninesix months ended SeptemberJune 30, 2021, compared to2022 changes primarily reflect the same period in 2020, the change is primarily due to the April 24, 2020 settlement agreementtiming of ongoing transmission related incomeexcess deferred tax regulatory liabilities, partially offset by the July 14, 2021 settlement which allowed ACE to retain certain tax benefits.amortization. See Note 3 — Regulatory Matters of the 2020 Exelon Form 10-K for additional information on the April 24, 2020
settlement. See Note 3 — Regulatory Matters and Note 107 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information on the July 14, 2021 settlement agreement and regarding the components of the effective income tax rates, respectively.rates.
Liquidity and Capital Resources (All Registrants)
All results included throughout the liquidity and capital resources section are presented on a GAAP basis.
The Registrants’ operating and capital expenditures requirements are provided by internally generated cash flows from operations, the sale of certain receivables, as well as funds from external sources in the capital markets and through bank borrowings. The Registrants’ businesses are capital intensive and require considerable capital resources. Each of the Registrants annually evaluates its financing plan, dividend practices, and credit line sizing, focusing on maintaining its investment grade ratings while meeting its cash needs to fund capital requirements, including construction expenditures, retire debt, pay dividends, and fund pension and OPEB obligations,obligations. The Registrants spend a significant amount of cash on capital improvements and investconstruction projects that have a long-term return on investment. Additionally, the Utility Registrants operate in rate-regulated environments in which the amount of new investment recovery may be delayed or limited and existing ventures. A broad spectrumwhere such recovery takes place over an extended period of financing alternatives beyond the core financing options can be used to meet its needs and fund growth including monetizing assets in the portfolio via project financing, asset sales, and the use of other financing structures (e.g., joint ventures, minority partners, etc.).time. Each Registrant’s access to external financing on reasonable terms depends on its credit ratings and current overall capital market business conditions, including that of the utility industry in general. If these conditions deteriorate to the extent that the Registrants no longer have access to the capital markets at reasonable terms, the Registrants have access to credit facilities with aggregate bank commitments of $10.3$4.0 billion. The Registrants utilize their credit facilities to support their commercial paper programs, provide for other short-term borrowings and to issue letters of credit. See the “Credit Matters”Matters and Cash Requirements” section below for additional information. The Registrants expect cash flows to be sufficient to meet operating expenses, financing costs, and capital expenditure requirements.
The Registrants primarily use their capital resources, including cash, to fund capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and OPEB obligations, and invest in new and existing ventures. The Registrants spend a significant amount of cash on capital improvements and construction projects that have a long-term return on investment. Additionally, the Utility Registrants operate in rate-regulated environments in which the amount of new investment recovery may be delayed or limited and where such recovery takes place over an extended period of time. See Note 1310 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ debt and credit agreements.
NRC Minimum Funding Requirements (ExelonCash flows related to Constellation have not been presented as discontinued operations and Generation)
NRC regulations require that licenseesare included in the Consolidated Statements of nuclear generating facilities demonstrate reasonable assurance that sufficient funds will be available in certain minimum amounts to decommissionCash Flows for all periods presented. The Exelon Consolidated Statement of Cash Flows for the facility. These NRC minimum funding levels are typically based uponsix months ended June 30, 2022 includes one month of cash flows from Generation. The Exelon Consolidated Statement of Cash Flows for the assumption that decommissioning activities will commence after the end of the current licensed life of each unit. If a unit fails the NRC minimum funding test, then the plant’s owners or parent companies would be required to take steps, such as providing financial guarantees through letters of credit or parent company guarantees or making additional cash contributions to the NDT fund to ensure sufficient funds are available. See Note 8 — Nuclear Decommissioning of the Combined Notes to Consolidated Financial Statements for additional information.
If a nuclear plant were to early retire there is a risk that it will no longer meet the NRC minimum funding requirements due to the earlier commencement of decommissioning activities and a shorter time period over which the NDT funds could appreciate in value. A shortfall could require that Generation address the shortfall by providing additional financial assurances such as surety bonds, letters of credit, or parent company guarantees for Generation’s share of the funding assurance. However, the amount of any assurance will ultimately depend on the decommissioning approach, the associated level of costs, and the NDT fund investment performance going forward. No later than two years after shutting down a plant, Generation must submit a PSDAR to the NRC that includes the planned option for decommissioning the site. As a result of the early retirement reversal, additional financial assurance is no longer required for Byron.
Upon issuance of any required financial assurance, subject to satisfying various regulatory preconditions, each site would be able to utilize the respective NDT funds for radiological decommissioning costs, which represent the majority of the total expected decommissioning costs. However, under the regulations, the NRC must approve an exemption in order for Generation to utilize the NDT funds to pay for non-radiological decommissioning costs (i.e. spent fuel management and site restoration costs, if applicable). If a unit does not receive this exemption, those costs would be borne by Generation without reimbursement from or access to the NDT funds.
As of Septembersix months ended June 30, 2021 Generation is not required to provide any additional financial assurances for TMI Unit 1 under the SAFSTOR scenario whichincludes six months of cash flows from Generation. This is the planned decommissioning optionprimary reason for the changes in cash flows as describedshown in the TMI Unit 1 PSDAR filed by Generation with the NRC on April 5, 2019. On October 16, 2019, the NRC granted Generation's exemption request to use the TMI Unit 1 NDT funds for spent fuel management costs. An additional exemption request to allow the TMI Unit 1 NDT funds to be used for site restoration costs was submitted to the NRC on May 20, 2021 and is pending NRC review.tables unless otherwise noted below.
Cash Flows from Operating Activities(All Registrants)
Generation’s cash flows from operating activities primarily result from the sale of electric energy and energy-related products and services to customers. Generation’s future cash flows from operating activities may be affected by future demand for, and market prices of, energy and its ability to continue to produce and supply power at competitive costs, as well as to obtain collections from customers and the sale of certain receivables.
The Utility Registrants' cash flows from operating activities primarily result from the transmission and distribution of electricity and, in the case of PECO, BGE, and DPL, gas distribution services. The Utility Registrants' distribution services are provided to an established and diverse base of retail customers. The Utility Registrants' future cash flows may be affected by the economy, weather conditions, future legislative initiatives, future regulatory proceedings with respect to their rates or operations, and their ability to achieve operating cost reductions.
See Note 3 — Regulatory Matters of the 2021 Recast Form 10-K and Note 19Notes 3 — Regulatory Matters and 12 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements of the Exelon 2020 Form 10-K for additional information on regulatory and legal proceedings and proposed legislation.
The following table provides a summary of the change in cash flows from operating activities for the ninesix months ended SeptemberJune 30, 20212022 and 20202021 by Registrant:
| | (Decrease) increase in cash flows from operating activities | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | |
| Net income | $ | (78) | | | $ | (607) | | | $ | 305 | | | $ | 66 | | | $ | 17 | | | $ | 117 | | | $ | 37 | | | $ | 44 | | | $ | 35 | | |
| Increase (decrease) in cash flows from operating activities | | Increase (decrease) in cash flows from operating activities | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Net income (loss) | | Net income (loss) | $ | 852 | | | $ | 25 | | | $ | 68 | | | $ | (20) | | | $ | (39) | | | $ | (18) | | | $ | (9) | | | $ | (14) | |
| Adjustments to reconcile net income to cash: | Adjustments to reconcile net income to cash: | | Adjustments to reconcile net income to cash: | |
| Non-cash operating activities | Non-cash operating activities | (899) | | | (527) | | | (216) | | | 1 | | | (4) | | | (22) | | | 8 | | | (10) | | | (23) | | Non-cash operating activities | (714) | | | (2) | | | 14 | | | 82 | | | 164 | | | 57 | | | 33 | | | 72 | |
| Option premiums (paid), net | | Option premiums (paid), net | (41) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Collateral received, net | | Collateral received, net | 732 | | | 58 | | | — | | | 188 | | | 403 | | | 85 | | | 180 | | | 137 | |
| Income taxes | | Income taxes | (167) | | | 15 | | | 25 | | | — | | | (1) | | | (4) | | | (8) | | | 6 | |
| Pension and non-pension postretirement benefit contributions | Pension and non-pension postretirement benefit contributions | (22) | | | 12 | | | (31) | | | 3 | | | (2) | | | (8) | | | (1) | | | — | | | — | | Pension and non-pension postretirement benefit contributions | (26) | | | (5) | | | 2 | | | 12 | | | (30) | | | — | | | (1) | | | (4) | |
| Income taxes | 281 | | | 65 | | | 13 | | | 7 | | | (43) | | | 31 | | | 1 | | | 31 | | | 6 | | |
| Changes in working capital and other noncurrent assets and liabilities | (775) | | | (611) | | | (28) | | | (75) | | | (25) | | | (92) | | | (134) | | | 28 | | | 27 | | |
| Option premiums paid, net | (55) | | | (55) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | |
| Collateral received, net | 1,467 | | | 1,334 | | | 65 | | | — | | | — | | | — | | | — | | | — | | | — | | |
| (Decrease) increase in cash flows from operating activities | $ | (81) | | | $ | (389) | | | $ | 108 | | | $ | 2 | | | $ | (57) | | | $ | 26 | | | $ | (89) | | | $ | 93 | | | $ | 45 | | |
| Changes in regulatory assets and liabilities, net | | Changes in regulatory assets and liabilities, net | (100) | | | (86) | | | (10) | | | 25 | | | (38) | | | 2 | | | 2 | | | (29) | |
| Changes in working capital and other assets and liabilities | | Changes in working capital and other assets and liabilities | 1,566 | | | 25 | | | (61) | | | 1 | | | (46) | | | (16) | | | (7) | | | (17) | |
| Increase in cash flows from operating activities | | Increase in cash flows from operating activities | $ | 2,102 | | | $ | 30 | | | $ | 38 | | | $ | 288 | | | $ | 413 | | | $ | 106 | | | $ | 190 | | | $ | 151 | |
Changes in the Registrants' cash flows from operations were generally consistent with changes in each Registrant’s respective results of operations, as adjusted by changes in working capital in the normal course of business, except as discussed below. In addition, significantSee above for additional information related to cash flows from Generation. Significant operating cash flow impacts for the Registrants and Generation for the ninesix months ended SeptemberJune 30, 20212022 and 20202021 were as follows:
•See Note 1814 — Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements and the Registrants’ Consolidated Statements of Cash Flows for additional information on non-cash operating activities.
197
•See Note 107 — Income Taxes of the Combined Notes to Consolidated Financial Statements and the Registrants' Consolidated Statements of Cash Flows for additional information on income taxes.
•Changes in working capital and other noncurrent assets and liabilities include a decrease in Accounts receivable resulting from the impact of cash received at Exelon and Generation in 2020 related to the revolving accounts receivable financing arrangement entered into on April 8, 2020 and an increase in Accounts payable and accrued expenses resulting from the impact of certain penalties for natural gas delivery associated with the February 2021 extreme cold weather event at Exelon and Generation. See Note 6 – Accounts Receivable and Note 3 –— Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on the sales of customer accounts receivableregulatory assets and on the February 2021 extreme cold weather event, respectively.liabilities.
•Depending upon whetherChanges in working capital and other assets and liabilities for the Utility Registrants and Exelon Corporate total $(74) million and for Generation is in a net mark-to-market liability or asset position, collateral may be requiredtotal $1,640 million. The change for Generation primarily relates to be posted with or collected from its counterparties. In addition, the collateral posting and collection requirements differ depending on whether the transactions are on an exchange or in the over-the-counter markets.revolving accounts receivable financing arrangement. See Note 126 — Derivative Financial InstrumentsAccounts Receivable of the Combined Notes to Consolidated Financial Statements2021 Form 10-K and the Collection of DPP discussion below for additional information on the Registrants’ collateral.information.
Cash Flows from Investing Activities (All Registrants)
The following table provides a summary of the change in cash flows from investing activities for the ninesix months ended SeptemberJune 30, 20212022 and 20202021 by Registrant:
| | Increase (decrease) in cash flows from investing activities | Increase (decrease) in cash flows from investing activities | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Increase (decrease) in cash flows from investing activities | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Capital expenditures | Capital expenditures | $ | (364) | | | $ | 126 | | | $ | (140) | | | $ | (54) | | | $ | (69) | | | $ | (227) | | | $ | (129) | | | $ | (42) | | | $ | (55) | | Capital expenditures | $ | 533 | | | $ | (46) | | | $ | (81) | | | $ | 42 | | | $ | 113 | | | $ | 37 | | | $ | 17 | | | $ | 60 | |
| Proceeds from NDT fund sales, net | (66) | | | (66) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | |
| | Investment in NDT fund sales, net | | Investment in NDT fund sales, net | 72 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Collection of DPP | | Collection of DPP | (2,040) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Proceeds from sales of assets and businesses | Proceeds from sales of assets and businesses | 755 | | | 756 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Proceeds from sales of assets and businesses | (708) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Changes in intercompany money pool | Changes in intercompany money pool | — | | | — | | | — | | | (68) | | | — | | | — | | | 117 | | | — | | | — | | Changes in intercompany money pool | — | | | — | | | — | | | — | | | — | | | — | | | (64) | | | — | |
| Collection of DPP | 534 | | | 534 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | |
| | Other investing activities | Other investing activities | 42 | | | — | | | 20 | | | 1 | | | 13 | | | (4) | | | 1 | | | 4 | | | (4) | | Other investing activities | (13) | | | 3 | | | 1 | | | (3) | | | 5 | | | 4 | | | 1 | | | — | |
| Increase (decrease) in cash flows from investing activities | $ | 901 | | | $ | 1,350 | | | $ | (120) | | | $ | (121) | | | $ | (56) | | | $ | (231) | | | $ | (11) | | | $ | (38) | | | $ | (59) | | |
| (Decrease) increase in cash flows from investing activities | | (Decrease) increase in cash flows from investing activities | $ | (2,156) | | | $ | (43) | | | $ | (80) | | | $ | 39 | | | $ | 118 | | | $ | 41 | | | $ | (46) | | | $ | 60 | |
Significant investing cash flow impacts for the Registrants for ninesix months ended SeptemberJune 30, 20212022 and 20202021 were as follows:
•Variances in capital expenditures are primarily due to the timing of cash expenditures for capital projects. ReferSee the "Credit Matters and Cash Requirements" section below for additional information on projected capital expenditure spending. See Note 2 — Discontinued Operations of the Combined Notes to Consolidated Financial Statements for capital expenditures related to Generation prior to the separation.
•Collection of DPP relates to the revolving accounts receivable financing agreement which Generation entered into in April of 2020. See Note 6 — Accounts Receivable of the 2021 Form 10-K for additional information on the transaction and the DPP, including the $400 million of additional funding received in February and March of 2021.
•Proceeds from sales of assets and businessesincreased decreased primarily due to the sale of a significant portion of Generation's solar business and a biomass facility and proceeds received on sales of equity investments.in 2021. See Note 2 –— Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements2021 Form 10-K for additional information on the sale of Generation's solar business and biomass facility.information.
•Changes in intercompany money pool are driven by short-term borrowing needs. Refer below for more information regarding the intercompany money pool.
Cash Flows from Financing Activities
The following table provides a summary of the change in cash flows from financing activities for the six months ended June 30, 2022 and 2021 by Registrant:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Increase (decrease) in cash flows from financing activities | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Changes in short-term borrowings, net | $ | 369 | | | $ | 290 | | | $ | 210 | | | $ | (130) | | | $ | (389) | | | $ | (251) | | | $ | (3) | | | $ | (135) | |
| Long-term debt, net | 1,619 | | | 50 | | | (375) | | | (100) | | | 124 | | | 50 | | | — | | | 74 | |
| Changes in intercompany money pool | — | | | — | | | 40 | | | — | | | 29 | | | 64 | | | — | | | — | |
| | | | | | | | | | | | | | | |
| Dividends paid on common stock | 84 | | | (36) | | | (31) | | | (4) | | | — | | | (177) | | | 7 | | | 191 | |
| Distributions to member | — | | | — | | | — | | | — | | | 19 | | | — | | | — | | | — | |
| Contributions from(to) parent/member | — | | | (60) | | | (168) | | | 186 | | | 144 | | | 249 | | | 24 | | | (130) | |
| Transfer of cash, restricted cash, and cash equivalents to Constellation | (2,594) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Other financing activities | (50) | | | (1) | | | (4) | | | (1) | | | (4) | | | (4) | | | (1) | | | — | |
| (Decrease) increase in cash flows from financing activities | $ | (572) | | | $ | 243 | | | $ | (328) | | | $ | (49) | | | $ | (77) | | | $ | (69) | | | $ | 27 | | | $ | — | |
Significant financing cash flow impacts for the Registrants for the six months ended June 30, 2022 and 2021 were as follows:
•Changes in short-term borrowings, net, is driven by repayments on and issuances of notes due in less than 365 days. Refer to Note 10 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on short-term borrowings for the Registrants. These changes also included repayments of $552 million in commercial paper and term loans by Generation prior to the separation.
•Long-term debt, net, varies due to debt issuances and redemptions each year. Refer to Note 10 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on debt issuances. Refer to the debt redemptions table below for additional information.
•Changes in intercompany money pool are driven by short-term borrowing needs. Refer below for more information regarding the intercompany money pool.
•Exelon’s ability to pay dividends on its common stock depends on the receipt of dividends paid by its operating subsidiaries. The payments of dividends to Exelon by its subsidiaries in turn depend on their results of operations and cash flows and other items affecting retained earnings. See Note 6 – Accounts Receivable17 — Commitments and Contingenciesof the 2021 Recast Form 10-K for additional information on dividend restrictions. See below for quarterly dividends declared.
•Refer to Note 2 - Discontinued Operations for the transfer of cash, restricted cash, and cash equivalents to Constellation related to the separation.
•For the six months ended June 30, 2022, other financing activities primarily consists of debt issuance costs. See Note 10 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of the Registrants’ debt issuances.
Debt
See Note 10 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Collection of DPP.Registrants’ debt issuances.
During the six months ended June 30, 2022, the following long-term debt was retired and/or redeemed:
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
Company(a) | | Type | | Interest Rate | | | Maturity | | Amount |
| Exelon | | Junior Subordinated Notes | | 3.50 | % | | | May 2, 2022 | | $ | 1,150 | |
| Exelon | | Long-Term Software License Agreement | | 3.96 | % | | | May 1, 2024 | | 2 | |
| PECO | | First Mortgage Bonds | | 2.375 | % | | | September 15, 2022 | | 350 | |
| Pepco | | First Mortgage Bonds | | 3.05 | % | | | April 1, 2022 | | 200 | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
__________
(a)On July 5, 2022, BGE redeemed $250 million of 2.80% senior notes originally due on August 15, 2022.
Dividends
Quarterly dividends declared by the Exelon Board of Directors during the six months ended June 30, 2022 and for the third quarter of 2022 were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Period | | Declaration Date | | Shareholder of Record Date | | Dividend Payable Date | | Cash per Share(a) |
| First Quarter 2022 | | February 8, 2022 | | February 25, 2022 | | March 10, 2022 | | $ | 0.3375 | |
| Second Quarter 2022 | | April 26, 2022 | | May 13, 2022 | | June 10, 2022 | | $ | 0.3375 | |
| Third Quarter 2022 | | July 26, 2022 | | August 15, 2022 | | September 9, 2022 | | $ | 0.3375 | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
__________
(a)Exelon's Board of Directors approved an updated dividend policy for 2022. The 2022 quarterly dividend will be $0.3375 per share.
Credit Matters and Cash Requirements
The Registrants fund liquidity needs for capital investment, working capital, energy hedging, and other financial commitments through cash flows from continuing operations, public debt offerings, commercial paper markets, and large, diversified credit facilities. The credit facilities include $4.0 billion in aggregate total commitments of which $3.6 billion was available to support additional commercial paper as of June 30, 2022, and of which no financial institution has more than 6% of the aggregate commitments for the Registrants. The Registrants had access to the commercial paper markets and had availability under their revolving credit facilities during the six months ended June 30, 2022 to fund their short-term liquidity needs, when necessary. On February 1, 2022, Exelon Corporate and the Utility Registrants each entered into a new 5-year revolving credit facility that replaced its existing syndicated revolving credit facility. See Note 10 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. The Registrants routinely review the sufficiency of their liquidity position, including appropriate sizing of credit facility commitments, by performing various stress test scenarios, such as commodity price movements, increases in margin-related transactions, changes in hedging levels, and the impacts of hypothetical credit downgrades. The Registrants have continued to closely monitor events in the financial markets and the financial institutions associated with the credit facilities, including monitoring credit ratings and outlooks, credit default swap levels, capital raising, and merger activity. See PART I. ITEM 1A. RISK FACTORS of the 2021 Form 10-K for additional information regarding the effects of uncertainty in the capital and credit markets.
The Registrants believe their cash flows from operating activities, access to credit markets, and their credit facilities provide sufficient liquidity to support the estimated future cash requirements.
Exelon anticipates issuing up to $1.0 billion of registered shares of common stock through 2025. Exelon plans to establish a $1.0 billion at-the-market (ATM) program, under which Exelon can issue registered shares of common stock through designated broker-dealers at prevailing market prices. Exelon anticipates issuing $500 million in 2022 through the ATM, a one-time common equity offering, or a combination of these methods.
Pursuant to the Separation Agreement between Exelon and Constellation, Exelon made a cash payment of $1.75 billion to Generation on January 31, 2022. See Note 2 — Discontinued Operations of the Combined Notes to Consolidated Financial Statements for additional information on the separation.
The following table presents the incremental collateral that each Utility Registrant would have been required to provide in the event each Utility Registrant lost its investment grade credit rating at June 30, 2022 and available credit facility capacity prior to any incremental collateral at June 30, 2022:
| | | | | | | | | | | | | | | | | |
| PJM Credit Policy Collateral | | Other Incremental Collateral Required(a) | | Available Credit Facility Capacity Prior to Any Incremental Collateral |
| ComEd | $ | 12 | | | $ | — | | | $ | 995 | |
| PECO | 2 | | | 37 | | | 390 | |
| BGE | 3 | | | 75 | | | 600 | |
| | | | | |
| Pepco | 3 | | | — | | | 257 | |
| DPL | 2 | | | 15 | | | 300 | |
| ACE | 1 | | | — | | | 300 | |
__________
(a)Represents incremental collateral related to natural gas procurement contracts.
Capital Expenditure Spending
As of SeptemberJune 30, 2021,2022, the most recent estimates of capital expenditures for plant additions and improvements for 20212022 are as follows:
| | (In millions) | (In millions) | Transmission | | Distribution | | Gas | | Total | (In millions) | Transmission | | Distribution | | Gas | | Total |
| Exelon | Exelon | N/A | | N/A | | N/A | | $ | 8,175 | | Exelon | N/A | | N/A | | N/A | | $ | 6,900 | |
| Generation | N/A | | N/A | | N/A | | 1,450 | | |
| ComEd | ComEd | 475 | | | 1,925 | | | N/A | | 2,400 | | ComEd | 475 | | | 2,000 | | | N/A | | 2,475 | |
| PECO | PECO | 150 | | | 775 | | | 350 | | | 1,275 | | PECO | 200 | | | 825 | | | 325 | | | 1,350 | |
| BGE | BGE | 325 | | | 475 | | | 400 | | | 1,200 | | BGE | 250 | | | 500 | | | 475 | | | 1,225 | |
| PHI | PHI | 550 | | | 1,125 | | | 75 | | | 1,750 | | PHI | 625 | | | 1,150 | | | 75 | | | 1,850 | |
| Pepco | Pepco | 250 | | | 650 | | | N/A | | 900 | | Pepco | 275 | | | 625 | | | N/A | | 900 | |
| DPL | DPL | 100 | | | 250 | | | 75 | | | 425 | | DPL | 150 | | | 250 | | | 75 | | | 475 | |
| ACE | ACE | 200 | | | 225 | | | N/A | | 425 | | ACE | 200 | | | 275 | | | N/A | | 475 | |
Projected capital expenditures and other investments are subject to periodic review and revision to reflect changes in economic conditions and other factors.
Cash Flows from Financing Activities (All Registrants)Pension and Other Postretirement Benefits
The following table provides a summaryManagement considers various factors when making pension funding decisions, including actuarially determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act of 2006 (the Act), management of the change in cash flows from financing activities forpension obligation, and regulatory implications. The Act requires the nine months ended September 30, 2021 and 2020 by Registrant:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Increase (decrease) in cash flows from financing activities | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Changes in short-term borrowings, net | $ | 825 | | | $ | 320 | | | $ | (334) | | | $ | — | | | $ | 76 | | | $ | 127 | | | $ | 87 | | | $ | (68) | | | $ | 108 | |
| Long-term debt, net | 190 | | | 1,271 | | | 300 | | | 100 | | | (100) | | | 13 | | | (24) | | | 26 | | | 11 | |
| Changes in intercompany money pool | — | | | (285) | | | — | | | (40) | | | — | | | (14) | | | — | | | — | | | (117) | |
| | | | | | | | | | | | | | | | | |
| Dividends paid on common stock | (2) | | | — | | | (6) | | | 1 | | | (33) | | | — | | | (47) | | | (7) | | | (169) | |
| Acquisition of noncontrolling interest | (885) | | | (885) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Distributions to member | — | | | 33 | | | — | | | — | | | — | | | (154) | | | — | | | — | | | — | |
| Contributions from parent/member | — | | | — | | | 105 | | | 166 | | | (27) | | | 174 | | | (18) | | | 8 | | | 186 | |
| | | | | | | | | | | | | | | | | |
| Other financing activities | 12 | | | 3 | | | (2) | | | (4) | | | 2 | | | (2) | | | 2 | | | (3) | | | (4) | |
| Increase (decrease) in cash flows from financing activities | $ | 140 | | | $ | 457 | | | $ | 63 | | | $ | 223 | | | $ | (82) | | | $ | 144 | | | $ | — | | | $ | (44) | | | $ | 15 | |
Significant financing cash flow impacts for the Registrants for the nine months ended September 30, 2021 and 2020 wereattainment of certain funding levels to avoid benefit restrictions (such as follows:
•Changes in short-term borrowings, net, is driven by repayments on and issuances of notes due in less than 365 days. Refer to Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on short-term borrowings.
•Long-term debt, net, varies due to debt issuances and redemptions each year. Refer to Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on debt issuances. Refer to the debt redemptions table below for additional information.
•Changes in intercompany money pool are driven by short-term borrowing needs. Refer below for more information regarding the intercompany money pool.
•Exelon’s abilityan inability to pay dividendslump sums or to accrue benefits prospectively), and at-risk status (which triggers higher minimum contribution requirements and participant notification). The projected contributions reflect a funding strategy to make levelized annual contributions with the objective of achieving 100% funded status on an ABO basis over time. This level funding strategy helps minimize volatility of future period required pension contributions. Post-separation, Exelon's estimated annual qualified pension contributions will be approximately $313 million in 2022. In connection with the separation, additional qualified pension contributions of $207 million and $33 million were completed on February 1, 2022 and March 2, 2022, respectively. Unlike the qualified pension plans, Exelon’s non-qualified pension plans are not funded, given that they are not subject to statutory minimum contribution requirements.
While OPEB plans are also not subject to statutory minimum contribution requirements, Exelon does fund certain of its common stock depends onplans. For Exelon's funded OPEB plans, contributions generally equal accounting costs, however, Exelon’s management has historically considered several factors in determining the receiptlevel of dividendscontributions to its OPEB plans, including liabilities management, levels of benefit claims paid, by its operating subsidiaries. The payments of dividends to Exelon by its subsidiaries in turn depend on their results of operations and cash flows and other items affecting retained earnings. See Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements of the Exelon 2020 Form 10-K for additional information on dividend restrictions. See below for quarterly dividends declared.
•See Note 2 – Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information related to the acquisition of CENG noncontrolling interest.
•For the nine months ended September 30, 2021, other financing activities primarily consists of debt issuance costs. See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of the Registrants’ debt issuances.
Debt
See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ debt issuances.
During the nine months ended September 30, 2021, the following long-term debt was retired and/or redeemed:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Company(a) | | Type | | Interest Rate | | | Maturity | | Amount | | |
| Exelon | | Senior Notes | | 2.45 | % | | | April 15, 2021 | | $ | 300 | | | |
| Exelon | | Long-Term Software License Agreement | | 3.95 | % | | | May 1, 2024 | | 24 | | | |
| Exelon | | Long-Term Software License Agreements | | 3.62 | % | | | December 1, 2025 | | 1 | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| Generation | | Continental Wind Nonrecourse Debt(b) | | 6.00 | % | | | February 28, 2033 | | 35 | | | |
| Generation | | EGR IV Nonrecourse Debt(b) | | 3 month LIBOR + 2.50 % | (c) | | December 15, 2027 | | 17 | | | |
| Generation | | SolGen Nonrecourse Debt(b) | | 3.93 | % | | | September 30, 2036 | | 7 | | | |
| Generation | | Antelope Valley DOE Nonrecourse Debt(b) | | 2.29% - 3.56% | | | January 5, 2037 | | 13 | | | |
| | | | | | | | | | | |
| Generation | | West Medway II Nonrecourse Debt(b) | | LIBOR + 3% | (d) | | March 31, 2026 | | 8 | | | |
| Generation | | RPG Nonrecourse Debt(a) | | 4.11 | % | | | March 31, 2035 | | 9 | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| ComEd | | First Mortgage Bonds | | 3.40 | % | | | September 1, 2021 | | 350 | | | |
| PECO | | First Mortgage Bonds | | 1.70 | % | | | September 15, 2021 | | 300 | | | |
| BGE | | Senior Notes | | 3.50 | % | | | November 15, 2021 | | 300 | | | |
| | | | | | | | | | | |
| ACE | | First Mortgage Bonds | | 4.35 | % | | | April 1, 2021 | | 200 | | | |
| ACE | | Tax-Exempt First Mortgage Bonds | | 6.80 | % | | | March 1, 2021 | | 39 | | | |
| ACE | | Transition Bonds | | 5.55 | % | | | October 20, 2021 | | 15 | | | |
_________
(a)On October 5, 2021, Generation redeemed $11 million of 2.29% - 3.56% Antelope Valley DOE nonrecourse debt. On October 20, 2021, ACE redeemed $6 million of 5.55% transition bonds.
(b)See Note 17 — Debt and Credit Agreements of the Exelon 2020 Form 10-K for additional information on nonrecourse debt.
(c)The interest rate was amended to 3 month LIBOR + 2.50 % on June 16, 2021.
(d)The nonrecourse debt has an average blended interest rate.
Dividends
Quarterly dividends declared by the Exelon Board of Directors during the nine months ended September 30, 2021 and for the fourth quarter of 2021 were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Period | | Declaration Date | | Shareholder of Record Date | | Dividend Payable Date | | Cash per Share(a)
|
First Quarter 2021 | | February 21, 2021 | | March 8, 2021 | | March 15, 2021 | | $ | 0.3825 | |
Second Quarter 2021 | | April 27, 2021 | | May 14, 2021 | | June 10, 2021 | | $ | 0.3825 | |
Third Quarter 2021 | | July 27, 2021 | | August 13, 2021 | | September 10, 2021 | | $ | 0.3825 | |
Fourth Quarter 2021 | | October 29, 2021 | | November 15, 2021 | | December 10, 2021 | | $ | 0.3825 | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
_________
(a)Exelon's Board of Directors approved an updated dividend policy for 2021. The 2021 quarterly dividend will remain the same as the 2020 dividend of $0.3825 per share.
Credit Matters (All Registrants)
The Registrants fund liquidity needs for capital investment, working capital, energy hedging, and other financial commitments through cash flows from continuing operations, public debt offerings, commercial paper markets, and large, diversified credit facilities. The credit facilities include $10.3 billion in aggregate total commitments of which $7.7 billion was available to support additional commercial paper as of September 30, 2021, and of which no financial institution has more than 7% of the aggregate commitments for the Registrants. The Registrants had access to the commercial paper markets and had availability under their revolving credit facilities during the nine months ended September 30, 2021 to fund their short-term liquidity needs, when necessary. Generation used its available credit facilities to manage short-term liquidity needs as a result of the impacts of the February 2021 extreme cold weather event and continues to believe it has sufficient cash on hand and available capacity on its revolverregulatory implications (amounts deemed prudent to meet its liquidity requirements. The Registrants routinely review the sufficiency of their liquidity position, including appropriate sizing of credit facility commitments, by performing various stress test scenarios, such as commodity price movements, increases in margin-related transactions, changes in hedging levels,regulatory expectations and the impacts of hypothetical credit downgrades. The Registrants havebest assure continued to closely monitor events in the financial markets and the financial institutions associated with the credit facilities, including monitoring credit ratings and outlooks, credit default swap levels, capital raising, and merger activity. See PART I. ITEM 1A. RISK FACTORS of the Exelon 2020 Form 10-K for additional information regarding the effects of uncertainty in the capital and credit markets.
The Registrants believe their cash flow from operating activities, access to credit markets, and their credit facilities provide sufficient liquidity. If Generation lost its investment grade credit rating as of September 30, 2021, it would have been required to provide incremental collateral of approximately $3.0 billion to meet collateral obligations for derivatives, non-derivatives, normal purchases and normal sales contracts, and applicable payables and receivables, net of the contractual right of offset under master netting agreements, which is well within the $4.3 billion of available credit capacity of its revolver.
The following table presents the incremental collateral that each Utility Registrant would have been required to provide in the event each Utility Registrant lost its investment grade credit rating at September 30, 2021 and available credit facility capacity prior to any incremental collateral at September 30, 2021:
| | | | | | | | | | | | | | | | | |
| PJM Credit Policy Collateral | | Other Incremental Collateral Required(a) | | Available Credit Facility Capacity Prior to Any Incremental Collateral |
| | | | | |
| ComEd | $ | 27 | | | $ | — | | | $ | 998 | |
| PECO | 1 | | | 23 | | | 600 | |
| BGE | 4 | | | 46 | | | 600 | |
| | | | | |
| Pepco | 3 | | | — | | | 260 | |
| DPL | 4 | | | 11 | | | 278 | |
| ACE | 1 | | | — | | | 75 | |
_________
(a)Represents incremental collateral related to natural gas procurement contracts.
Project Financing (Exelon and Generation)
Project financing is used to help mitigate risk of specific generating assets. Project financing is based upon a nonrecourse financial structure, in which project debt is paid back from the cash generated by the specific asset or portfolio of assets. Borrowings under these agreements are secured by the assets and equity of each
respective project. The lenders do not have recourse against Exelon or Generation in the event of a default. If a specific project financing entity does not maintain compliance with its specific debt financing covenants, there could be a requirement to accelerate repayment of the associated debt or other project-related borrowings earlier than the stated maturity dates. In these instances, if such repayment was not satisfied, or restructured, the lenders or security holders would generally have rights to foreclose against the project-specific assets and related collateral. The potential requirement to satisfy its associated debt or other borrowings earlier than otherwise anticipated could lead to impairments due to a higher likelihood of disposing of the respective project-specific assets significantly before the end of their useful lives. Additionally, project financing has credit facilities. Refer to Note 17 — Debt and Credit Agreements of the Exelon 2020 Form 10-K and Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on credit facilities and nonrecourse debt.rate recovery).
Credit Facilities (All Registrants)
Exelon Corporate, ComEd, and BGE meet their short-term liquidity requirements primarily through the issuance of commercial paper. Generation and PECO meet theirmeets its short-term liquidity requirements primarily through the issuance of
commercial paper and borrowings from the Exelon intercompany money pool. Pepco, DPL, and ACE meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the PHI intercompany money pool. PHI Corporate meets its short-term liquidity requirements primarily through the issuance of short-term notes and the Exelon intercompany money pool. The Registrants may use their respective credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit.
See Note 1310 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ short-termcredit facilities and short term borrowing activity. See Note 17 — Debt and Credit Agreements of the Exelon 2020 Form 10-K for additional information on the Registrants’ credit facilities.
Security Ratings (All Registrants)
The Registrants’ access to the capital markets, including the commercial paper market, and their respective financing costs in those markets, may depend on the securities ratings of the entity that is accessing the capital markets.
The Registrants’ borrowings are not subject to default or prepayment as a result of a downgrading of securities, although such a downgrading of a Registrant’s securities could increase fees and interest charges under that Registrant’s credit agreements.
As part of the normal course of business, the Registrants enter into contracts that contain express provisions or otherwise permit the Registrants and their counterparties to demand adequate assurance of future performance when there are reasonable grounds for doing so. In accordance with the contracts and applicable contracts law, if the Registrants are downgraded by a credit rating agency, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance, which could include the posting of collateral. See Note 129 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on collateral provisions.
The credit ratings for Exelon CorporateComEd, PECO, BGE, and the Utility RegistrantsDPL did not change for the ninesix months ended SeptemberJune 30, 2021.
2022. On February 24, 2021, S&PJanuary 14, 2022, Fitch lowered Generation’sExelon Corporate's long-term and senior unsecured debtratings from BBB+ to BBB and affirmed the short-term rating of F2. In addition, Fitch upgraded Pepco, ACE, and PHI's long-term rating from BBB to ‘BBB-‘BBB+ and upgraded Pepco and ACE's senior secured rating from ‘BBB’ in responseA- to the financial impacts of the February 2021 weather event and Texas-based generating assets outages. See Significant 2021 Transactions and Developments for additional information. The S&P ratings changes did not materially impact Generation's financial statements. Furthermore, there were no material increases in required collateral or financial assurances or material impacts to our anticipated access to liquidity or cost of financing.A.
Intercompany Money Pool (All Registrants)
To provide an additional short-term borrowing option that will generally be more favorable to the borrowing participants than the cost of external financing, both Exelon and PHI operate an intercompany money pool. Maximum amounts contributed to and borrowed from the money pool by participant and the net contribution or borrowing as of June 30, 2022, are presented in the following table. ACE had no activity within the PHI intercompany money pool during the six months ended June 30, 2022.
borrowing as of September 30, 2021, are presented in the following table. ACE had no activity within the PHI Intercompany Money Pool for the nine months ended September 30, 2021. | | | | | | | | | | | | | | | | | | | | |
| | During the Six Months Ended June 30, 2022 | | As of June 30, 2022 |
| Exelon Intercompany Money Pool | | Maximum
Contributed | | Maximum
Borrowed | | Contributed
(Borrowed) |
| Exelon Corporate | | $ | 396 | | | $ | — | | | $ | 287 | |
| PECO | | 60 | | | (105) | | | — | |
| BSC | | — | | | (377) | | | (308) | |
| PHI Corporate | | — | | | (54) | | | (24) | |
| PCI | | 50 | | | — | | | 45 | |
| | | | | | | | | | | | | | | | | |
| During the Nine Months Ended September 30, 2021 | | As of September 30, 2021 |
| Exelon Intercompany Money Pool | Maximum
Contributed | | Maximum
Borrowed | | Contributed
(Borrowed) |
| Exelon Corporate | $ | 735 | | | $ | — | | | $ | 239 | |
| Generation | — | | | (426) | | | — | |
| PECO | 303 | | | (100) | | | — | |
| BSC | — | | | (435) | | | (273) | |
| PHI Corporate | — | | | (40) | | | (16) | |
| PCI | 60 | | | — | | | 50 | |
| | | | | | | | | | | | | | | | | |
| | | | | |
| During the Nine Months Ended September 30, 2021 | | As of September 30, 2021 |
PHI Intercompany Money Pool | Maximum
Contributed | | Maximum
Borrowed | | Contributed
(Borrowed) |
| | | | | |
Pepco | $ | — | | | $ | (30) | | | $ | — | |
DPL | 30 | | | — | | | — | |
| | | | | |
| | | | | |
| | | | | | | | | | | | | | | | | | | | |
| | During the Six Months Ended June 30, 2022 | | As of June 30, 2022 |
| PHI Intercompany Money Pool | | Maximum
Contributed | | Maximum
Borrowed | | Contributed
(Borrowed) |
| Pepco | | $ | — | | | $ | (85) | | | $ | (73) | |
| DPL | | 85 | | | — | | | 73 | |
Shelf Registration Statements (All Registrants)
Exelon Generation, and the Utility Registrants have a currently effective combined shelf registration statement unlimited in amount, filed with the SEC, that will expire in August 2022. The ability of each Registrant to sell securities off the shelf registration statement or to access the private placement markets will depend on a number of factors at the time of the proposed sale, including other required regulatory approvals, as applicable, the current financial condition of the Registrant, its securities ratings and market conditions.
Regulatory Authorizations (All Registrants)
The Utility Registrants are required to obtain short-term and long-term financing authority from Federal and State Commissions as follows:
| | | As of September 30, 2021 | | As of June 30, 2022 |
| | Short-term Financing Authority(a)(b) | | Remaining Long-term Financing Authority(a) | | Short-term Financing Authority | | Remaining Long-term Financing Authority |
| Commission | | Expiration Date | | Amount | Commission | | Expiration Date | | Amount | Commission | | Expiration Date | | Amount | Commission | | Expiration Date | | Amount |
ComEd(c)(a) | ComEd(c)(a) | | FERC | | December 31, 2021 | | $ | 2,500 | | | ICC | | February 1, 2023 | | $ | 93 | | ComEd(c)(a) | | FERC | | December 31, 2023 | | $ | 2,500 | | | ICC | | January 1, 2025 | | $ | 1,343 | |
PECO(d)(b) | PECO(d)(b) | | FERC | | December 31, 2021 | | 1,500 | | | PAPUC | | December 31, 2021 | | 475 | | PECO(d)(b) | | FERC | | December 31, 2023 | | 1,500 | | | PAPUC | | December 31, 2024 | | 1,550 | |
| BGE | BGE | | FERC | | December 31, 2021 | | 700 | | | MDPSC | | N/A | | 500 | | BGE | | FERC | | December 31, 2023 | | 700 | | | MDPSC | | N/A | | — | |
Pepco | Pepco | | FERC | | December 31, 2021 | | 500 | | | MDPSC / DCPSC | | December 31, 2022 | | 625 | | Pepco | | FERC | | December 31, 2023 | | 500 | | | MDPSC / DCPSC | | 2022 & 2025 | | 1,625 | |
| DPL | DPL | | FERC | | December 31, 2021 | | 500 | | | MDPSC / DPSC | | December 31, 2022 | | 172 | | DPL | | FERC | | December 31, 2023 | | 500 | | | MDPSC / DEPSC | | December 31, 2022 | | 47 | |
ACE | ACE | | NJBPU | | December 31, 2021 | | 350 | | | NJBPU | | December 31, 2022 | | 250 | | ACE | | NJBPU | | December 31, 2023 | | 350 | | | NJBPU | | December 31, 2022 | | — | |
___________________
(a)Generation currently has blanket financing authority it received from FERC in connection with its market-based rate authority.
(b)On October 15,November 18, 2021, ComEd PECO, BGE, Pepco, and DPL filed applications with FERC and on July 21, 2021, ACE filed an application with NJBPU for renewal of their short-term financing authority through December 31, 2023. ComEd, PECO, BGE, Pepco, DPL, and ACE expectreceived approval of their applications by December 31, 2021.
(c)ComEd had $93 million available in new money long-term debt financing authority from the ICC as of September 30, 2021 and has an expiration date of February 1, 2023. On June 29, 2021, ComEd filed an application for $2 billion in new money long-term debt financing authority with an effective date of January 1, 2022.
(b)On December 2, 2021, PECO received approval from the ICCPAPUC for $2.5 billion in new long-term debt financing authority with an effective date of January 1, 2022.
(c)As of June 30, 2022, Pepco had $225 million in long-term financing authority from the MDPSC and expects approval byDCPSC, which has an expiration date of December 31, 2021.2022. On June 9, 2022 and June 30, 2022, Pepco received approval from the MDPSC and DCPSC, respectively, for $1.4 billion in new long-term financing authority. The long-term financing authority became effective on the date of respective approvals and has an expiration date of December 31, 2025.
(d)PECO is currentlyOn July 13, 2022, ACE received approval from the NJBPU for $700 million in the process of renewing itsnew long-term debt financing authority with PAPUC and expects approval by December 31, 2021.
Contractual Obligations and Off-Balance Sheet Arrangements
Contractual obligations represent cash obligations that are considered to be firm commitments and commercial commitments triggered by future events. See Note 15 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.
Generation, ComEd, PECO, BGE, Pepco, DPL, and ACE have obligations related to contracts for the purchase of power and fuel supplies, and ComEd and PECO have obligations related to their financing trusts. The power and fuel purchase contracts and the financing trusts have been considered for consolidation in the Registrants’ respective financial statements pursuant to the authoritative guidance for VIEs. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements in the Exelon 2020 Form 10-K for additional information.
For an in-depth discussion of the Registrants' contractual obligations and off-balance sheet arrangements, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Contractual Obligations and Off-Balance Sheet Arrangements” in the Exelon 2020 Form 10-K and Note 6 — Accounts Receivable of the Combined Notes to Consolidated Financial Statements.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
The Registrants hold commodity and financial instruments that are exposed to the following market risksrisks:
•Commodity price risk, which is discussed further below.
•Counterparty credit risk associated with adversenon-performance by counterparties on executed derivative instruments and participation in all, or some of the established, wholesale spot energy markets that are administered by PJM. The credit policies of PJM may, under certain circumstances, require that losses arising from the default of one member on spot energy market transactions be shared by the remaining participants. See Note 9 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for a detailed discussion of counterparty credit risk related to derivative instruments.
•Equity price and interest rate risk associated with Exelon’s pension and OPEB plan trusts. See Note 13 — Retirement Benefits of the 2021 Recast Form 10-K for additional information.
•Interest rate risk associated with changes in commodity prices, counterparty credit, interest rates for the Registrants’ outstanding long-term debt. This risk is significantly reduced as substantially all of the Registrants’ outstanding debt has fixed interest rates. There is inherent interest rate risk related to refinancing maturing debt by issuing new long-term debt. The Registrants use a combination of fixed-rate and equity prices. Exelon’s RMC approvesvariable-rate debt to manage interest rate exposure. See Note 10 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.
The Registrants operate primarily under cost-based rate regulation limiting exposure to the effects of market risk. Hedging programs are utilized to reduce exposure to energy and natural gas price volatility and have no direct earnings impacts as the costs are fully recovered through regulatory-approved recovery mechanisms.
Exelon manages these risks through risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of risk exposures. The RMC is chaired byRisk management issues are reported to Exelon’s Executive Committee, the chief executive officerRisk Management Committees of each Utility Registrant, and includes the chief risk officer, chief strategy officer, chief executive officer of Exelon Utilities, chief commercial officer, chief financial officer, and chief executive officer of Constellation. The RMC reports to the FinanceAudit and Risk Committee of the ExelonExelon’s Board of Directors on the scope of the risk management activities. The following discussion serves as an update to ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK of Exelon’s 2020 Annual Report on Form 10-K incorporated herein by reference.Directors.
Commodity Price Risk (All Registrants)
Commodity price risk is associated with price movements resulting from changes in supply and demand, fuel costs, market liquidity, weather conditions, governmental regulatory and environmental policies, and other factors. To the extent the total amount of energy Exelon generates and purchases differs from the amount of energy it has contracted to sell, Exelon is exposed to market fluctuations in commodity prices. Exelon seeks to mitigate its commodity price risk through the sale and purchase of electricity fossil fuel, and other commodities.natural gas.
GenerationComEd entered into 20-year floating-to-fixed renewable energy swap contracts beginning in June 2012, which are considered an economic hedge and have changes in fair value recorded to an offsetting regulatory asset or liability. ComEd has block energy contracts to procure electric supply that are executed through a competitive procurement process, which are considered derivatives and qualify for NPNS, and as a result are accounted for on an accrual basis of accounting. PECO, BGE, Pepco, DPL, and ACE have contracts to procure electric supply that are executed through a competitive procurement process. PECO, BGE, Pepco, DPL, and ACE have certain full requirements contracts, which are considered derivatives and qualify for NPNS, and as a result are accounted for on an accrual basis of accounting. Other full requirements contracts are not derivatives.
Electricity available from Generation’s ownedPECO, BGE, and DPL also have executed derivative natural gas contracts, which either qualify for NPNS or contracted generation supply in excess of Generation’s obligationshave no mark-to-market balances because the derivatives are index priced, to customers, including portions of the Utility Registrants' retail load, is sold into the wholesale markets. To reduce commodityhedge their long-term price risk caused by market fluctuations, Generation enters into non-derivative contracts as well as derivative contracts, including swaps, futures, forwards, and options, with approved counterparties to hedge anticipated exposures. Generation uses derivative instruments as economic hedges to mitigate exposure to fluctuations in commodity prices. Generation expects the settlement of the majority of its economic hedges will occur during 2021 through 2023.
As of September 30, 2021, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York, and ERCOT reportable segments is 96%-99% for the remainder of 2021. Market price risk exposure is the risk of a change in the value of unhedged positions.natural gas market. The forecasted market price risk exposurehedging programs for Generation’s entire economic hedge portfolio associated with a $5 reduction in the annual average around-the-clock energy price basednatural gas procurement have no direct impact on September 30, 2021 market conditions and hedged position would be immaterial for 2021. Seetheir financial statements.
For additional information on these contracts, see Note 129 — Derivative Financial Instruments and Note 11 — Fair Value of Financial Assets and Liabilities of the Combined Notes to Consolidated Financial Statements for additional information.
Fuel Procurement
Approximately 60% of Generation’s uranium concentrate requirements from 2021 through 2025 are supplied by three suppliers. In the event of non-performance by these or other suppliers, Generation believes that replacement uranium concentrates can be obtained, although at prices that may be unfavorable when compared to the prices under the current supply agreements. Non-performance by these counterparties could have a material adverse impact in Exelon’s and Generation’s financial statements.
Utility Registrants
There have been no significant changes or additions to the Utility Registrants exposures to commodity price risk that were described in ITEM 1A. RISK FACTORS of Exelon’s 2020 Annual Report on Form 10-K. See Note 12 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding commodity price risk exposure.
Trading and Non-Trading Marketing ActivitiesStatements.
The following table detailingpresents the maturity and source of fair value for Exelon’s Generation’s, and ComEd’s trading and non-trading marketing activities is included to address the recommended disclosures by themark-to-market commodity contract net liabilities. These net liabilities are associated with ComEd’s floating-to-fixed energy industry’s Committee of Chief Risk Officers (CCRO).swap
The following table provides detail on changes in Exelon’s, Generation’s, and ComEd’s commodity mark-to-market net asset or liability balance sheet position from December 31, 2020 to September 30, 2021. It indicates the drivers behind changes in the balance sheet amounts. This table incorporates the mark-to-market activities that are immediately recorded in earnings. This table excludes all NPNS contracts and does not segregate proprietary trading activity. See Note 12 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on the balance sheet classification of the mark-to-market energy contract net assets (liabilities) recorded as of September 30, 2021 and December 31, 2020.
| | | | | | | | | | | | | | | | | | | | | |
| Exelon | | Generation | | ComEd | | | | |
Total mark-to-market energy contract net assets (liabilities) at December 31, 2020(a) | $ | 428 | | | $ | 729 | | | $ | (301) | | | | | |
| Total change in fair value during 2021 of contracts recorded in results of operations | 1,434 | | | 1,434 | | | — | | | | | |
| Reclassification to realized at settlement of contracts recorded in results of operations | (186) | | | (186) | | | — | | | | | |
| | | | | | | | | |
Changes in fair value — recorded through regulatory assets(b) | 87 | | | — | | | 87 | | | | | |
| Changes in allocated collateral | (2,061) | | | (2,061) | | | — | | | | | |
| Net option premium paid | 186 | | | 186 | | | — | | | | | |
| Option premium amortization | (45) | | | (45) | | | — | | | | | |
Upfront payments and amortizations(c) | (107) | | | (107) | | | — | | | | | |
Total mark-to-market energy contract net liabilities at September 30, 2021(a) | $ | (264) | | | $ | (50) | | | $ | (214) | | | | | |
_________
(a)Amounts are shown net of collateral paid to and received from counterparties.
(b)For ComEd, the changes in fair value are recorded as a change in regulatory assets. As of September 30, 2021, ComEd recorded a regulatory asset of $214 million related to its mark-to-market derivative liabilities with unaffiliated suppliers. For the nine months ended September 30, 2021, ComEd recorded $72 million of increases in fair value and an increase for realized losses due to settlements of $15 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers.
(c)Includes derivative contracts acquired or sold by Generation through upfront payments or receipts of cash, excluding option premiums, and the associated amortizations.
Fair Values
The following tables present maturity and source of fair value for Exelon, Generation, and ComEd mark-to-market commodity contract net assets (liabilities). The tables providetable provides two fundamental pieces of information. First, the tables providetable provides the source of fair value used in determining the carrying amount of the Registrants’Exelon's and ComEd's total mark-to-market net assets (liabilities), net of allocated collateral.liabilities. Second, the tables showtable shows the maturity, by year, of the Registrants’Exelon's and ComEd's commodity contract net assets (liabilities), net of allocated collateral,liabilities giving an indication of when these mark-to-market amounts will settle and either generate or require cash. See Note 1411 — Fair Value of Financial Assets and Liabilities of the Combined Notes to Consolidated Financial Statements for additional information regarding fair value measurements and the fair value hierarchy.
Exelon
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Maturities Within | | Total Fair
Value |
| 2021 | | 2022 | | 2023 | | 2024 | | 2025 | | 2026 and Beyond | |
Normal Operations, Commodity derivative contracts(a)(b): | | | | | | | | | | | | | |
| Actively quoted prices (Level 1) | $ | 302 | | | $ | 578 | | | $ | 63 | | | $ | 53 | | | $ | 38 | | | $ | 23 | | | $ | 1,057 | |
| Prices provided by external sources (Level 2) | 17 | | | 737 | | | 40 | | | (40) | | | — | | | — | | | 754 | |
Prices based on model or other valuation methods (Level 3)(c) | (566) | | | (1,304) | | | 17 | | | (15) | | | (18) | | | (189) | | | (2,075) | |
| Total | $ | (247) | | | $ | 11 | | | $ | 120 | | | $ | (2) | | | $ | 20 | | | $ | (166) | | | $ | (264) | |
_________
(a)Mark-to-market gains and losses on other economic hedge and trading derivative contracts that are recorded in results of operations.
(b)Amounts are shown net of collateral paid/(received) from counterparties (and offset against mark-to-market assets and liabilities) of $(1,645) million at September 30, 2021.
(c)Includes ComEd’s net assets (liabilities) associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers.
Generation
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Maturities Within | | Total Fair
Value |
| 2021 | | 2022 | | 2023 | | 2024 | | 2025 | | 2026 and Beyond | |
Normal Operations, Commodity derivative contracts(a)(b): | | | | | | | | | | | | | |
| Actively quoted prices (Level 1) | $ | 302 | | | $ | 578 | | | $ | 63 | | | $ | 53 | | | $ | 38 | | | $ | 23 | | | $ | 1,057 | |
| Prices provided by external sources (Level 2) | 17 | | | 737 | | | 40 | | | (40) | | | — | | | — | | | 754 | |
| Prices based on model or other valuation methods (Level 3) | (565) | | | (1,293) | | | 39 | | | 8 | | | 5 | | | (55) | | | (1,861) | |
| Total | $ | (246) | | | $ | 22 | | | $ | 142 | | | $ | 21 | | | $ | 43 | | | $ | (32) | | | $ | (50) | |
_________
(a)Mark-to-market gains and losses on other economic hedge and trading derivative contracts that are recorded in the results of operations.
(b)Amounts are shown net of collateral paid/(received) from counterparties (and offset against mark-to-market assets and liabilities) of $(1,645) million at September 30, 2021.
ComEd
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Maturities Within | | Total Fair
Value |
| 2021 | | 2022 | | 2023 | | 2024 | | 2025 | | 2026 and Beyond | |
Commodity derivative contracts(a): | | | | | | | | | | | | | |
Prices based on model or other valuation methods (Level 3)(a) | $ | (1) | | | $ | (11) | | | $ | (22) | | | $ | (23) | | | $ | (23) | | | $ | (134) | | | $ | (214) | |
_________
(a)Represents ComEd’s net liabilities associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers.
Credit Risk (All Registrants)
The Registrants would be exposed to credit-related losses in the event of non-performance by counterparties that execute derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts at the reporting date. See Note 12 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for detailed discussion of credit risk.
Generation
The following tables provide information on Generation’s credit exposure for all derivative instruments, NPNS, and payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of September 30, 2021. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties and an indication of the duration of a company’s credit risk by credit rating of the counterparties. The amounts in the tables below exclude credit risk exposure from individual retail customers, uranium procurement contracts, and exposure through RTOs, ISOs, and commodity exchanges, which are discussed below.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Rating as of September 30, 2021 | | Total Exposure Before Credit Collateral | | Credit Collateral(a) | | Net
Exposure | | Number of
Counterparties
Greater than 10%
of Net Exposure | | Net Exposure of
Counterparties
Greater than
10% of Net
Exposure |
| Investment grade | | $ | 701 | | | $ | 254 | | | $ | 447 | | | — | | | $ | — | |
| Non-investment grade | | 23 | | | 2 | | | 21 | | | — | | | — | |
| No external ratings | | | | | | | | | | |
| Internally rated — investment grade | | 110 | | | 1 | | | 109 | | | — | | | — | |
| Internally rated — non-investment grade | | 309 | | | 48 | | | 261 | | | — | | | — | |
| Total | | $ | 1,143 | | | $ | 305 | | | $ | 838 | | | — | | | $ | — | |
_________
(a)As of September 30, 2021, credit collateral held from counterparties where Generation had credit exposure included $188 million of cash and $117 million of letters of credit.
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Maturity of Credit Risk Exposure |
| Rating as of September 30, 2021 | | Less than
2 Years | | 2-5 Years | | Exposure
Greater than
5 Years | | Total Exposure
Before Credit
Collateral |
| Investment grade | | $ | 579 | | | $ | 69 | | | $ | 53 | | | $ | 701 | |
| Non-investment grade | | 23 | | | — | | | — | | | 23 | |
| No external ratings | | | | | | | | |
| Internally rated — investment grade | | 96 | | | 10 | | | 4 | | | 110 | |
| Internally rated — non-investment grade | | 251 | | | 49 | | | 9 | | | 309 | |
| Total | | $ | 949 | | | $ | 128 | | | $ | 66 | | | $ | 1,143 | |
| | | | | | | | |
Net Credit Exposure by Type of Counterparty | | As of September 30, 2021 |
Financial institutions | | $ | 53 | |
Investor-owned utilities, marketers, power producers | | 652 | |
Energy cooperatives and municipalities | | 62 | |
Other | | 71 | |
Total | | $ | 838 | |
The Utility Registrants
There have been no significant changes or additions to the Utility Registrants exposures to credit risk that are described in ITEM 1A. RISK FACTORS of Exelon’s 2020 Annual Report on Form 10-K. See Note 12 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding credit exposure to suppliers.
Credit-Risk-Related Contingent Features (All Registrants)
Generation
As part of the normal course of business, Generation routinely enters into physical or financial contracts for the sale and purchase of electricity, natural gas, and other commodities. In accordance with the contracts and applicable law, if Generation is downgraded by a credit rating agency, especially if such downgrade is to a level below investment grade, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance. Depending on Generation’s net position with a counterparty, the demand could be for the posting of collateral. In the absence of expressly agreed-to provisions that specify the collateral that must be provided, collateral requested will be a function of the facts and circumstances of the situation at the time of the demand. See Note 12 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding collateral requirements. See Note 15 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information regarding the letters of credit supporting the cash collateral.
Generation transacts output through bilateral contracts. The bilateral contracts are subject to credit risk, which relates to the ability of counterparties to meet their contractual payment obligations. Any failure to collect these payments from counterparties could have a material impact on Exelon’s and Generation’s financial statements. As market prices rise above or fall below contracted price levels, Generation is required to post collateral with purchasers; as market prices fall below contracted price levels, counterparties are required to post collateral with Generation. To post collateral, Generation depends on access to bank credit facilities, which serve as liquidity sources to fund collateral requirements. See Note 17 — Debt and Credit Agreements of Exelon’s 2020 Annual Report on Form 10-K for additional information.
Utility Registrants
As of September 30, 2021, the Utility Registrants were not required to post collateral under their energy and/or natural gas procurement contracts. See Note 12 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
Interest Rate and Foreign Exchange Risk (Exelon and Generation)
Exelon and Generation use a combination of fixed-rate and variable-rate debt to manage interest rate exposure. Exelon and Generation may also utilize interest rate swaps to manage their interest rate exposure. A hypothetical 50 basis point increase in the interest rates associated with unhedged variable-rate debt (excluding Commercial Paper) and fixed-to-floating swaps would result in approximately a $1 million decrease in Exelon pre-tax income for the nine months ended September 30, 2021. To manage foreign exchange rate exposure associated with international energy purchases in currencies other than U.S. dollars, Generation utilizes foreign currency derivatives, which are typically designated as economic hedges. See Note 12 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
Equity Price Risk (Exelon and Generation)
Exelon and Generation maintain trust funds, as required by the NRC, to fund certain costs of decommissioning its nuclear plants. As of September 30, 2021, Generation’s NDT funds are reflected at fair value in its Consolidated Balance Sheets. The mix of securities in the trust funds is designed to provide returns to be used to fund decommissioning and to compensate Generation for inflationary increases in decommissioning costs; however, the equity securities in the trust funds are exposed to price fluctuations in equity markets, and the value of fixed-rate, fixed-income securities are exposed to changes in interest rates. Generation actively monitors the investment performance of the trust funds and periodically reviews asset allocation in accordance with Generation’s NDT fund investment policy. A hypothetical 25 basis points increase in interest rates and 10% decrease in equity prices would result in a $863 million reduction in the fair value of the trust assets. This calculation holds all other variables constant and assumes only the discussed changes in interest rates and equity prices. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Maturities Within | | Total Fair
Value |
| 2022 | | 2023 | | 2024 | | 2025 | | 2026 | | 2027 and Beyond | |
| Prices based on model or other valuation methods (Level 3) | $ | 11 | | | $ | (2) | | | $ | (14) | | | $ | (16) | | | $ | (15) | | | $ | (52) | | | $ | (88) | |
ITEM 4. CONTROLS AND PROCEDURES
During the thirdsecond quarter of 2021,2022, each of the Registrants' management, including its principal executive officer and principal financial officer, evaluated its disclosure controls and procedures related to the recording, processing, summarizing, and reporting of information in its periodic reports that it files with the SEC. These
disclosure controls and procedures have been designed by the Registrants to ensure that (a) material information relating to that Registrant, including its consolidated subsidiaries, is accumulated and made known to Exelon’sthat Registrant's management, including its principal executive officer and principal financial officer, by other employees of that Registrant and its subsidiaries as appropriate to allow timely decisions regarding required disclosure, and (b) this information is recorded, processed, summarized, evaluated, and reported, as applicable, within the time periods specified in the SEC’s rules and forms. Due to the inherent limitations of control systems, not all misstatements may be detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Additionally, controls could be circumvented by the individual acts of some persons or by collusion of two or more people.
Accordingly, as of SeptemberJune 30, 2021,2022, the principal executive officer and principal financial officer of each of the Registrants concluded that such Registrant’s disclosure controls and procedures were effective to accomplish its objectives. The Registrants continually strive to improve their disclosure controls and procedures to enhance the quality of its financial reporting and to maintain dynamic systems that change as conditions warrant. There were no changes in internal control over financial reporting during the thirdsecond quarter of 20212022 that materially affected, or are reasonably likely to materially affect, any of the Registrants' internal control over financial reporting.
PART II — OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
The Registrants are parties to various lawsuits and regulatory proceedings in the ordinary course of their respective businesses. For information regarding material lawsuits and proceedings, see (a) ITEM 3. LEGAL PROCEEDINGS of Exelon’s 2020the 2021 Form 10-K, and (b) Notes 3 — Regulatory Matters and 1517 — Commitments and Contingencies of the 2021 Recast Form 10-K, and (c) Notes 3 — Regulatory Matters and 12 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements in PART I, ITEM 1. FINANCIAL STATEMENTS of this Report. Such descriptions are incorporated herein by these references.
ITEM 1A. RISK FACTORS
Risks Related to All Registrants
At SeptemberJune 30, 2021,2022, the Registrants' risk factors were consistent with the risk factors described in the Registrants' combined 20202021 Form 10-K in ITEM 1A. RISK FACTORS, except for the updates below.
We could be negatively affected byThe Registrants are subject to physical security and cybersecurity risks (All Registrants).
The Registrants face physical security and cybersecurity risks. Threat sources, including sophisticated nation-state actors, continue to seek to exploit potential vulnerabilities in the impacts of weather (Exelon and Generation).
Our operations are affected by weather, which affects demand for electricityelectric and natural gas the priceutility industry, grid infrastructure, and other energy infrastructures, and these attacks and disruptions, both physical and cyber, are becoming increasingly sophisticated and dynamic. Continued implementation of energy commodities, as well as operating conditions. To the extent that weather is warmer in the summer or colder in the winter than assumed, we could require greater resources to meet our contractual commitments. Extreme weather conditions or storms have affected the availability of generation and its transmission, limiting our ability to source or send power to where it is sold, and have also affected the transportation of natural gas to our generating assets and our ability to supply natural gas to our customers. In addition, drought-like conditions limiting water usage could impact our ability to run certain generating assets at full capacity. These conditions, which cannot be accurately predicted, could cause us to seek additional capacity at a time when wholesale markets are tight or to seek to sell excess capacity at a time when markets are weak.
Climate change projections suggest increases to summer temperature and humidity trends, as well as more erratic precipitation and storm patterns over the long-term in the areas where we have generation assets. The frequency in which weather conditions emerge outside the current expected climate norms could contribute to weather-related impacts discussed above.
Beginning on February 15, 2021, our Texas-based generating assets within the ERCOT market, specifically Colorado Bend II, Wolf Hollow II, and Handley, experienced periodic outages as a result of historically severe cold weather conditions. We estimate a reduction in Net income at Exelon and Generation of approximately $670 million to $820 million for the full year 2021 arising from these market and weather conditions. See ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Significant 2021 Transactions and Developments — Impacts of February 21 Extreme Weather Event and Texas-based Generating Assets Outages for additional information.
ITEM 4. MINE SAFETY DISCLOSURESadvanced digital technologies
increases the potentially unfavorable impacts of such attacks. Additionally, the U.S. government has warned that the Ukraine conflict may increase the risks of attacks targeting critical infrastructure in the United States.
A security breach of the Registrants' physical assets or information systems or those of the Registrants competitors, vendors, business partners and interconnected entities in RTOs and ISOs, or regulators could impact the operation of the generation fleet and/or reliability of the transmission and distribution system or result in the theft or inappropriate release of certain types of information, including critical infrastructure information, sensitive customer, vendor, and employee data, trading or other confidential data. The risk of these system-related events and security breaches occurring continues to intensify, and while the Registrants have been, and will likely continue to be, subjected to physical and cyber-attacks, to date none have directly experienced a material breach or disruption to its network or information systems or our operations. However, as such attacks continue to increase in sophistication and frequency, the Registrants may be unable to prevent all such attacks in the future.
If a significant breach were to occur, the Registrants' reputation could be negatively affected, customer confidence in the Registrants or others in the industry could be diminished, or the Registrants could be subject to legal claims, loss of revenues, increased costs, or operations shutdown. Moreover, the amount and scope of insurance maintained against losses resulting from any such events or security breaches may not be sufficient to cover losses or otherwise adequately compensate for any disruptions to business that could result.
The Utility Registrants' deployment of smart meters throughout their service territories could increase the risk of damage from an intentional disruption of the system by third parties.
In addition, new or updated security regulations or unforeseen threat sources could require changes in current measures taken by the Registrants or their business operations and could adversely affect their consolidated financial statements.
ITEM 4. MINE SAFETY DISCLOSURES
All Registrants
Not applicable to the Registrants.
ITEM 5. OTHER INFORMATION
All RegistrantsAmendments to Exelon Governing Documents
None.On August 3, 2022, Exelon adopted Amended and Restated Bylaws (the “Bylaws”), effective as of that date. Amendments contained in the Bylaws include the addition of language to amend Exelon's advance notice provisions to address the adoption by the Securities and Exchange Commission of universal proxy rules, reorganization of certain sections, and other minor edits to address certain administrative and other non-material matters.
ITEM 6. EXHIBITS
Certain of the following exhibits are incorporated herein by reference under Rule 12b-32 of the Securities and Exchange Act of 1934, as amended. Certain other instruments which would otherwise be required to be listed below have not been so listed because such instruments do not authorize securities in an amount which exceeds 10% of the total assets of the applicable Registrant and its subsidiaries on a consolidated basis and the relevant Registrant agrees to furnish a copy of any such instrument to the Commission upon request.
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| One Hundred and Twenty-First Supplemental Indenture dated as of August 2, 2021, from ComEd to BNY Mellon TrustMay 1, 2022, among PECO Energy Company of Illinois,and U.S. Bank , N.A., as trustee and D.G. Donovan, as co-trustee (File No. 001-01839,001-16844, Form 8-K dated August 12, 2021,May 24, 2022, Exhibit 4.1) |
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| 101.INS | Inline 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. |
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| 101.SCH | Inline XBRL Taxonomy Extension Schema Document. |
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| 101.CAL | Inline XBRL Taxonomy Extension Calculation Linkbase Document. |
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| 101.DEF | Inline XBRL Taxonomy Extension Definition Linkbase Document.
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| 101.LAB | Inline XBRL Taxonomy Extension Labels Linkbase Document. |
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| 101.PRE | Inline XBRL Taxonomy Extension Presentation Linkbase Document.
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| 104 | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) |
*Filed herewith
Certifications Pursuant to Rule 13a-14(a) and 15d-14(a) of the Securities and Exchange Act of 1934 as to the Quarterly Report on Form 10-Q for the quarterly period ended SeptemberJune 30, 20212022 filed by the following officers for the following companies:
Certifications Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code (Sarbanes — Oxley Act of 2002) as to the Quarterly Report on Form 10-Q for the quarterly period ended SeptemberJune 30, 20212022 filed by the following officers for the following companies:
SIGNATURES
Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
EXELON CORPORATION
| | | | | | | | |
| /s/ CHRISTOPHER M. CRANE | | /s/ JOSEPH NIGRO |
| Christopher M. Crane | | Joseph Nigro |
President, Chief Executive Officer
(Principal Executive Officer) and Director | | Senior Executive Vice President and Chief Financial Officer
(Principal Financial Officer) |
| | |
/s/ FABIAN E. SOUZAJOSEPH R. TRPIK | | |
Fabian E. SouzaJoseph R. Trpik | | |
Senior Vice President and Corporate Controller
(Principal Accounting Officer) | | |
NovemberAugust 3, 20212022
Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
EXELON GENERATION COMPANY, LLC
| | | | | | | | |
/s/ JOSEPH DOMINGUEZ | | /s/ DANIEL L. EGGERS |
Joseph Dominguez | | Daniel L. Eggers |
Chief Executive Officer
(Principal Executive Officer) | | Chief Financial Officer
(Principal Financial Officer) |
| | |
/s/ MATTHEW N. BAUER | | |
Matthew N. Bauer | | |
Vice President and Controller
(Principal Accounting Officer) | | |
November 3, 2021
Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
COMMONWEALTH EDISON COMPANY
| | | | | | | | |
/s/ CALVIN G. BUTLERGIL C. QUINIONES | | /s/ JEANNE M. JONESELISABETH J. GRAHAM |
Calvin G. ButlerGil C. Quiniones | | Jeanne M. JonesElisabeth J. Graham |
Interim Chief Executive Officer
(Principal Executive Officer) | | Senior Vice President, Chief Financial Officer and Treasurer
(Principal Financial Officer) |
| | |
| /s/ STEVEN J. CICHOCKI | | |
| Steven J. Cichocki | | |
Director, Accounting
(Principal Accounting Officer) | | |
NovemberAugust 3, 20212022
Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
PECO ENERGY COMPANY
| | | | | | | | |
| /s/ MICHAEL A. INNOCENZO | | /s/ ROBERT J. STEFANI |
| Michael A. Innocenzo | | Robert J. Stefani |
President and Chief Executive Officer
(Principal Executive Officer) | | Senior Vice President, Chief Financial Officer and Treasurer
(Principal Financial Officer) |
| | |
| /s/ CAROLINE FULGINITI | | |
| Caroline Fulginiti | | |
Director, Accounting
(Principal Accounting Officer) | | |
NovemberAugust 3, 20212022
Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
BALTIMORE GAS AND ELECTRIC COMPANY
| | | | | | | | |
| /s/ CARIM V. KHOUZAMI | | /s/ DAVID M. VAHOS |
| Carim V. Khouzami | | David M. Vahos |
Chief Executive Officer
(Principal Executive Officer) | | Senior Vice President, Chief Financial Officer and Treasurer
(Principal Financial Officer) |
| | |
| /s/ JASON T. JONES | | |
| Jason T. Jones | | |
Director, Accounting
(Principal Accounting Officer) | | |
NovemberAugust 3, 20212022
Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
PEPCO HOLDINGS LLC
| | | | | | | | |
/s/ DAVID M. VELAZQUEZJ. TYLER ANTHONY | | /s/ PHILLIP S. BARNETT |
David M. VelazquezJ. Tyler Anthony | | Phillip S. Barnett |
President and Chief Executive Officer
(Principal Executive Officer) | | Senior Vice President, Chief Financial Officer and Treasurer
(Principal Financial Officer) |
| | |
| /s/ JULIE E. GIESE | | |
| Julie E. Giese | | |
Director, Accounting
(Principal Accounting Officer) | | |
NovemberAugust 3, 20212022
Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
POTOMAC ELECTRIC POWER COMPANY
| | | | | | | | |
/s/ DAVID M. VELAZQUEZJ. TYLER ANTHONY | | /s/ PHILLIP S. BARNETT |
David M. VelazquezJ. Tyler Anthony | | Phillip S. Barnett |
President and Chief Executive Officer
(Principal Executive Officer) | | Senior Vice President, Chief Financial Officer and Treasurer
(Principal Financial Officer) |
| | |
| /s/ JULIE E. GIESE | | |
| Julie E. Giese | | |
Director, Accounting
(Principal Accounting Officer) | | |
NovemberAugust 3, 20212022
Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
DELMARVA POWER & LIGHT COMPANY
| | | | | | | | |
/s/ DAVID M. VELAZQUEZJ. TYLER ANTHONY | | /s/ PHILLIP S. BARNETT |
David M. VelazquezJ. Tyler Anthony | | Phillip S. Barnett |
President and Chief Executive Officer
(Principal Executive Officer) | | Senior Vice President, Chief Financial Officer and Treasurer
(Principal Financial Officer) |
| | |
| /s/ JULIE E. GIESE | | |
| Julie E. Giese | | |
Director, Accounting
(Principal Accounting Officer) | | |
NovemberAugust 3, 20212022
Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
ATLANTIC CITY ELECTRIC COMPANY
| | | | | | | | |
/s/ DAVID M. VELAZQUEZJ. TYLER ANTHONY | | /s/ PHILLIP S. BARNETT |
David M. VelazquezJ. Tyler Anthony | | Phillip S. Barnett |
President and Chief Executive Officer
(Principal Executive Officer) | | Senior Vice President, Chief Financial Officer and Treasurer
(Principal Financial Officer) |
| | |
| /s/ JULIE E. GIESE | | |
| Julie E. Giese | | |
Director, Accounting
(Principal Accounting Officer) | | |
NovemberAugust 3, 20212022