| | | | | | | | | GLOSSARY OF TERMS AND ABBREVIATIONS | Exelon Corporation and Related Entities | Exelon | | Exelon Corporation | Generation | | Constellation Energy Generation, LLC (formerly Exelon Generation Company, LLC, a subsidiary of Exelon as of December 31, 2021 prior to separation on February 1, 2022) | ComEd | | Commonwealth Edison Company | PECO | | PECO Energy Company | BGE | | Baltimore Gas and Electric Company | Pepco Holdings or PHI | | Pepco Holdings LLC (formerly Pepco Holdings, Inc.) | 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 | Legacy PHI | | PHI, Pepco, DPL, ACE, PES, and PCI, collectively | ACE Funding or ATF | | Atlantic City Electric Transition Funding LLC | Antelope Valley | | Antelope Valley Solar Ranch One | BondCo | | RSB BondCo LLC | BSC | | Exelon Business Services Company, LLC | CENG | | Constellation Energy Nuclear Group, LLC | Constellation | | | Constellation | | Constellation Energy Group, Inc. | EEDCCR | | Constellation Renewables, LLC (formerly ExGen Renewables IV, LLC) | CRP | | Constellation Renewables Partners, LLC (formerly ExGen Renewables Partners, LLC) | EEDC | | Exelon Energy Delivery Company, LLC | EGR IV | | ExGen Renewables IV, LLC | EGRP | | ExGen Renewables Partners, LLC | EGTP | | ExGen Texas Power, LLC | Entergy | | Entergy Nuclear FitzPatrick, LLC | Exelon Corporate | | Exelon in its corporate capacity as a holding company | Exelon Transmission Company | | Exelon Transmission Company, LLC | Exelon WindFitzPatrick | | Exelon Wind, LLC and Exelon Generation Acquisition Company, LLC | FitzPatrick | | James A. FitzPatrick nuclear generating station | Ginna | | R. E. Ginna nuclear generating station | PCINER | | NewEnergy Receivables LLC | PCI | | Potomac Capital Investment Corporation and its subsidiaries | PEC L.P. | | PECO Energy Capital, L.P. | PECO Trust III | | PECO Energy Capital Trust III | PECO Trust IV | | PECO Energy Capital Trust IV | Pepco Energy Services or PES | | Pepco Energy Services, Inc. and its subsidiaries | PHI Corporate | | PHI in its corporate capacity as a holding company | PHISCO | | PHI Service Company | RPG | | Renewable Power Generation, LLC | SolGen | | SolGen, LLC | TMI | | Three Mile Island nuclear facility | UII | | Unicom Investments, Inc. |
| | | | | | | | | GLOSSARY OF TERMS AND ABBREVIATIONS | Other Terms and Abbreviations | | | | | | GLOSSARY OF TERMS AND ABBREVIATIONS | | | Other Terms and AbbreviationsABO | | Accumulated Benefit Obligation | 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 | AGEAMI | | Albany Green Energy Project | AMI | | Advanced Metering Infrastructure | AMPAOCI | | Advanced Metering Program | AOCI | | Accumulated Other Comprehensive Income (Loss) | ARC | | Asset Retirement Cost | ARO | | Asset Retirement Obligation | ARP | | Alternative Revenue Program | ASA | | Asset Sale Agreement | BGS | | | BGS | | Basic Generation Service | CAISOBrookfield Renewable | | California ISOBrookfield Renewable Partners, L.P. | CAPBSA | | Customer Assistance ProgramBill Stabilization Adjustment | CCGTsCAISO | | Combined-Cycle gas turbinesCalifornia ISO | CERCLACBAs | | Collective Bargaining Agreements | CERCLA | | Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended | CES | | Clean Energy Standard | Clean Air Act | | Clean Air Act of 1963, as amended | Clean Water Act | | Federal Water Pollution Control Amendments of 1972, as amended | CODMCMC | | Carbon Mitigation Credit | CODM | | Chief Operating Decision Maker | Conectiv | | Conectiv, LLC, a wholly owned subsidiary of PHI and the parent of DPL and ACE during the Predecessor periods | Conectiv Energy | | Conectiv Energy Holdings, Inc. and substantially all of its subsidiaries, which were sold to Calpine in July 2010 | ConEdison Solutions | | The competitive retail electricity and natural gas business of Consolidated Edison Solutions, Inc., a subsidiary of Consolidated Edison, Inc | CSAPR | | Cross-State Air Pollution Rule | CTA | | Consolidated tax adjustment | D.C. Circuit Court | | United States Court of Appeals for the District of Columbia Circuit | DC PLUG | | District of Columbia Power Line Undergrounding Initiative | DCPSC | | District of Columbia Public Service Commission | DDOT | | District Department of Transportation | DOEDEPSC | | Delaware Public Service Commission | DOE | | United States Department of Energy | DOEE | | Department of Energy & Environment | DOJ | | United States Department of Justice | DPSCDPP | | Delaware Public Service CommissionDeferred Purchase Price | DSP | | | DSP | | Default Service Provider | DSP ProgramEDF | | Default Service Provider Program | EDF | | Electricite de France SA and its subsidiaries | EIMA | | | | | | EIMA | | Energy Infrastructure Modernization Act (Illinois Senate Bill 1652 and Illinois House Bill 3036) | EmPower | | A Maryland demand-side management program for Pepco and DPL |
| EPA | | | GLOSSARY OF TERMS AND ABBREVIATIONS | Other Terms and Abbreviations | | | EPA | | United States Environmental Protection Agency | EPSAERCOT | | Electric Power Supply Association | ERCOT | | Electric Reliability Council of Texas | ERISA | | Employee Retirement Income Security Act of 1974, as amended | EROA | | Expected Rate of Return on Assets | FASB | | Financial Accounting Standards Board | FEJAERP | | Enterprise Resource Program | | | | 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 |
| | | | | | | | | GWh | | Gigawatt hourGLOSSARY OF TERMS AND ABBREVIATIONS | IBEWOther Terms and Abbreviations | | International Brotherhood of Electrical Workers | ICCGWh | | Gigawatt hour | ICC | | Illinois Commerce Commission | ICE | | Intercontinental Exchange | IIP | | Infrastructure Investment Program | Illinois EPA | | Illinois Environmental Protection Agency | Illinois Settlement Legislation | | Legislation enacted in 2007 affecting electric utilities in Illinois | IntegrysIPA | | Integrys Energy Services, Inc. | IPA | | Illinois Power Agency | IRC | | Internal Revenue Code | IRS | | Internal Revenue Service | ISO | | Independent System Operator | ISO-NE | | ISO New England Inc. | NYISO | | New York ISO | kV | | Kilovolt | kWkWh | | KilowattKilowatt-hour | kWhLIBOR | | Kilowatt-hour | LIBOR | | London Interbank Offered Rate | LLRW | | Low-Level Radioactive Waste | LNG | | Liquefied Natural Gas | LTIP | | Long-Term Incentive Plan | MAPP | | Mid-Atlantic Power Pathway | MATS | | U.S. EPA Mercury and Air Toxics Rule | MBR | | Market Based Rates Incentive | MDE | | Maryland Department of the Environment | MDPSC | | Maryland Public Service Commission | MGP | | Manufactured Gas Plant | MISO | | Midcontinent Independent System Operator, Inc. |
| | | | GLOSSARY OF TERMS AND ABBREVIATIONSLTIP | | Long-Term Incentive Plan | Other Terms and Abbreviations | | | mmcfLTRRPP | | Long-Term Renewable Resources Procurement Plan | 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 | Moody’sMOPR | | Moody’s Investor Service | MOPR | | Minimum Offer Price Rule | MRVMPSC | | Market-Related ValueMissouri Public Service Commission | MWMRV | | MegawattMarket-Related Value | MWhMW | | Megawatt hour | n.m.MWh | | not meaningfulMegawatt hour | NAAQSN/A | | National Ambient Air Quality StandardsNot applicable | NAV | | Net Asset Value | NDT | | Nuclear Decommissioning Trust | NEIL | | Nuclear Electric Insurance Limited | NERC | | North American Electric Reliability Corporation | NGSNGX | | Natural Gas SupplierExchange | NJBPU | | New Jersey Board of Public Utilities | NJDEP | | New Jersey Department of Environmental Protection | NLRBNon-Regulatory Agreement Units | | National Labor Relations Board | Non-Regulatory Agreements 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 | NPDES | | National Pollutant Discharge Elimination System | NPNS | | Normal Purchase Normal Sale scope exception | NRC | | Nuclear Regulatory Commission | NSPS | | New Source Performance Standards | NWPA | | Nuclear Waste Policy Act of 1982 | NYMEX | | New York Mercantile Exchange | NYPSC | | New York Public Service Commission | OCIOCEP | | Oyster Creek Environmental Protection, LLC | OCI | | Other Comprehensive Income |
| | | | | | | | | OIESOGLOSSARY OF TERMS AND ABBREVIATIONS | Other Terms and Abbreviations | | | OIESO | | Ontario Independent Electricity System Operator | OPCOPEB | | Office of People’s Counsel | OPEB | | Other Postretirement Employee Benefits | | | | PA DEP | | Pennsylvania Department of Environmental Protection | PAPUC | | Pennsylvania Public Utility Commission | PCB | | Polychlorinated Biphenyl | PGC | | Purchased Gas Cost Clause | | | | PG&E | | Pacific Gas and Electric Company | PJM | | PJM Interconnection, LLC | POLR | | Provider of Last Resort | PORPPA | | Purchase of Receivables | PPA | | Power Purchase Agreement | PP&E | | Property, Plant, and Equipment | Price-Anderson Act | | Price-Anderson Nuclear Industries Indemnity Act of 1957 | Preferred Stock | | Originally issued shares of non-voting, non-convertible and non-transferable Series A preferred stock, par value $0.01 per share |
| PRP | | | GLOSSARY OF TERMS AND ABBREVIATIONS | Other Terms and Abbreviations | | | PRP | | Potentially Responsible Parties | PSEG | | Public Service Enterprise Group Incorporated | PVPUCT | | PhotovoltaicPublic Utility Commission of Texas | RCRAPV | | Photovoltaic | RCRA | | Resource Conservation and Recovery Act of 1976, as amended | REC | | Renewable Energy Credit which is issued for each megawatt hour of generation from a qualified renewable energy source | Regulatory Agreement Units | | Nuclear generating units or portions thereof whose decommissioning-related activities are subject to contractual elimination under regulatory accounting | RES | | Retail Electric Suppliers | RFP | | Request for Proposal | Rider | | Reconcilable Surcharge Recovery Mechanism | RGGI | | Regional Greenhouse Gas Initiative | RMC | | Risk Management Committee | RNF | | Revenue Net of Purchased Power and Fuel Expense | ROE | | Return on equity | ROU | | Right-of-use | RPMRPS | | PJM Reliability Pricing Model | RPS | | Renewable Energy Portfolio Standards | RSSARTEP | | Reliability Support Services Agreement | RTEP | | Regional Transmission Expansion Plan | RTO | | Regional Transmission Organization | S&P | | Standard & Poor’s Ratings Services | SEC | | United States Securities and Exchange Commission | SERC | | | SERC | | SERC Reliability Corporation (formerly Southeast Electric Reliability Council) | SGIG | | Smart Grid Investment Grant from DOE | SILOSNF | | Sale-In, Lease-Out | SNF | | Spent Nuclear Fuel | SOSSOA | | Society of Actuaries | SOFR | | Secured Overnight Financing Rate | SOS | | Standard Offer Service | SPFPASPP | | Security, Police and Fire Professionals of America | SPP | | Southwest Power Pool | TCJASSA | | Social Security Administration | STRIDE | | Maryland Strategic Infrastructure Development and Enhancement Program | TCJA | | Tax Cuts and Jobs Act
| Transition Bond Charge | | Revenue ACE receives, and pays to ACE Funding, to fund the principal and interest payments on Transition Bonds and related taxes, expenses, and fees |
| | | | | | | | | GLOSSARY OF TERMS AND ABBREVIATIONS | Other Terms and Abbreviations | | | Transition Bonds | | Transition Bonds issued by ACE Funding | UpstreamU.S. Court of Appeals for the D.C. Circuit | | Natural gas and oil exploration and production activitiesUnited States Court of Appeals for the District of Columbia Circuit | VIE | | Variable Interest Entity | WECC | | Western Electric Coordinating Council | ZEC | | Zero Emission Credit | ZES | | Zero Emission Standard |
FILING FORMAT This combined Annual Report on Form 10-K 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. 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, including those factors discussed with respect to the Registrants discussed in (a) Part I, ITEM 1A. Risk Factors, (b) Part II, ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, and (c) Part II, ITEM 8. Financial Statements and Supplementary Data: Note 18,19, Commitments and Contingencies;Contingencies, and (d) other factors discussed in filings with the SEC by the Registrants. Readers 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 General Corporate Structure and Business and Other Information As of December 31, 2021, Exelon iswas 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, creating two publicly traded companies with the resources necessary to best serve customers and sustain long-term investment and operating excellence. The separation was completed on February 1, 2022 and gives each company the financial and strategic independence to focus on its specific customer needs, while executing its core business strategy. See Note 26 – Separation of the Combined Notes to Consolidated Financial Statements for additional information. | | | | | | | | | | | | | | | Name of Registrant / Subsidiary | | State/Jurisdiction andBusiness | | Business | | Service Territories | Year of Incorporation | Territories | Commonwealth Edison Company (registrant) | | 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 (registrant) | | 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 (registrant) | | 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 (registrant) | | Utility services holding company engaged, through its reportable segments Pepco, DPL, and ACE | | Service Territories of Pepco, DPL, and ACE | | | | | | Potomac Electric Power Company (registrant) | | 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 (registrant) | | 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 (registrant) | | Purchase and regulated retail sale of electricity | | Portions of Southern New Jersey | | | Transmission and distribution of electricity to retail customers | | | Constellation Energy Generation, LLC (formerly Exelon Generation Company, LLC LLC) (subsidiary) | | Pennsylvania (2000) | | 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 | | Illinois (1913) | | 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 | | Pennsylvania (1929) | | 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 | | Maryland (1906) | | 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 | | Delaware (2016) | | Utility services holding company engaged, through its reportable segments Pepco, DPL and ACE | | Service Territories of Pepco, DPL and ACE | | | | | | | | Potomac Electric
Power Company
| | District of Columbia (1896)
Virginia (1949)
| | 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 | | Delaware (1909)
Virginia (1979)
| | 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 | | New Jersey (1924) | | Purchase and regulated retail sale of electricity | | Portions of Southern New Jersey | | | | | Transmission and distribution of electricity to retail customers | | |
Business Services 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” within the consolidated financial statements and include intercompany eliminations unless otherwise disclosed.
Merger with Pepco Holdings, Inc. (Exelon)
On March 23, 2016, Exelon completed the merger contemplated by the Merger Agreement among Exelon, Purple Acquisition Corp., a wholly owned subsidiary of Exelon (Merger Sub) and PHI. As a result of that merger, Merger Sub was merged into PHI (the PHI Merger) with PHI surviving as a wholly owned subsidiary of Exelon and EEDC, a wholly owned subsidiary of Exelon which also owns Exelon's interests in ComEd, PECO and BGE (through a special purpose subsidiary in the case of BGE). Following the completion of the PHI Merger, Exelon and PHI completed a series of internal corporate organization restructuring transactions resulting in the transfer of PHI’s unregulated business interests to Exelon and Generation and the transfer of PHI, Pepco, DPL and ACE to a special purpose subsidiary of EEDC.
Generation Generation, one of the largest competitive electric generation companies in the United States as measured by owned and contracted MW, physically delivers and markets power across multiple geographic regions through its customer-facing business, Constellation. Constellation sells electricity and natural gas, including renewable energy and associated attributes, in competitive domestic energy markets to both wholesale and retail customers. Generation leverages its energy generation portfolio to ensure delivery of energy to both wholesale and retailserve customers under both long-term and short-term contracts, and in wholesale power markets.as well as spot market sales. Generation operates in well-developed energy markets and employs an integrated and ratable hedging strategystrategies to manage commodity price volatility. Generation's fleet also provides geographic and supply source diversity. Generation’s customers include distribution utilities, municipalities, cooperatives, financial institutions, and commercial, industrial, governmental, and residential customers in competitive markets. Generation’s customer-facing activities foster development and delivery of other innovative energy-related products and services for its customers. Generation is a public utility as defined under the Federal Power Act and is subject to FERC’s exclusive ratemaking jurisdiction over wholesale sales of electricity and the transmission of electricity in interstate commerce. Under the Federal Power Act, FERC has the authority to grant or deny market-based rates for sales of energy, capacity, and ancillary services to ensure that such sales are just and reasonable. FERC’s jurisdiction over ratemaking includes the authority to suspend the market-based rates of utilities and set cost-based rates should FERC find that its previous grant of market-based rates authority is no longer just and reasonable. Other matters subject to FERC jurisdiction include, but are not limited to, third-party financings; review of mergers; dispositions of jurisdictional facilities and acquisitions of securities of another public utility or an existing operational generating facility; affiliate transactions; intercompany financings and cash management arrangements; certain internal corporate reorganizations; and certain holding company acquisitions of public utility and holding company securities. RTOs and ISOs exist in a number of regions to provide transmission service across multiple transmission systems. FERC has approved PJM, MISO, ISO-NE, and SPP as RTOs and CAISO and NYISO as ISOs. These entities are responsible for regional planning, managing transmission congestion, developing wholesale markets for energy and capacity, maintaining reliability, market monitoring, the scheduling of physical power sales brokered through ICE and NYMEX, and the elimination or reduction of redundant transmission charges imposed by multiple transmission providers when wholesale customers take transmission service across several transmission systems. ERCOT is not subject to regulation by FERC but performs a similar function in Texas to that performed by RTOs in markets regulated by FERC. Specific operations of Generation are also subject to the jurisdiction of various other Federal, state, regional, and local agencies, including the NRC, and Federal and state environmental protection agencies. Additionally, Generation is subject to NERC mandatory reliability standards, which protect the nation’s bulk power system against potential disruptions from cyber and physical security breaches. Acquisitions and Dispositions
DispositionTable of Oyster Creek.On July 1, 2019, Generation completed the sale with Holtec International (Holtec) and its indirect wholly owned subsidiary, Oyster Creek Environmental Protection, LLC (OCEP), of Oyster Creek located in Forked River, New Jersey, which permanently ceased generation operations on September 17, 2018.
Disposition of EGTP and Acquisition of Handley Generating Station. On November 7, 2017, EGTP and all of its wholly owned subsidiaries filed voluntary petitions for relief under Chapter 11 of Title 11 of the United States Code in the United States Bankruptcy Court for the District of Delaware. As a result of the bankruptcy filing, EGTP’s assets and liabilities were deconsolidated from Exelon and Generation's consolidated financial statements. The Chapter 11 bankruptcy proceedings were finalized on April 17, 2018, resulting in the ownership of EGTP assets (other than the Handley Generating Station) being transferred to EGTP's lenders.
On April 4, 2018, Generation acquired the Handley Generating Station in conjunction with the EGTP Chapter 11 proceedings for a total purchase price of $62 million.
Acquisition of FitzPatrick. On March 31, 2017, Generation acquired the single-unit FitzPatrick plant located in Scriba, New York from Entergy for a total purchase price consideration of $289 million, resulting in an after-tax bargain purchase gain of $233 million in 2017.Contents
Acquisition of ConEdison Solutions. On September 1, 2016, Generation acquired ConEdison Solutions for a purchase price of $257 million, including net working capital of $204 million. The renewable energy, sustainable services and energy efficiency businesses of ConEdison were excluded from the transaction.
See Note 2 — Mergers, Acquisitions and Dispositions and Note 11 — Asset Impairments of the Combined Notes to Consolidated Financial Statements for additional information on acquisitions and dispositions.
Generating Resources At December 31, 2019,2021, the generating resources of Generation consisted of the following: | | | | | | Type of Capacity | MW | Owned generation assets(a)(b) | | Nuclear | 18,87220,899 |
| Fossil (primarily natural gas and oil) | 9,6658,819 |
| Renewable(c)(b) | 3,0572,682 |
| Owned generation assets | 31,59432,400 |
| Contracted generation(d)(c) | 4,765 |
| Total generating resources | 36,359 |
|
4,102 __________
| | (a)Total generating resources | See “Fuel” for sources of fuels used in electric generation. |
36,502 | | (b) | Net generation capacity is stated at proportionate ownership share. See ITEM 2. PROPERTIES—Generation for additional information. |
| | (c) | Includes wind, hydroelectric, solar and biomass generation. |
| | (d) | Electric supply procured under site specific agreements. |
__________ (a)Net generation capacity is stated at proportionate ownership share. See ITEM 2. PROPERTIES—Generation for additional information. (b)Includes wind, hydroelectric, and solar generating assets. (c)Electric supply procured under unit-specific agreements. Generation has five reportable segments, as described in the table below, representing the different geographical areas in which Generation’s owned generating resources are located and Generation's customer-facing activities are conducted. | | | | | | | | | | | | | | | | | | | | | Segment | | Net Generation Capacity (MW)(a) | | % of Net Generation Capacity | | Geographical Area | Mid-Atlantic | | 10,508 | | | 32 | % | | 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 | | 11,898 | | | 37 | % | | Western half of PJM and the United States footprint of MISO, excluding MISO’s Southern Region | New York | | 3,093 | | | 10 | % | | NYISO | ERCOT | | 3,610 | | | 11 | % | | Electric Reliability Council of Texas | Other Power Regions | | 3,291 | | | 10 | % | | New England, South, West, and Canada | Total | | 32,400 | | | 100 | % | | |
| | | | | | | Segment | | % of Capacity | | Geographical Area | Mid-Atlantic | | 32 | % | | Eastern half of PJM, which includes Pennsylvania, New Jersey, Maryland, Virginia, West Virginia, Delaware, the District of Columbia and parts of North Carolina | Midwest | | 38 | % | | Western half of PJM and the United States footprint of MISO, excluding MISO’s Southern Region | New York | | 6 | % | | NYISO | ERCOT | | 11 | % | | Electric Reliability Council of Texas | Other Power Regions | | 13 | % | | New England, South, West and Canada | __________
(a)Net generation capacity is stated at proportionate ownership share. See ITEM 2. PROPERTIES—Generation for additional information.
Nuclear Facilities Generation has ownership interests in thirteen nuclear generating stations currently in service, consisting of 23 units with an aggregate of 18,87220,899 MW of capacity. These stations exclude TMI located in Middletown, Pennsylvania, which permanently ceased generation operations on September 20, 2019 and Oyster Creek located in Forked River, New Jersey, which permanently ceased generation operations on September 17, 2018 and was subsequently sold to Holtec International (Holtec) on July 1, 2019. Generation wholly owns all of its nuclear generating stations, except for undivided ownership interests in threefour jointly-owned nuclear stations: Quad Cities (75% ownership), Peach Bottom (50% ownership), and Salem (42.59% ownership), and Nine Mile Point Unit 2 (82% ownership), which are consolidated in Exelon’s and Generation's financial statements relative to its proportionate ownership interest in each unit, andunit. Generation had a 50.01% membership interest in CENG, a joint venture with EDF, which wholly owns the Calvert Cliffs and Ginna nuclear stations 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. Generation and EDF entered into a Put Option Agreement on April 1, 2014, pursuant to which EDF has anhad the option to sell its 49.99% equity interest in CENG to Generation. The put option becameGeneration exercisable beginning on January 1, 2016 and may be exercised any timethereafter until June 30, 2022. On November 20, 2019,August 6, 2021, Generation received noticeand
EDF entered into a settlement agreement pursuant to which Generation, through a wholly owned subsidiary, purchased EDF’s intention to exercise the put option and sell its ownership shareequity interest in CENG to Generation. Under the terms of the Put Option Agreement, thefor a net purchase price is to be determined by agreement of the parties, or absent such agreement, by a third-party arbitration process. The transaction will require approval of the NYPSC, the FERC and the NRC. The process and regulatory approvals could take one to two years or more to complete.$885 million. See ITEM 2. PROPERTIES for additional information on Generation's nuclear facilities, Note 2 ��� Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information on the acquisition of EDF's equity interest in CENG and the disposition of Oyster Creek, and Note 2223 — Variable Interest Entities of the Combined Notes to Consolidated Financial Statements for additional information regarding the CENG consolidation. Generation’s nuclear generating stations are all operated by Generation, with the exception of the two units at Salem, which are operated by PSEG Nuclear, LLC (PSEG Nuclear), an indirect, wholly owned subsidiary of PSEG. In 2019, 20182021, 2020, and 20172019 electric supply (in GWh) generated from the nuclear generating facilities was 64%65%, 68%62%, and 69%64%, respectively, of Generation’s total electric supply, which also includes fossil, hydroelectric, and renewable generation and electric supply purchased for resale. Generation’s wholesale and retail power marketing activities are, in part, supplied by the output from the nuclear generating stations. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS for additional information of Generation’s electric supply sources. Nuclear Operations Capacity factors, which are significantly affected by the number and duration of refueling and non-refueling outages, can have a significant impact on Generation’s results of operations. Generation’s operations from its nuclear plants have historically had minimal environmental impact and the plants have a safe operating history. During 2019, 2018 and 2017, the nuclear generating facilities operated by Generation achieved capacity factors of 95.7%, 94.6% and 94.1%, respectively. The capacity factors reflect ownership percentage of stations operated by Generation. Generation manages its scheduled refueling outages to minimize their duration and to maintain high nuclear generating capacity factors, resulting in a stable generation base for Generation’s wholesale and retail power marketing activities. During scheduled refueling outages, Generation performs maintenance and equipment upgrades in order to minimize the occurrence of unplanned outages and to maintain safe, reliable operations. During 2021, 2020, and 2019, the nuclear generating facilities operated by Generation, achieved capacity factors of 94.5%, 95.4%, and 95.7%, respectively, at ownership percentage.
In addition to the maintenance and equipment upgrades performed by Generation during scheduled refueling outages, Generation has extensive operating and security procedures in place to ensure the safe operation of the nuclear units. Generation also has extensive safety systems in place to protect the plant, personnel, and surrounding area in the unlikely event of an accident or other incident. Regulation of Nuclear Power Generation Generation is subject to the jurisdiction of the NRC with respect to the operation of its nuclear generating stations, including the licensing for operation of each unit. The NRC subjects nuclear generating stations to continuing review and regulation covering, among other things, operations, maintenance, emergency planning, security, and environmental and radiological aspects of those stations. As part of its reactor oversight process, the NRC continuously assesses unit performance indicators and inspection results and communicates its assessment on a semi-annual basis. All nuclear generating stations operated by Generation are categorized by the NRC in the Licensee Response Column, which is the highest of five performance bands. The NRC may modify, suspend, or revoke operating licenses and impose civil penalties for failure to comply with the Atomic Energy Act the regulations
under such Act or the terms of the operating licenses. Changes in regulations by the NRC may require a substantial increase in capital expenditures and/or operating costs for nuclear generating facilities.
Licenses Generation has original 40-year operating licenses from the NRC for each of its nuclear units and has received 20-year operating license renewals from the NRC for all its nuclear units except Clinton. Additionally, PSEG has received 20-year operating license renewals for Salem Units 1 and 2. Peach Bottom has received a second 20-year license renewal from the NRC for Units 2 and 3.
The following table summarizes the current license expiration dates for Generation’s operating nuclear facilities in service: | | Station | Unit | | In-Service Date(a) | | Current License Expiration | Station | Unit | | In-Service Date(a) | | Current License Expiration | Braidwood | 1 |
| | 1988 | | 2046 | Braidwood | 1 | | | 1988 | | 2046 | | 2 |
| | 1988 | | 2047 | | 2 | | | 1988 | | 2047 | Byron | 1 |
| | 1985 | | 2044 | Byron | 1 | | | 1985 | | 2044 | | 2 |
| | 1987 | | 2046 | | 2 | | | 1987 | | 2046 | Calvert Cliffs | 1 |
| | 1975 | | 2034 | Calvert Cliffs | 1 | | | 1975 | | 2034 | | 2 |
| | 1977 | | 2036 | | 2 | | | 1977 | | 2036 | Clinton(b) | 1 |
| | 1987 | | 2027 | Clinton(b) | 1 | | | 1987 | | 2027 | Dresden | 2 |
| | 1970 | | 2029 | Dresden | 2 | | | 1970 | | 2029 | | 3 |
| | 1971 | | 2031 | | 3 | | | 1971 | | 2031 | FitzPatrick | 1 |
| | 1974 | | 2034 | FitzPatrick | 1 | | | 1975 | | 2034 | LaSalle | 1 |
| | 1984 | | 2042 | LaSalle | 1 | | | 1984 | | 2042 | | 2 |
| | 1984 | | 2043 | | 2 | | | 1984 | | 2043 | Limerick | 1 |
| | 1986 | | 2044 | Limerick | 1 | | | 1986 | | 2044 | | 2 |
| | 1990 | | 2049 | | 2 | | | 1990 | | 2049 | Nine Mile Point | 1 |
| | 1969 | | 2029 | Nine Mile Point | 1 | | | 1969 | | 2029 | | 2 |
| | 1988 | | 2046 | | 2 | | | 1988 | | 2046 | Peach Bottom(c) | 2 |
| | 1974 | | 2033 | | Peach Bottom | | Peach Bottom | 2 | | | 1974 | | 2053 | | 3 |
| | 1974 | | 2034 | | 3 | | | 1974 | | 2054 | Quad Cities | 1 |
| | 1973 | | 2032 | Quad Cities | 1 | | | 1973 | | 2032 | | 2 |
| | 1973 | | 2032 | | 2 | | | 1973 | | 2032 | Ginna | 1 |
| | 1970 | | 2029 | Ginna | 1 | | | 1970 | | 2029 | Salem | 1 |
| | 1977 | | 2036 | Salem | 1 | | | 1977 | | 2036 | | 2 |
| | 1981 | | 2040 | | 2 | | | 1981 | | 2040 |
__________ | | (a) | Denotes year in which nuclear unit began commercial operations. |
| | (b) | Although timing has been delayed, Generation currently plans to seek license renewal for Clinton and has notified the NRC that any license renewal application would not be filed until the first quarter of 2024. In 2019, the NRC approved a change of the operating license expiration for Clinton from 2026 to 2027. |
| | (c) | On July 10, 2018, Generation submitted a second 20-year license renewal application to NRC for Peach Bottom Units 2 and 3. See Note 3 - Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. |
(a)Denotes year in which nuclear unit began commercial operations. (b)Although timing has been delayed, Generation currently plans to seek license renewal for Clinton and has received a Timely Renewal Exemption from the NRC that allows for the license renewal application to be filed in the first quarter of 2024. The operating license renewal process takes approximately four to five years from the commencement of the renewal process, which includes approximately two years for Generation to develop the application and approximately two years for the NRC to review the application. To date, each granted license renewal has been for 20 years beyond the original operating license expiration. Depreciation provisions are based on the estimated useful lives of the stations, which corresponds with the term of the NRC operating licenses denoted in the table above as of December 31, 2021. From August 27, 2020 through September 15, 2021, Byron and Dresden depreciation provisions were accelerated to reflect the first renewalpreviously announced shutdown dates of September 2021 and November 2021, respectively. On September 15, 2021, Generation updated the expected useful lives for both facilities to reflect the end of the available NRC operating licenseslicense for all of Generation’s operating nuclear generating stations except for Clinton and Peach Bottom. Clinton depreciation provisions are based on an estimated useful life of 2027 which iseach unit consistent with the last year of the Illinois ZES. Peach Bottom depreciation provisions are based on estimated
useful life of 2053 and 2054 for Unit 2 and Unit 3, respectively, which reflects the anticipated second renewal of its operating licenses.table above. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on FEJA and Note 67 — Early Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information on early retirements.Byron and Dresden.
Nuclear Waste Storage and Disposal There are no facilities for the reprocessing or permanent disposal of SNF currently in operation in the United States, nor has the NRC licensed any such facilities. Generation currently stores all SNF generated by its nuclear generating facilities on-site in storage pools or in dry cask storage facilities. Since Generation’s SNF storage pools generally do not have sufficient storage capacity for the life of the respective plant, Generation has developed dry cask storage facilities to support operations.
As of December 31, 2019,2021, Generation had approximately 84,70089,400 SNF assemblies (21,000(21,900 tons) stored on site in SNF pools or wet and dry cask storage which includes SNF assemblies at Zion Station, for which Generation retains ownership even though theand responsibility for the decommissioning of the Zion Station has been assumed by another party, and TMI, which is no longer operational. See the Decommissioning section below for additional information regarding Zion Station.Independent Spent Fuel Storage Installation. All currently operating Generation-owned nuclear sites have on-site dry cask storage. TMI's on-site dry cask storage is projected to be in operation in 2021.2022. On-site dry cask storage in concert with on-site storage pools will be capable of meeting all current and future SNF storage requirements at Generation’s sites through the end of the license renewal periods and through decommissioning. For a discussion of matters associated with Generation’s contracts with the DOE for the disposal of SNF, see Note 1819 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements. As a by-product of their operations, nuclear generating units produce LLRW. LLRW is accumulated at each generating station and permanently disposed of at licensed disposal facilities. The Federal Low-Level Radioactive Waste Policy Act of 1980 provides that states may enter into agreements to provide regional disposal facilities for LLRW and restrict use of those facilities to waste generated within the region. Illinois and Kentucky have entered into such an agreement, although neither state currently has an operational site and none is anticipated to be operational until after 2020.for the next ten years. Generation ships its Class A LLRW, which represents 93% of LLRW generated at its stations, to disposal facilities in Utah and South Carolina, which have enough storage capacity to store all Class A LLRW for the life of all stations in Generation's nuclear fleet. The disposal facility in South Carolina at present is only receiving LLRW from LLRW generators in South Carolina, New Jersey (which includes Salem), and Connecticut. Generation utilizes on-site storage capacity at all its stations to store and stage for shipping Class B and Class C LLRW. Generation has a contract through 20322040 to ship Class B and Class C LLRW to a disposal facility in Texas. The agreement provides for disposal of all current Class B and Class C LLRW currently stored at each station as well as the Class B and Class C LLRW generated during the term of the agreement. However, because the production of LLRW from Generation’s nuclear fleet will exceed the capacity at the Texas site (3.9 million curies for 15 years beginning in 2012), Generation will still be required to utilize on-site storage at its stations for Class B and Class C LLRW. Generation currently has enough storage capacity to store all Class B and Class C LLRW for the life of all stations in Generation’s nuclear fleet. Generation continues to pursue alternative disposal strategies for LLRW, including an LLRW reduction program to minimize on-site storage and cost impacts. Nuclear Insurance Generation is subject to liability, property damage, and other risks associated with major incidents at all of its nuclear stations. Generation has reduced its financial exposure to these risks through insurance and other industry risk-sharing provisions. See “Nuclear Insurance” within Note 1819 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information. For information regarding property insurance, see ITEM 2. PROPERTIES — Generation. Generation is self-insured to the extent that any losses may exceed the amount of insurance maintained or are within the policy deductible for its insured losses. Such losses could have a material adverse effect on Exelon’s and Generation’s future financial statements.
Decommissioning
NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in specified minimum amounts at the end of the life of the facility to decommission the facility. The ultimate decommissioning obligation will be funded by the NDTs. At December 31, 2019 the fair value of NDTs exceeds the balance of the Nuclear AROs. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Exelon Corporation, Executive Overview; ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, Critical Accounting Policies and Estimates, Nuclear Decommissioning, Asset Retirement Obligations and Nuclear Decommissioning Trust Fund Investments; and Note 3 — Regulatory Matters, Note 2 — Mergers, Acquisitions and Dispositions, Note 17 — Fair Value of Financial Assets and Liabilities and Note 9 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information regarding Generation’s NDT funds and its decommissioning obligations.
Zion Station Decommissioning. On September 1, 2010, Generation completed an Asset Sale Agreement (ASA) with EnergySolutions, Inc. and its wholly owned subsidiaries, EnergySolutions, LLC and ZionSolutions under which ZionSolutions has assumed responsibility for decommissioning Zion Station. See Note 9 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information.
Fossil and Renewable Facilities (including Hydroelectric) Generation wholly owns all of its fossil and renewable generating stations, with the exception of:except for: (1) Wyman; (2) certain wind project entities and a biomass project entity with minority interest owners;entities; and (3) EGRPCRP, which is owned 49% by another owner. See Note 2223 — Variable Interest Entities of the Combined Notes to Consolidated Financial Statements for additional information regarding EGRPCRP which is a VIE. Generation’s fossil and renewable generating stations are all operated by Generation, with the exception ofexcept for Wyman, which is operated by the principal owner, NextEra Energy Resources LLC, a third party.subsidiary of the FPL Group, Inc. In 2019, 20182021, 2020, and 2017,2019, electric supply (in GWh) generated from owned fossil and renewable generating facilities was 11%10%, 11%9%, and 12%11%, respectively, of Generation’s total electric supply. The majorityMuch of this output was dispatched to support Generation’s wholesale and retail power marketing activities. ForOn March 31, 2021 and June 30, 2021, Generation completed the sale of a significant portion of its solar business and its interest in the Albany Green Energy biomass facility, respectively. See ITEM 2. PROPERTIES for additional information regarding Generation’sGeneration's electric generating facilities see ITEM 2. PROPERTIES.and Note 2 - Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information on these dispositions.
Licenses Fossil and renewable generation plants are generally not licensed, and, therefore, the decision on when to retire plants is, fundamentally, a commercial one. FERC has the exclusive authority to license most non-Federal hydropower projects located on navigable waterways or Federal lands, or connected to the interstate electric grid, which include Generation's Conowingo Hydroelectric Project (Conowingo) and Muddy Run Pumped Storage Facility Project (Muddy Run). Muddy Run's license expires on December 1, 2055. On August 29, 2012, Generation submitted a hydroelectric license application to the FERC for a new license for Conowingo. Based2055 and Conowingo's on the FERC procedural schedule, the FERC licensing process for Conowingo was not completed prior to the expiration of the plant’s license on September 1, 2014. As a result, on September 10, 2014, FERC issued an annual license for Conowingo, effective as of the expiration of the previous license. The annual license renews automatically absent any further FERC action.February 28, 2071. The stations are currently being depreciated over their estimated useful lives, which include actual and anticipatedcorrespond with the license renewal periods.terms. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.information on Conowingo. Insurance Generation maintains business interruption insurance for its renewable projects, but not for its fossil and hydroelectric operations unless required by contract or financing agreements. See Note 1617 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on financing agreements. Generation maintains both property damage and liability insurance. For property damage and liability claims for these operations, Generation is self-insured to the extent that losses are within the policy deductible or exceed the amount of insurance maintained. Such losses could have a material adverse effect on Exelon’s and Generation’s future financial conditions and their results of operations and cash flows. For information regarding property insurance, see ITEM 2. PROPERTIES — Exelon Generation Company, LLC.
Generation.
Contracted Generation In addition to energy produced by owned generation assets, Generation sources electricity from plants it does not own under long-term contracts. The following tables summarize Generation’s long-term contracts to purchase unit-specific physical power with an original term in excess of one year in duration, by region, in effect as of December 31, 2019:2021: | | | | | | | | | | | | | | | | | | | | | Region | | Number of Agreements | | Expiration Dates | | Capacity (MW) | Mid-Atlantic | | 7 | | | 2022 - 2032 | | 176 | | Midwest | | 3 | | | 2026 - 2032 | | 351 | | New York | | 4 | | | 2022 | | 26 | | ERCOT | | 5 | | | 2022 - 2035 | | 864 | | Other Power Regions | | 12 | | | 2022 - 2033 | | 2,685 | | Total | | 31 | | | | | 4,102 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2022 | | 2023 | | 2024 | | 2025 | | 2026 | | Thereafter | | Total | Capacity Expiring (MW) | | 1,084 | | | 114 | | | 101 | | | 490 | | | 398 | | | 1,915 | | | 4,102 | |
| | | | | | | | | | Region | | Number of Agreements | | Expiration Dates | | Capacity (MW) | Mid-Atlantic | | 13 |
| | 2020 - 2032 | | 235 |
| Midwest | | 3 |
| | 2020 - 2031 | | 332 |
| ERCOT | | 6 |
| | 2020 - 2035 | | 1,706 |
| Other Power Regions | | 16 |
| | 2020 - 2030 | | 2,492 |
| Total | | 38 |
| | | | 4,765 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | 2020 | | 2021 | | 2022 | | 2023 | | 2024 | | Thereafter | | Total | Capacity Expiring (MW) | | 1,054 |
| | 814 |
| | 304 |
| | 168 |
| | 50 |
| | 2,375 |
| | 4,765 |
|
Fuel The following table shows sources of electric supply in GWh for 20192021 and 2018:2020: | | | | | | | | | | | | | Source of Electric Supply | | 2021 | | 2020 | Nuclear(a) | 174,987 | | | 175,085 | | Purchases — non-trading portfolio | 67,605 | | | 79,972 | | Fossil (primarily natural gas and oil) | 19,960 | | | 19,501 | | Renewable(b) | 6,577 | | | 7,052 | | Total supply | 269,129 | | | 281,610 | |
| | | | | | | | Source of Electric Supply | | 2019 | | 2018 | Nuclear(a) | 181,326 |
| | 185,020 |
| Purchases — non-trading portfolio | 70,939 |
| | 59,154 |
| Fossil (primarily natural gas and oil) | 21,554 |
| | 21,015 |
| Renewable(b) | 7,777 |
| | 8,469 |
| Total supply | 281,596 |
|
| 273,658 |
|
__________ | | (a) | Includes the proportionate share of output where Generation has an undivided ownership interest in jointly-owned generating plants and includes the total output of plants that are fully consolidated (e.g., CENG). Nuclear generation for 2019 and 2018 includes physical volumes of 35,745 GWh and 35,100 GWh, respectively, for CENG. |
| | (b) | Includes wind, hydroelectric, solar and biomass generating assets. |
(a)Includes the proportionate share of output where Generation has an undivided ownership interest in jointly-owned generating plants and includes the total output of plants that are fully consolidated. (b)Includes wind, hydroelectric, solar, and biomass generating assets. The cycle of production and utilization of nuclear fuel includes the mining and milling of uranium ore into uranium concentrates, the conversion of uranium concentrates to uranium hexafluoride, the enrichment of the uranium hexafluoride, and the fabrication of fuel assemblies. Generation has inventory in various forms and does not anticipate difficulty in obtaining the necessary uranium concentrates or conversion, enrichment, or fabrication services to meet the nuclear fuel requirements of its nuclear units. Natural gas is procured through long-term and short-term contracts, as well as spot-market purchases. Fuel oil inventories are managed so that in the winter months sufficient volumes of fuel are available in the event of extreme weather conditions and during the remaining months to take advantage of favorable market pricing. Generation uses financial instruments to mitigate price risk associated with certain commodity price exposures, using both over-the-counter and exchange-traded instruments. See ITEM 1A. RISK FACTORS, ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, Critical Accounting Policies and Estimates and Note 1516 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding derivative financial instruments. Power Marketing Generation’s integrated business operations include physical delivery and marketing of power.power and natural gas. Generation largely obtains physical power supply from its owned and contracted generation in multiple geographic regions. The
commodity risks associated with the output from owned and contracted generation is managed using various commodity transactions including sales to customers.customers and its ratable hedging program. The main objective is to obtain low-cost energy supply to meet physical delivery obligations to both wholesale and retail customers. Generation sells electricity, natural gas, and other energy related products and solutions to various customers, including distribution utilities, municipalities, cooperatives, and commercial, industrial, governmental, and residential customers in competitive markets. Where necessary, Generation may also purchase transmission service to ensure that it has reliable transmission capacity to physically move its power supplies to meet customer delivery needs. Price and Supply Risk Management Generation also managesuses a combination of wholesale and retail customer load sales, as well as 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 the price and supply risks for energy and fuel associated withrisk of the generation assets and the risks of power marketing activities.portfolio. Generation implements a three-year ratable sales plan to align its hedging strategy with its financial objectives. Generation may also enter into transactions that are outside of this ratable sales plan. Generation is exposed to commodity price risk in 2020 and beyond for portions of its electricity portfolio that are unhedged. As of December 31, 2019, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York and ERCOT reportable segments is 91%-94% and 61%-64% for 2020 and 2021, respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation. Expected generation is the volume of energy that best represents our commodity position in energy markets from owned or contracted generation based upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products and options. Equivalent sales represent all hedging products, which include economic hedges and certain non-derivative contracts, including sales to the Utility Registrants to serve their retail load. program. A portion of Generation’s hedging strategy may be implemented through the use ofusing fuel products based on assumed correlations between power and fuel prices. The risk management group and Exelon’s RMC monitormonitors the financial risks of the wholesale and retail power marketing activities. Generation also uses financial and commodity contracts for proprietary trading purposes, but this activity accounts for only a small portion of Generation’s efforts. The
proprietary trading portfolio is subject to a risk management policy that includes stringent risk management limits. See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for additional information. Capital Expenditures
Generation’s business is capital intensive and requires significant investments primarily in nuclear fuel and energy generation assets. Generation’s estimated capital expenditures for 2020 includes Generation's share of the investment in the co-owned Salem plant and the total capital expenditures for CENG. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, Liquidity and Capital Resources, for additional information regarding projected 2020 capital expenditures.
Utility Registrants Utility Operations Service Territories and Franchise Agreements The following table presents the size of service territories, populations of each service territory, and the number of customers within each service territory for the Utility Registrants as of December 31, 2019:2021: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE | Service Territories (in square miles) | Electric | | 11,450 | | | 2,100 | | | 2,300 | | | 650 | | | 5,400 | | | 2,750 | | Natural Gas | | N/A | | 1,900 | | | 3,050 | | | N/A | | 250 | | | N/A | Total(a) | | 11,450 | | | 2,100 | | | 3,250 | | | 650 | | | 5,400 | | | 2,750 | | | | | | | | | | | | | | | Service Territory Population (in millions) | Electric | | 9.3 | | | 4.0 | | | 3.0 | | | 2.4 | | | 1.5 | | | 1.2 | | Natural Gas | | N/A | | 2.5 | | | 2.9 | | | N/A | | 0.6 | | | N/A | Total(b) | | 9.3 | | | 4.0 | | | 3.1 | | | 2.4 | | | 1.5 | | | 1.2 | | Main City | | Chicago | | Philadelphia | | Baltimore | | District of Columbia | | Wilmington | | Atlantic City | Main City Population | | 2.7 | | | 1.6 | | | 0.6 | | | 0.7 | | | 0.1 | | | 0.1 | | | | | | | | | | | | | | | Number of Customers (in millions) | Electric | | 4.1 | | | 1.7 | | | 1.3 | | | 0.9 | | | 0.5 | | | 0.6 | | Natural Gas | | N/A | | 0.5 | | | 0.7 | | | N/A | | 0.1 | | | N/A | Total(c) | | 4.1 | | | 1.7 | | | 1.3 | | | 0.9 | | | 0.5 | | | 0.6 | | ___________ | | | | | | | | | | | | | | | | | | | | | | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE | Service Territories (in square miles) | Electric | | 11,400 |
| | 2,100 |
| | 2,300 |
| | 640 |
| | 5,400 |
| | 2,800 |
| Natural Gas | | n/a |
| | 1,960 |
| | 3,050 |
| | n/a |
| | 270 |
| | n/a |
| Total | | 11,400 |
| | 2,100 |
| | 3,250 |
| | 640 |
| | 5,400 |
| | 2,800 |
| | | | | | | | | | | | | | Service Territory Population (in millions) | Electric | | 9.6 |
| | 4.0 |
| | 3.0 |
| | 2.4 |
| | 1.5 |
| | 1.1 |
| Natural Gas | | n/a |
| | 2.5 |
| | 2.9 |
| | n/a |
| | 0.6 |
| | n/a |
| Total | | 9.6 |
| | 4.0 |
| | 3.1 |
| | 2.4 |
| | 1.5 |
| | 1.1 |
| Main City | | Chicago |
| | Philadelphia |
| | Baltimore |
| | District of Columbia |
| | Wilmington |
| | Atlantic City |
| Main City Population | | 2.7 |
| | 1.6 |
| | 0.6 |
| | 0.7 |
| | 0.1 |
| | 0.1 |
| | | | | | | | | | | | | | Number of Customers (in millions) | Electric | | 4.1 |
| | 1.7 |
| | 1.3 |
| | 0.9 |
| | 0.5 |
| | 0.6 |
| Natural Gas | | n/a |
| | 0.5 |
| | 0.7 |
| | n/a |
| | 0.1 |
| | n/a |
| Total | | 4.1 |
| | 1.7 |
| | 1.3 |
| | 0.9 |
| | 0.5 |
| | 0.6 |
|
(a)The number of total service territory square miles counts once only a square mile that includes both electric and natural gas services, and thus does not represent the combined total square mileage of electric and natural gas service territories.(b)The total service territory population counts once only an individual who lives in a region that includes both electric and natural gas services, and thus does not represent the combined total population of electric and natural gas service territories. (c)The number of total customers counts once only a customer who is both an electric and a natural gas customer, and thus does not represent the combined total of electric customers and natural gas customers. The Utility Registrants have the necessary authorizations to perform their current business of providing regulated electric and natural gas distribution services in the various municipalities and territories in which they now supply such services. These authorizations include charters, franchises, permits, and certificates of public convenience issued by local and state governments and state utility commissions. ComEd's, BGE's (gas), Pepco DC's, and ACE's rights are generally non-exclusive while PECO's, BGE's (electric), Pepco MD's, and DPL's rights are generally exclusive. Certain authorizations are perpetual while others have varying expiration dates. The Utility Registrants anticipate working with the appropriate governmental bodies to extend or replace the authorizations prior to their expirations.
Utility Regulations State utility commissions regulate the Utility Registrants' electric and gas distribution rates and service, issuances of certain securities, and certain other aspects of the business. The following table outlines the state commissions responsible for utility oversight. | | | | | | | | | Registrant | | Commission | ComEd | | ICC | PECO | | PAPUC | BGE | | MDPSC | Pepco | | DCPSC/MDPSC | DPL | | DPSC/DEPSC/MDPSC | ACE | | NJBPU |
The Utility Registrants are public utilities under the Federal Power Act subject to regulation by FERC related to transmission rates and certain other aspects of the utilities' business. The U.S. Department of Transportation also regulates pipeline safety and other areas of gas operations for PECO, BGE, and DPL. The U.S. Department of Homeland Security (Transportation Security Administration) provided new security directives in 2021 that regulate cyber risks for certain gas distribution operators. Additionally, the Utility Registrants are subject to NERC mandatory reliability standards, which protect the nation's bulk power system against potential disruptions from cyber and physical security breaches. Seasonality Impacts on Delivery Volumes The Utility Registrants' electric distribution volumes are generally higher during the summer and winter months when temperature extremes create demand for either summer cooling or winter heating. For PECO, BGE, and DPL, natural gas distribution volumes are generally higher during the winter months when cold temperatures create demand for winter heating. ComEd, BGE, Pepco, and DPL Maryland, and ACE have electric distribution decoupling mechanisms and BGE has a natural gas decoupling mechanism that eliminate the favorable and unfavorable impacts of weather and customer usage patterns on electric distribution and natural gas delivery volumes. As a result, ComEd’s, BGE’s, Pepco’sComEd's, BGE's, Pepco's, DPL Maryland's, and DPL’s MarylandACE's electric distribution revenues and BGE's natural gas distribution revenues are not materially impacted by delivery volumes. PECO’sPECO's and DPL Delaware's electric distribution revenues and natural gas distribution revenues, ACE’s electric distribution revenues and DPL’s Delaware electric distribution and natural gas revenues are impacted by delivery volumes. Electric and Natural Gas Distribution Services The Utility Registrants are allowed to recover reasonable costs and fair and prudent capital expenditures associated with electric and natural gas distribution services and earn a return on those capital expenditures, subject to commission approval. ComEd recovers costs through a performance-based rate formula. ComEd is required to file an update to the performance-based rate formula on an annual basis. On September 15, 2021, Illinois passed the Clean Energy Law, which contains requirements for ComEd to transition away from the performance-based rate formula by the end of 2022 and would allow for the submission of either a general rate or multi-year rate plan. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. PECO's, BGE’sBGE's, and DPL's electric and gas distribution costs and Pepco's and ACE's electric distribution costs arehave generally been recovered through traditional rate case proceedings. However, the MDPSC and the DCPSC allow utilities to file multi-year rate plans. In certain instances, the Utility Registrants use specific recovery mechanisms as approved by their respective regulatory agencies. ComEd, Pepco, DPL and ACE customers have the choice to purchase electricity, and PECO BGE and DPLBGE customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers. DPL customers, with the exception of certain commercial and industrial customers, do not have the choice to purchase natural gas from competitive natural gas suppliers. The Utility Registrants remain the distribution service providers for all customers and are obligated to deliver electricity and natural gas to customers in their respective service territories while charging a regulated rate for distribution service. In addition, the Utility Registrants also retain significant default service obligations to provide electricity to certain groups of customers in their respective service areas who do not choose a competitive electric generation supplier. PECO,
BGE, and BGEDPL also retain significant default service obligations to provide natural gas to certain groups of customers in their respective service areas who do not choose a competitive natural gas supplier. For natural gas, DPL does not retain default service obligations for its residential customers. For customers that choose to purchase electric generation or natural gas from competitive suppliers, the Utility Registrants act as the billing agent and therefore do 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 a Utility Registrant, the Utility Registrants are permitted to recover the electricity and natural gas procurement costs from customers without mark-up or with a slight mark-up and therefore record equal and offsettingthe amounts ofin Operating revenues and Purchased power and fuel expense related to the electricity and/or natural gas.expense. As a result, fluctuations in electricity or natural gas sales and procurement costs have no significant impact on the Utility Registrants’ Revenues net of purchased power and fuel expense, which is a non-GAAP measure used to evaluate operational performance, or Net Income.income. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, Results of Operations and Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information regarding electric and natural gas distribution services. Procurement-Related ProceedingsProcurement of Electricity and Natural Gas
The Utility Registrants' electric supply for its customers is primarily procured through contracts as required by their respective state commissions. The Utility Registrants procure electricity supply from various approved bidders, including Generation. RTO spot market purchases and sales are utilized to balance the utility electric load and
supply as required. Charges incurred for electric supply procured through contracts with Generation are included in Purchased power from affiliates on the Utility Registrants' Statements of Operations and Comprehensive Income. PECO's, BGE’s, and DPL's natural gas supplies are purchased from a number of suppliers for terms of up to three years. PECO, BGE, and DPL have annual firm supply and transportation contracts of 132,000137,000 mmcf, 129,000268,000 mmcf and 58,00061,000 mmcf, respectively. In addition, to supplement gas supply at times of heavy winter demands and in the event of temporary emergencies, PECO, BGE, and DPL have available storage capacity from the following sources: | | | | | | | | | | | | | | | | | | | Peak Natural Gas Sources (in mmcf) | | LNG Facility | | Propane-Air Plant | | Underground Storage Service Agreements (a) | PECO | 1,200 | | | 150 | | | 19,400 | | BGE | 1,056 | | | 550 | | | 22,000 | | DPL | 250 | | | N/A | | 3,900 | |
| | | | | | | | | | | Peak Natural Gas Sources (in mmcf) | | Liquefied Natural Gas Facility | | Propane-Air Plant | | Underground Storage Service Agreements (a) | PECO | 1,200 |
| | 150 |
| | 18,000 |
| BGE | 1,056 |
| | 550 |
| | 22,000 |
| DPL | 250 |
| | n/a |
| | 3,900 |
|
______________________(a)Natural gas from underground storage represents approximately 28%, 20%, and 33% of PECO's, BGE’s, and DPL's 2021-2022 heating season planned supplies, respectively.
| | (a) | Natural gas from underground storage represents approximately 28%, 42% and 30% of PECO's, BGE’s and DPL's 2019-2020 heating season planned supplies, respectively. |
PECO, BGE, and DPL have long-term interstate pipeline contracts and also participate in the interstate markets by releasing pipeline capacity or bundling pipeline capacity with gas for off-system sales. Off-system gas sales are low-margin direct sales of gas to wholesale suppliers of natural gas. Earnings from these activities are shared between the utilities and customers. PECO, BGE, and DPL make these sales as part of a program to balance its supply and cost of natural gas. The off-system gas sales are not material to PECO, BGE, and DPL. See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK, Commodity Price Risk (All Registrants), for additional information regarding Utility Registrants' contracts to procure electric supply and natural gas. Energy Efficiency Programs The Utility Registrants are generally allowed to recover costs associated with the energy efficiency and demand response programs they offer. Each commission approved program seeks to meet mandated electric consumption reduction targets and implement demand response measures to reduce peak demand. The programs are designed to meet standards required by each respective regulatory agency. ComEd is allowed to earn a return on its energy efficiency costs. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Capital Investment The Utility Registrants' businesses are capital intensive and require significant investments, primarily in electric transmission and distribution and natural gas transportation and distribution facilities, to ensure the adequate capacity, reliability, and efficiency of their systems. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, Liquidity and Capital Resources, for additional information regarding projected 20202022 capital expenditures. Transmission Services Under FERC’s open access transmission policy, the Utility Registrants, as owners of transmission facilities, are required to provide open access to their transmission facilities under filed tariffs at cost-based rates approved by FERC. The Utility Registrants and their affiliates are required to comply with FERC’s Standards of Conduct regulation governing the communication of non-public transmission information between the transmission owner’s employees and wholesale merchant employees. PJM is the regional grid operator and operates pursuant to FERC-approved tariffs. PJM is the transmission provider under, and the administrator of, the PJM Open Access Transmission Tariff (PJM Tariff). PJM operates the PJM energy, capacity, and other markets, and, through central dispatch, controls the day-to-day operations of the bulk power system for the region. The Utility Registrants are members of PJM and provide regional transmission service pursuant to the PJM Tariff. The Utility Registrants and the other transmission owners in PJM have turned over control
of certain of their transmission facilities to PJM, and their transmission systems are under the dispatch control of PJM. Under the PJM Tariff, transmission service is provided on a region-wide, open-access basis using the transmission facilities of the PJM transmission owners at rates based on the costs of transmission service. The Utility Registrants' transmission rates are established based on a formula that wasFERC approved by FERCformula as shown below: | | | | | | | Approval Date | ComEd | Approval DateJanuary 2008 | ComEdPECO | January 2008December 2019 | PECOBGE | December 2019April 2006 | BGEPepco | April 2006 | PepcoDPL | April 2006 | DPLACE | April 2006 | ACE | April 2006 |
Exelon’s Strategy and Outlook In 2021, the businesses remained focused on maintaining industry leading operational excellence, meeting or exceeding their financial commitments, ensuring timely recovery on investments to enable customer benefits, supporting enactment of clean energy policies, and continued commitment to corporate responsibility. Exelon’s strategy is to improve reliability and operations, enhance the customer experience, and advance clean and affordable energy choices, while ensuring ratemaking mechanisms provide the utilities fair financial returns. The Utility Registrants only invest in rate base where it provides a benefit to customers and the community by improving reliability and the service experience or otherwise meeting customer needs. The Utility Registrants make these investments at the lowest reasonable cost to customers. Exelon seeks to leverage its scale and expertise across the utilities platform through enhanced standardization and sharing of resources and best practices to achieve improved operational and financial results. Additionally, the Utility Registrants anticipate making significant future investments in smart grid technology, transmission projects, gas infrastructure, and electric system improvement projects, providing greater reliability, improved service for our customers, increased capacity to accommodate new technologies, and a stable return for the company. Management continually evaluates growth opportunities aligned with Exelon’s businesses, assets and markets leveraging Exelon’s expertise in those areas and offering sustainable returns. The Utility Registrants anticipate investing approximately $29 billion over the next four years in electric and natural gas infrastructure improvements and modernization projects, including smart grid technology, storm
hardening, advanced reliability technologies, and transmission projects, which is projected to result in an increase to current rate base of approximately $17 billion by the end of 2025. The Utility Registrants invest in rate base where beneficial to customers and the community by increasing reliability and the service experience or otherwise meeting customer needs. These investments are made at the lowest reasonable cost to customers. 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. See ITEM 1. BUSINESS — Environmental Matters and Regulation — Climate Change for additional information. Various market, financial, regulatory, legislative and operational factors could affect Exelon's success in pursuing its strategies. Exelon continues to assess infrastructure, operational, policy, and legal solutions to these issues. See ITEM 1A. RISK FACTORS for additional information. Employees The Registrants strive to create a workplace that is diverse, innovative, and safe for their employees. In order to provide the services and products that their customers expect, the Registrants must create the best teams. These teams must reflect the diversity of the communities that the Registrants serve. Therefore, the Registrants strive to attract highly qualified and diverse talent and routinely review their hiring and promotion practices to ensure they maintain equitable and bias free processes to neutralize any unconscious bias. The Registrants provide growth opportunities, competitive compensation and benefits, and a variety of training and development programs. The Registrants are committed to helping employees grow their skills and careers largely through numerous training opportunities in technical, safety and business acumen areas, mentorship programs, and continuous feedback and development discussions and evaluations. Employees are encouraged to thrive outside the workplace as well. The Registrants provide a full suite of wellness benefits targeted at supporting work-life balance, physical, mental and financial health, and industry-leading paid leave policies. The Registrants generally conduct an employee engagement survey every other year to help identify their successes and areas where they can grow. The survey results are reviewed with senior management and the Exelon Board of Directors. Diversity Metrics The following tables show diversity metrics for all employees and management as of December 31, 2021. The Exelon numbers include all subsidiaries, including Generation. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Employees | | Exelon | | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Female(a) (b) | | 7,892 | | | | | 1,505 | | | 752 | | | 753 | | | 1,269 | | | 339 | | | 143 | | | 105 | | People of Color(b) | | 9,436 | | | | | 2,464 | | | 929 | | | 1,115 | | | 1,760 | | | 873 | | | 196 | | | 139 | | Aged <30 | | 3,236 | | | | | 653 | | | 315 | | | 280 | | | 413 | | | 169 | | | 87 | | | 58 | | Aged 30-50 | | 17,008 | | | | | 3,566 | | | 1,337 | | | 1,728 | | | 2,241 | | | 748 | | | 458 | | | 361 | | Aged >50 | | 11,274 | | | | | 2,037 | | | 1,157 | | | 1,120 | | | 1,532 | | | 472 | | | 365 | | | 214 | | Total Employees(c) | | 31,518 | | | | | 6,256 | | | 2,809 | | | 3,128 | | | 4,186 | | | 1,389 | | | 910 | | | 633 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Management(d) | | Exelon | | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Female(a) (b) | | 1,242 | | | | | 219 | | | 123 | | | 116 | | | 179 | | | 49 | | | 11 | | | 19 | | People of Color(b) | | 1,233 | | | | | 308 | | | 117 | | | 146 | | | 246 | | | 113 | | | 27 | | | 20 | | Aged <30 | | 73 | | | | | 6 | | | 7 | | | 1 | | | 8 | | | 3 | | | — | | | 2 | | Aged 30-50 | | 2,857 | | | | | 469 | | | 157 | | | 256 | | | 356 | | | 105 | | | 58 | | | 44 | | Aged >50 | | 2,107 | | | | | 365 | | | 194 | | | 161 | | | 266 | | | 67 | | | 59 | | | 40 | | Within 10 years of retirement eligibility | | 2,876 | | | | | 497 | | | 239 | | | 226 | | | 368 | | | 92 | | | 74 | | | 53 | | Total Employees in Management(c) | | 5,037 | | | | | 840 | | | 358 | | | 418 | | | 630 | | | 175 | | | 117 | | | 86 | |
__________ (a)The Registrants are devoted to creating an environment that allows women to stay in the workforce, grow with the company, and move up the ranks, all with parity of pay. Exelon employs an independent third-party vendor to run regression analysis on all management positions each year. The analysis consistently shows that the Registrants have no systemic pay equity issues. (b)This is based on self-disclosed information. (c)Total employees represents the sum of the aged categories. (d)Management is defined as executive/senior level officials and managers as well as all employees who have direct reports and supervisory responsibilities. Turnover Rates As turnover is inherent, management succession planning is performed and tracked for all executives and critical key manager positions. Management frequently reviews succession planning to ensure the Registrants are prepared when positions become available. The table below shows the average turnover rate for all employees for the last three years of 2019 to 2021. The Exelon numbers include all subsidiaries, including Generation. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exelon | | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Retirement Age | | 4.27 | % | | | | 3.82 | % | | 3.47 | % | | 3.70 | % | | 4.02 | % | | 4.37 | % | | 4.10 | % | | 3.17 | % | Voluntary | | 2.98 | % | | | | 1.49 | % | | 1.76 | % | | 1.36 | % | | 2.06 | % | | 2.36 | % | | 1.11 | % | | 1.20 | % | Non-Voluntary | | 0.98 | % | | | | 0.56 | % | | 1.06 | % | | 0.94 | % | | 0.96 | % | | 1.87 | % | | 0.32 | % | | 0.68 | % |
Collective Bargaining Agreements Approximately 37% of Exelon’s employees participate in CBAs. The following table presents employee information, including information about collective bargaining agreements (CBAs),CBAs, as of December 31, 2019:2021. The Exelon numbers include all subsidiaries, including Generation. | | | | | | | | | | | | | | | | | | | | | | | | | Total Employees Covered by CBAs | | Number of CBAs | | CBAs New and Renewed in 2021(a) | | Total Employees Under CBAs New and Renewed in 2021 | Exelon | 11,770 | | | 32 | | | 8 | | | 6,476 | | | | | | | | | | ComEd | 3,478 | | | 2 | | | 2 | | | 3,478 | | PECO | 1,351 | | | 2 | | | 2 | | | 1,351 | | BGE | 1,416 | | | 1 | | | — | | | — | | PHI | 2,161 | | | 5 | | | — | | | — | | Pepco | 929 | | | 1 | | | — | | | — | | DPL | 631 | | | 2 | | | — | | | — | | ACE | 387 | | | 2 | | | — | | | — | |
__________ (a)Does not include CBAs that were extended in 2021 while negotiations are ongoing for renewal. | | | | | | | | | | | | | | | | | Total Employees | | Total Employees Covered by CBAs | | Number of CBAs | | CBAs New and Renewed in 2019(a) | | Total Employees Under CBAs New and Renewed in 2019 | Exelon | 32,713 |
| | 12,310 |
| | 32 |
| | 6 |
| | 2,593 |
| Generation | 13,082 |
| | 3,648 |
| | 20 |
| | 2 |
| | 189 |
| ComEd | 6,182 |
| | 3,462 |
| | 2 |
| | — |
| | — |
| PECO | 2,752 |
| | 1,398 |
| | 2 |
| | — |
| | — |
| BGE | 3,151 |
| | 1,436 |
| | 1 |
| | 1 |
| | 1,436 |
| PHI | 4,188 |
| | 2,268 |
| | 7 |
| | 3 |
| | 968 |
| Pepco | 1,389 |
| | 953 |
| | 1 |
| | 1 |
| | 953 |
| DPL | 936 |
| | 652 |
| | 2 |
| | — |
| | — |
| ACE | 639 |
| | 398 |
| | 2 |
| | — |
| | — |
|
20
| | (a) | Does not include CBAs that were extended in 2019 while negotiations are ongoing for renewal. |
Environmental Matters and Regulation GeneralOn February 21, 2021, Exelon's Board of Directors approved a plan to separate the Utility Registrants and Generation, creating two publicly traded companies. The separation was completed on February 1, 2022. See Note 26 — Separation of the Combined Notes to Consolidated Financial Statements for additional information. As such, the disclosures below do not include disclosures associated with Generation.
The Registrants are subject to comprehensive and complex environmental legislation regarding environmental matters byand regulation at the federal, government and various state, and local jurisdictions in which they operate their facilities. The Registrants are also subjectlevels, including requirements relating to environmental regulations administered by the EPAclimate change, air and various state and local environmental protection agencies. Federal, state and local regulation includes the authority to regulate air, water andquality, solid and hazardous waste, disposal.and impacts on species and habitats. The Exelon Board of Directors is responsible for overseeing the management of environmental matters. Exelon has a management team to address environmental compliance and strategy, including the CEO; the Senior Vice President Corporateand Chief Strategy & Chief Innovation and Sustainability Officer; the Senior Vice President, Competitive Market Policy; and the Director, Safety & Sustainability, as well as senior management of the Utility Registrants. Performance of those individuals directly involved in environmental compliance and strategy is reviewed and affects compensation as part of the annual individual performance review process. The Exelon Board of Directors has delegated to its Generation Oversight Committee and the Corporate Governance Committee the authority to oversee
Exelon’s compliance with health, environmental, and safety laws and regulations and its strategies and efforts to protect and improve the quality of the environment, including Exelon’s internal climate change and sustainability policies and programs, as discussed in further detail below. The respective Boards of the Utility Registrants oversee environmental, health, and safety issues related to these companies. Air QualityClimate Change
Air quality regulations promulgated byAs detailed below, the EPARegistrants face climate change mitigation and transition risks as well as adaptation risks. Mitigation and transition risks include changes to the energy systems as a result of new technologies, changing customer expectations and/or voluntary GHG goals, as well as local, state or federal regulatory requirements intended to reduce GHG emissions. Adaptation risk refers to risks to the Registrants' facilities or operations that may result from changes in the physical climate, such as changes to temperature, weather patterns and sea level.
Climate Change Mitigation and Transition The Registrants support comprehensive federal climate legislation that addresses the urgent need to substantially reduce national GHG emissions while providing appropriate protections for consumers, businesses, and the variouseconomy. In the absence of comprehensive federal legislation, Exelon supports EPA moving forward with meaningful regulation of GHG emissions under the Clean Air Act. The Registrants currently are subject to, and may become subject to additional, federal and/or state and local environmental agencies impose restrictions onlegislation and/or regulations addressing GHG emissions. GHG emission of particulates, sulfur dioxide (SO2), nitrogen oxides (NOx), mercury and other air pollutants and require permits for operation of emitting sources. Such permits have been obtained as needed by Exelon’s subsidiaries. However, due to its low emitting generation fleet comprised of nuclear,sources associated with the Registrants include natural gas hydroelectric, wind(methane) leakage on the natural gas systems, sulfur hexafluoride (SF6) leakage from electric transmission and solar, compliancedistribution operations, refrigerant leakage from chilling and cooling equipment, and fossil fuel combustion in motor vehicles. In addition, PECO, BGE, and DPL distribute natural gas; and consumers' use of such natural gas produces GHG emissions. Since its inception, Exelon has positioned itself as a leader in climate change mitigation. In 2020, Exelon's Scope 1 and 2 GHG emissions, as revised following the separation, were just over 5.6 million metric tons carbon dioxide equivalent using the World Resources Institute Corporate Standard Market-based accounting. Of these emissions, 551,000 metric tons are considered to be operations-driven and in more direct control of our employees and processes. The remaining 5 million metric tons, approximately 90%, are the indirect emissions associated with electric distribution and transmission system uses and losses resulting from the Utility Registrant's delivery of electricity to their customers. These system uses and losses are driven primarily by customer use and generation assets on the grid that are not under our ownership. 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, while also supporting customers and communities to achieve their clean energy and emissions goals. 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. Over the next 10 years, Exelon anticipates investing approximately $4.8 billion towards its "path to clean" goal. Exelon believes it has line of sight into solutions available today to achieve 80% of its "path to clean" goal and that achieving full net-zero operations will require some technology advancement and continued policy support. Exelon is laying the groundwork by partnering with national labs, universities and research consortia to research, develop and pilot clean technologies. The Utility Registrants are also driving customer-driven emissions reductions in their communities through some of the nation's largest energy efficiency programs. During 2022 - 2025, estimated energy efficiency investments across the Utility Registrants total $3.4 billion. These programs enable customer savings through home energy audits, lighting discounts, appliance recycling, home improvement rebates, equipment upgrade incentives and innovative programs like smart thermostats and combined heat and power programs. The electric sector plays a key role in lowering GHG emissions across much of the economy. Electrification, where feasible for transportation, buildings, and industry coupled with simultaneous decarbonization of electric generation can be a key lever for emissions reductions. To support this transition, Exelon is advocating for public policy supportive of vehicle electrification, investing in enabling infrastructure and technology, and supporting customer education and adoption. In addition, the Utility Registrants will electrify 30% of their own vehicle fleet by 2025, increasing to 50% by 2030. Exelon also continues to explore other decarbonization opportunities, supporting pilots of emerging energy technologies and clean fuels to support both operational and customer-driven emissions reductions. International Climate Change Agreements. At the international level, the United States is a party to the United Nations Framework Convention on Climate Change (UNFCCC). The Parties to the UNFCCC adopted the Paris Agreement at the 21st session of the UNFCCC Conference of the Parties (COP 21) on December 12, 2015. Under the Agreement, which became effective on November 4, 2016, the parties committed to try to limit the global average temperature increase and to develop national GHG reduction commitments. On November 4, 2020, the United States formally withdrew from the Paris Agreement, retracting its commitment to reduce domestic GHG emissions by 26%-28% by 2025 compared with 2005 levels. However, on January 20, 2021, President Biden accepted the Paris Agreement, which resulted in the United States’ formal re-entry on February 19, 2021. The Biden administration has announced its intent to pursue ambitious GHG reductions in the United States and internationally, and the United States has now set an economy-wide target of reducing its net GHG emissions by 50-52% below 2005 levels by 2030. The 2021 UNFCCC Conference of the Parties (COP26) and resulting Glasgow Climate Pact indicated important global support for the Paris Agreement and continued progress toward decarbonization. Federal Climate Change Legislation and Regulation.It is uncertain whether federal legislation to significantly reduce GHG emissions will be enacted in the near-term. On November 15, 2021, President Biden signed the Infrastructure Investment and Jobs Act's (IIJA) into law, which does include provisions intended to address climate change. Exelon anticipates pursuing opportunities under IIJA. Regulation of GHGs from Power Plants under the Clean Air Act.TheEPA’s 2015 Clean Power Plan (CPP) established regulations addressing carbon dioxide emissions from existing fossil-fired power plants under Clean Air Act does notSection 111(d). The CPP’s carbon pollution limits could be met through changes to the electric generation system, including shifting generation from higher-emitting units to lower- or zero-emitting units, as well as the development of new or expanded zero-emissions generation. In July 2019, the EPA published its final Affordable Clean Energy rule, which repealed the CPP and replaced it with less stringent emissions guidelines for existing fossil-fired power plants based on heat rate improvement measures that could be achieved within the fence line of individual plants. Exelon, together with a coalition of other electric utilities, filed a lawsuit in the U.S. Court of Appeals for the D.C. Circuit on September 6, 2019, challenging the Affordable Clean Energy rule as unlawful. This lawsuit was consolidated with separate challenges to the Affordable Clean Energy rule filed by various states, non-governmental organizations, and business coalitions. On January 19, 2021, the U.S. Court of Appeals for the D.C. Circuit held the Affordable Clean Energy Rule to be unlawful, vacated the rule, and remanded it to the EPA. On October 29, 2021, the Supreme Court granted certiorari to examine the extent of EPA's authority to regulate GHGs from power plants; a decision is expected in 2022. The EPA has indicated it will promulgate new GHG limits for existing power plants. Increased regulation of GHG emissions from power plants could increase the cost of electricity delivered or sold by The Registrants. As of February 1, 2022, the Registrants no longer directly own electric generation plants.
State Climate Change Legislation and Regulation. A number of states in which the Registrants operate have a materialstate and regional programs to reduce GHG emissions and renewable and other portfolio standards, which impact on Generation’s operations. the power sector. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONSdiscussion below for additional information regarding clean air regulationon renewable and other portfolio standards. Eleven northeast and mid-Atlantic states (Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Rhode Island, Vermont, and Virginia) currently participate in the formsRGGI, which is in the process of strengthening its requirements. The program requires most fossil fuel-fired power plants in the region to hold allowances, purchased at auction, for each ton of CO2 emissions. Non-emitting resources do not have to purchase or hold these allowances. In October 2019, the Governor of Pennsylvania issued an Executive Order directing the PA DEP to begin a rulemaking process to allow Pennsylvania to join the RGGI, with the goal of reducing carbon emissions from the electricity sector. On November 7, 2020, the PA DEP proposed its rule, which is anticipated to support Pennsylvania's participation in RGGI beginning sometime in 2022. Broader state programs impact other sectors as well, such as the District of Columbia's Clean Energy DC Omnibus Act and cross-sector GHG reduction plans, which resulted in recent requirements for Pepco to develop 5-year and 30-year decarbonization programs and strategies. Maryland has a statewide GHG reduction mandate to reduce GHG emissions by 40% no later than 2030, which it expects to meet and surpass. New Jersey accelerated its goals through Executive Order 274, which establishes an interim goal of 50% reductions below 2006 levels by 2030 and affirms its goal of achieving 80% reductions by 2050 and includes programs to drive greater amounts of electrified transportation. Finally, 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. See Note 3 — Regulatory Matters of the CSAPR, regulationCombined Notes to Consolidated Financial Statements for additional information on the Clean Energy Law. The Registrants cannot predict the nature of hazardous air pollutantsfuture regulations or how such regulations might impact future financial statements. Renewable and Clean Energy Standards. The states where Exelon operates have adopted some form of renewable or clean energy procurement requirement. These standards impose varying levels of mandates for procurement of renewable or clean electricity (the definition of which varies by state) and/or energy efficiency. These are generally expressed as a percentage of annual electric load, often increasing by year. The Utility Registrants comply with these various requirements through purchasing qualifying renewables, implementing efficiency programs, acquiring sufficient credits (e.g., RECs), paying an alternative compliance payment, and/or a combination of these compliance alternatives. The Utility Registrants are permitted to recover from coal-retail customers the costs of complying with their state RPS requirements, including the procurement of RECs or other alternative energy resources. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. Climate Change Adaptation The Registrants' facilities and oil-firedoperations are subject to the global impacts of climate change. Long-term shifts in climactic patterns, such as sustained higher temperatures and sea level rise, may present challenges for the Registrants and their service territories. Exelon believes its operations could be significantly affected by the physical risks of climate change. See ITEM 1A. RISK FACTORS, The Registrants are subject to risks associated with climate change, for additional information. The Registrants' assets undergo seasonal readiness efforts to ensure they are ready for the weather projections of the summer and winter months. The Registrants consider and review national climate assessments to inform their planning. Each of the Utility Registrants also has well establish system recovery plans and is investing in its systems to install advanced equipment and reinforce the local electric generating facilities under MATS,system, making it more weather resistant and regulation of GHG emissions.less vulnerable to anticipated storm damage. Other Environmental Regulation Water Quality Under the federal Clean Water Act, NPDES permits for discharges into waterways are required to be obtained from the EPA or from the state environmental agency to which the permit program has been delegated, and
permits must be renewed periodically. Certain of Exelon's facilities discharge stormwater and industrial wastewaterwater into waterways and are therefore subject to these regulations and operate under NPDES permits or pending applications for renewals of such permits after being granted an administrative extension. Generation is also subject to the jurisdiction of the Delaware River Basin Commission and the Susquehanna River Basin Commission, regional agencies that primarily regulate water usage.permits. Section 316(b) of the Clean Water Act
Section 316(b) requires that the cooling water intake structures at electric power plants reflect the best technology available to minimize adverse environmental impacts and is implemented through state-level NPDES permit programs. All of Generation’s power generation facilities with cooling water systems are subject to the regulations. Facilities without closed-cycle recirculating systems (e.g., cooling towers) are potentially most affected by recent changes to the regulations. For Generation, those facilities are Calvert Cliffs, Clinton, Dresden, Eddystone, Fairless Hills, FitzPatrick, Ginna, Gould Street, Handley, Mystic 7, Nine Mile Point Unit 1, Peach Bottom, Quad Cities and Salem.
On October 14, 2014, the EPA's Section 316(b) rule became effective. The rule requires that a series of studies and analyses be performed to determine the best technology available to minimize adverse impacts on aquatic life, followed by an implementation period for the selected technology. The timing of the various requirements for each facility is related to the status of its current NPDES permit and the subsequent renewal period. There is no fixed compliance schedule, as this is left to the discretion of the state permitting director.
Until the compliance requirements are determined by the applicable state permitting director on a site-specific basis for each plant, Generation cannot estimate the effect that compliance with the rule will have on the operation of its generating facilities and its future results of operations, cash flows, and financial position. Should a state permitting director determine that a facility must install cooling towers to comply with the rule, that facility’s economic viability could be called into question. However, the potential impact of the rule has been significantly reduced since the final rule does not mandate cooling towers as a national standard and sets forth technologies that are presumptively compliant, and the state permitting director is required to apply a cost-benefit test and can take into consideration site-specific factors, such as those that would make cooling towers infeasible.
New York Facilities
In July 2011, the New York Department of Environmental Conservation (DEC) issued a policy regarding the best available technology for cooling water intake structures. Through its policy, the DEC established closed-cycle cooling or its equivalent as the performance goal for all existing facilities, but also provided that the DEC will select a feasible technology whose costs are not wholly disproportionate to the environmental benefits to be gained and allows for a site-specific determination where the entrainment performance goal cannot be achieved (i.e., the requirement
most likely to support cooling towers). The Ginna, Nine Mile Point Unit 1, and Fitzpatrick power generation facilities have received renewals of their state water discharge permits and cooling towers were not required. These facilities are now engaged in the required analyses to enable the environmental agency to determine the best technology available in the next permit renewal cycles.
Salem
On July 28, 2016, the NJDEP issued a final permit for Salem that did not require the installation of cooling towers and allows Salem to continue to operate utilizing the existing cooling water system with certain required system modifications. However, the permit is being challenged by an environmental organization, and if successful, could result in additional costs forUnder Clean Water Act compliance. Potential coolingSection 404 and state laws and regulations, the Registrants may be required to obtain permits for projects involving dredge or fill activities in Waters of the United States.
Where Registrants’ facilities are required to secure a federal license or permit for activities that may result in a discharge to covered waters, they may be required to obtain a state water system modification costs could be material and could adversely impact the economic competitiveness of this facility.quality certification under Clean Water Act section 401. Solid and Hazardous Waste and Environmental Remediation CERCLA provides for immediate response and removal actions coordinated by the EPA in the event of threatened releases of hazardous substances and authorizes the EPA either to clean up sites at which hazardous substances have created actual or potential environmental hazards or to order persons responsible for the situation to do so. Under CERCLA, generators and transporters of hazardous substances, as well as past and present owners and operators of hazardous waste sites, are strictly, jointly and severally liable for the cleanup costs of hazardous waste at sites, mostmany of which are listed by the EPA on the National Priorities List (NPL). These PRPs can be ordered to perform a cleanup, can be sued for costs associated with an EPA-directed cleanup, may voluntarily settle with the EPA concerning their liability for cleanup costs, or may voluntarily begin a site investigation and site remediation under state oversight prioroversight. Most states have also enacted statutes that contain provisions substantially similar to listing onCERCLA. Such statutes apply in many states where the NPL. Various states,Registrants currently own or operate, or previously owned or operated, facilities, including Delaware, Illinois, Maryland, New Jersey, and Pennsylvania and the District of Columbia have also enacted statutes that contain provisions substantially similar to CERCLA.Columbia. In addition, RCRA governs treatment, storage and disposal of solid and hazardous wastes and cleanup of sites where such activities were conducted. Generation,The Registrants’ operations have in the Utilitypast, and may in the future, require substantial expenditures in order to comply with these Federal and state environmental laws. Under these laws, the Registrants may be 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. The Registrants and their subsidiaries are, or could become in the future, parties to proceedings initiated by the EPA, state agencies, and/or other responsible parties under CERCLA and RCRA or similar state laws with respect to a number of sites, including MGP sites or may undertake to investigate and remediate sites for which they may be subject to enforcement actions by an agency or third-party.
See Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information related to environmental matters.
Environmental Remediation
ComEd’s and PECO’s environmental liabilities primarily arise from contamination at former MGP sites. ComEd, pursuant to an ICC order, and PECO, pursuant to settlements of natural gas distribution rate cases with the PAPUC, have an on-going process to recover environmental remediation costs of the MGP sites through a provision within customer rates. BGE, ACE, Pepco, and DPL do not have material contingent liabilities relating to MGP sites. The amount to be expended in 20202022 for compliance with environmental remediation related to contamination at former MGP sites and other gas purification sites is expectedestimated to total $49be approximately $54 million which consists primarily of $45$48 million at ComEd. The Utility Registrants also have contingent liabilities for environmental remediation of non-MGP contaminants (e.g., PCBs). As of December 31, 2019,2021, the Utility Registrants have established appropriate contingent liabilities for environmental remediation requirements. The Registrants’ operations have in the past, and may in the future, require substantial expenditures in order to comply with environmental laws. Additionally, under Federal 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, Generation and the Utility Registrants may be required to make significant additional expenditures not presently determinable for other environmental remediation costs.
See Note 3 — Regulatory Matters and Note 1819 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information regarding the Registrants’ environmental matters, remediation efforts, and related impacts to the Registrants’ Consolidated Financial Statements.
Exelon has utility and generation assets, and customers, that are and will be further subject to the impactsTable of climate change. Accordingly, Exelon is engaged in a variety of initiatives to understand and mitigate these impacts, including investments in resiliency, partnering with federal, state and local governments to minimize impacts, and, importantly, advocating for public policy that reduces emissions that cause climate change. Exelon, as a producer of electricity from predominantly low- and zero-carbon generating facilities (such as nuclear, hydroelectric, natural gas, wind and solar photovoltaic), has a relatively small GHG emission profile, or carbon footprint, compared to other domestic generators of electricity (Exelon neither owns nor operates any coal-fueled generating assets). Exelon's natural gas and biomass 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. Other GHG emission sources at Exelon include natural gas (methane) leakage on the natural gas systems, sulfur hexafluoride (SF6) leakage from electric transmission and distribution operations, refrigerant leakage from chilling and cooling equipment, and fossil fuel combustion in motor vehicles. Exelon facilities and operations are subject to the global impacts of climate change and Exelon believes its operations could be significantly affected by the physical risks of climate change. See ITEM 1A. RISK FACTORS for additional information.Climate Change Regulation
Exelon is or may become subject to additional climate change regulation or legislation at the federal, regional and state levels.
International Climate Change Agreements. At the international level, the United States is a Party to the United Nations Framework Convention on Climate Change (UNFCCC). The Parties to the UNFCCC adopted the Paris Agreement at the 21st session of the UNFCCC Conference of the Parties (COP 21) on December 12, 2015, and it became effective on November 4, 2016. Under the Paris Agreement, the Parties agreed to try to limit the global average temperature increase to 2°C (3.6°F) above pre-industrial levels. In doing so, Parties developed their own national reduction commitments. The United States submitted a non-binding target of 17% below 2005 emission levels by 2020 and 26% to 28% below 2005 levels by 2025. President Trump has stated his intention to withdraw the U.S. from the Paris Agreement, but no formal action has been initiated. A withdrawal would not be effective until November 2020 at the earliest.Contents
Federal Climate Change Legislation and Regulation. It is highly unlikely that federal legislation to reduce GHG emissions will be enacted in the near-term. If such legislation is adopted, it would likely increase the value of Exelon's low-carbon fleet even though Exelon may incur costs either to further limit or offset the GHG emissions from its operations or to procure emission allowances or credits. Continued inaction could negatively impact the value of Exelon’s low-carbon fleet.
Under the Obama Administration, the EPA finalized its Clean Power Plan regulations to reduce GHG emissions from fossil fuel-fired power plants. Subsequently, the Trump Administration EPA proposed regulations on October 16, 2017 to repeal the CPP on the basis that the new Administration believed that the CPP rule went beyond the EPA's authority to establish a best system of emissions reduction (BSER) for existing power plants. On August 31, 2018, EPA proposed its Affordable Clean Energy rule to replace the CPP with revised emission guidelines based on heat rate improvement measures that could be achieved within the fence line of existing power plants. In June 2019, EPA issued a final rule that repealed the CPP, and finalized the Affordable Clean Energy rule. The Affordable Clean Energy rule is currently being litigated.
Given litigation uncertainty around the final Affordable Clean Energy rule, Exelon and Generation cannot predict the impacts of regulation of existing power plants, or individual state responses to developments related to final resolution of the Affordable Clean Energy rule, or how developments will impact their future financial statements.
Regional and State Climate Change Legislation and Regulation. A number of states in which Exelon operates have state and regional programs to reduce GHG emissions, including from the power sector. As the nation’s largest generator of carbon-free electricity, our fleet supports these efforts to produce safe, reliable electricity with minimal GHGs. Notably, nine northeast and mid-Atlantic states (Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New York, Rhode Island and Vermont) currently participate in the Regional Greenhouse Gas
Initiative (RGGI), which is in the process of strengthening its requirements. The program requires most fossil fuel-fired power plants in the region to hold allowances, purchased at auction, for each ton of CO2 emissions. Non-emitting resources do not have to purchase or hold these allowances.
In June 2019, New Jersey was accepted as a RGGI member effective January 2020. In October 2019, Governor Wolf of Pennsylvania issued an Executive Order that directed the Pennsylvania Department of Environmental Protection to begin a rulemaking process that will allow Pennsylvania to join the RGGI, with the goal of reducing carbon emissions from the electricity sector.
Many states in which Exelon subsidiaries operate also have state-specific programs to address GHGs, including from power plants. Most notable of these, besides RGGI, are through renewable and other portfolio standards. Additionally, in response to a court decision clarifying the obligations under the Global Warming Solutions Act, the Massachusetts Department of Environmental Protection in 2017 finalized regulations establishing a statewide cap on CO2 emissions from fossil fuel power plants (Massachusetts remains in RGGI as well). The effect of this new obligation and potential for market illiquidity in the early years represent a risk to Generation’s Massachusetts fossil facilities, including Medway and Mystic. At the same time, the District of Columbia is considering a plan to incorporate the cost of carbon into electricity, via consumption, as well as directly into the cost of transportation and home heating fuels. Details remain to be developed, but the specifics could have implications for Pepco’s operations.
Regardless of whether GHG regulation occurs at the local, state, or federal level, Exelon remains one of the largest, lowest-carbon electric generators in the United States, relying mainly on nuclear, natural gas, hydropower, wind, and solar. The extent that the low-carbon generating fleet will continue to be a competitive advantage for Exelon depends on resolution of the CPP and Affordable Clean Energy regulations and associated current or future litigation at the federal level, new or expanded state action on greenhouse gas emissions or direct support of clean energy technologies, including nuclear, as well as potential market reforms that value our fleet’s emission-free attributes.
Renewable and Alternative Energy Portfolio Standards
Thirty-nine states and the District of Columbia, incorporating the vast majority of Exelon operations as well as all utility operations, have adopted some form of RPS requirement. These standards impose varying levels of mandates for procurement of renewable or clean electricity (the definition of which varies by state) and/or energy efficiency. These are generally expressed as a percentage of annual electric load, often increasing by year. Exelon's utilities comply with these various requirements through purchasing qualifying renewables, implementing efficiency programs, acquiring sufficient credits (e.g., RECs), paying an alternative compliance payment, and/or a combination of these compliance alternatives. The Utility Registrants are permitted to recover from retail customers the costs of complying with their state RPS requirements, including the procurement of RECs or other alternative energy resources. New York, Illinois and New Jersey adopted standards targeted at preserving the zero-carbon attributes of certain nuclear-powered generating facilities. Generation owns multiple facilities participating in these programs within these states. Other states in which Generation and our utilities operate are considering similar programs.
See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on renewable portfolio standards.
Information about our Executive Officers as of February 11, 202025, 2022 Exelon | | | | | | | | | | | | | | | | | | | | | Name | | Age |
| Position | Position | | Period | Crane, Christopher M. | | 6163 |
| | Chief Executive Officer, Exelon; | | 2012 - Present | | | | | | | | | | | | | | | | | | | President, Exelon | | 2008 - Present | | | | | | | | Cornew, Kenneth W. | | 54 |
| | | | | | | | | | | Butler, Calvin G. | | 52 | | | Senior Executive Vice President, andExelon; Chief CommercialOperations Officer, Exelon;Exelon | | 20132021 - Present | | | | | President and CEO, Generation | | 2013 - Present | | | | | | | | Butler, Calvin G. | | 50 |
| | Senior Executive Vice President, Exelon; Chief Executive Officer, Exelon Utilities | | 2019 - Present2021 | | | | | Chief Executive Officer, BGE | | 2014 - 2019 | | | | | | | | Dominguez, Joseph | | 57 |
| | Chief Executive Officer, ComEd | | 2018 - Present | | | | | Executive Vice President, Governmental & Regulatory Affairs and Public Policy, Exelon | | 2015 - 2018 | | | | | Senior Vice President, Governmental & Regulatory Affairs and Public Policy, Exelon | | 2012 - 2015 | | | | | | | | Innocenzo, Michael A. | | 54 |
| | President and Chief Executive Officer, PECO | | 2018 - Present | | | | | Senior Vice President and Chief Operations Officer, PECO | | 2012 - 2018 | | | | | | | | Khouzami, Carim V. | | 44 |
| | Chief Executive Officer, BGE | | 2019 - Present | | | | | Senior Vice President, Chief Operating Officer, Exelon Utilities | | 2018 - 2019 | | | | | Senior Vice President, Chief Financial Officer, Exelon Utilities | | 2016 - 2018 | | | | | Senior Vice President, Chief Integration Officer, Exelon | | 2014 - 2016 | | | | | | | | Velazquez, David M. | | 60 |
| | President and Chief Executive Officer, PHI | | 2016 - Present | | | | | President and Chief Executive Officer, Pepco, DPL and ACE | | 2009 - Present | | | | | Executive Vice President, Pepco Holdings, Inc. | | 2009 - 2016 | | | | | | | | Von Hoene Jr., William A. | | 66 |
| | Senior Executive Vice President and Chief Strategy Officer, Exelon | | 2012 - Present | | | | | | | | Nigro, Joseph | | 55 |
| | Senior Executive Vice President and Chief Financial Officer, Exelon | | 2018 - Present | | | | | Executive Vice President, Exelon; Chief Executive Officer, Constellation | | 2013 - 2018 | | | | | | | | Aliabadi, Paymon | | 57 |
| | Executive Vice President and Chief Risk Officer, Exelon | | 2013 - Present | | | | | | | | Souza, Fabian E. | | 49 |
| | Senior Vice President and Corporate Controller, Exelon | | 2018 - Present | | | | | Senior Vice President and Deputy Controller, Exelon | | 2017 - 2018 | | | | | Vice President, Controller and Chief Accounting Officer, The AES Corporation | | 2015 - 2017 | | | | | Vice President, Internal Audit and Advisory Services, The AES Corporation | | 2014 - 2015 |
Generation
| | | | | | | | | Name | | Age |
| | Position | | Period | Cornew, Kenneth W. | | 54 |
| | Senior Executive Vice President and Chief Commercial Officer, Exelon; | | 2013 - Present | | | | | President and Chief Executive Officer, Generation | | 2013 - Present | | | | | | | | Pacilio, Michael J. | | 59 |
| | Executive Vice President and Chief Operating Officer, Generation | | 2015 - Present | | | | | President, Exelon Nuclear; Senior Vice President and Chief Nuclear Officer, Generation | | 2010 - 2015 | | | | | | | | Hanson, Bryan C | | 54 |
| | President and Chief Nuclear Officer, Exelon Nuclear; Senior Vice President, Generation | | 2015 - Present | | | | | | | | McHugh, James | | 48 |
| | Executive Vice President, Exelon; Chief Executive Officer, Constellation | | 2018 - Present | | | | | Senior Vice President, Portfolio Management & Strategy, Constellation | | 2016 - 2018 | | | | | Vice President, Portfolio Management, Constellation | | 2012 - 2016 | | | | | | | | Barnes, John | | 56 |
| | Senior Vice President, Generation; President, Exelon Power | | 2018 - Present | | | | | Senior Vice President, Generation, Senior Vice President and Chief Operating Officer, Exelon Power | | 2012 - 2018 | | | | | | | | Wright, Bryan P. | | 53 |
| | Senior Vice President and Chief Financial Officer, Generation | | 2013 - Present | | | | | | | | Bauer, Matthew N. | | 43 |
| | Vice President and Controller, Generation | | 2016 - Present | | | | | Vice President and Controller, BGE | | 2014 - 2016 |
ComEd
| | | | | | | | | Name | | Age |
| | Position | | Period | Dominguez, Joseph | | 57 |
| | Chief Executive Officer, ComEd | | 2018 - Present | | | | | Executive Vice President, Governmental & Regulatory Affairs and Public Policy, Exelon | | 2015 - 2018 | | | | | Senior Vice President, Governmental & Regulatory Affairs and Public Policy, Exelon | | 2012 - 2015 | | | | | | | | Donnelly, Terence R. | | 59 |
| | President and Chief Operating Officer, ComEd | | 2018 - Present | | | | | Executive Vice President and Chief Operating Officer, ComEd | | 2012 - 2018 | | | | | | | | Jones, Jeanne M. | | 40 |
| | Senior Vice President, Chief Financial Officer and Treasurer, ComEd | | 2018 - Present | | | | | Vice President, Finance, Exelon Nuclear | | 2014 - 2018 | | | | | | | | Park, Jane | | 47 |
| | Senior Vice President, Customer Operations, ComEd | | 2018 - Present | | | | | Vice President, Regulatory Policy & Strategy, ComEd | | 2016 - 2018 | | | | | Director, Business Strategy & Technology, ComEd | | 2014 - 2016 | | | | | | | | Gomez, Veronica | | 50 |
| | Senior Vice President, Regulatory and Energy Policy and General Counsel, ComEd | | 2017 - Present | | | | | Vice President and Deputy General Counsel, Litigation, Exelon | | 2012 - 2017 | | | | | | | | Washington, Melissa | | 50 |
| | Senior Vice President, Governmental and External Affairs, ComEd | | 2019 - Present | | | | | Vice President, Governmental and External Affairs, ComEd | | 2019 -2019 | | | | | Vice President, External Affairs and Large Customer Services, ComEd | | 2016 - 2019 | | | | | Vice President, Corporate Affairs, Exelon Business Services Company | | 2014 - 2016 | | | | | | | | Perez, David | | 50 |
| | Senior Vice President, Distribution Operations, ComEd | | 2019 - Present | | | | | Vice President, Transmission and Substation, ComEd | | 2016 - 2019 | | | | | Vice President, Regional Operations, ComEd | | 2010 - 2016 | | | | | | | | Kozel, Gerald J. | | 47 |
| | Vice President, Controller, ComEd | | 2013 - Present |
PECO
| | | | | | | | | | | | | | | NameGlockner, David | | Age61 |
| | Position | | Period | Innocenzo, Michael A. | | 54 |
| | President and Chief Executive Officer, PECO | | 2018 - Present | | | | | Senior Vice President, Compliance and Chief Operations Officer, PECOAudit, Exelon | | 2012 - 2018 | | | | | | | | McDonald, John | | 62 |
| | Senior Vice President and Chief Operations Officer, PECO | | 2018 - Present | | | | | Vice President, Integration, PHI | | 2016 - 2018 | | | | | Vice President, Technical Services | | 2006 - 2016 | Stefani, Robert J. | | 45 |
| | Senior Vice President, Chief Financial Officer and Treasurer, PECO | | 2018 - Present | | | | | Vice President, Corporate Development, Exelon | | 2015 - 2018 | | | | | Director, Corporate Development, Exelon | | 2012 - 2015 | | | | | | | | Murphy, Elizabeth A. | | 60 |
| | Senior Vice President, Governmental and External Affairs, PECO | | 2016 - Present | | | | | Vice President, Governmental and External Affairs, PECO | | 2012 - 2016 | | | | | | | | Webster Jr., Richard G. | | 58 |
| | Vice President, Regulatory Policy and Strategy, PECO | | 2012 - Present | | | | | | | | Williamson, Olufunmilayo | | 41 |
| | Senior Vice President, Customer Operations, PECO | | 2020 - Present | | | | | Senior Vice President, Chief Commercial RiskCompliance Officer, ExelonCitadel LLC | | 2017 - 2020 | | | | | Vice President, Commercial Risk Management, ExelonRegional Director, U.S. Securities and Exchange Commission | | 20152013 - 2017 | | | | | | | | Gay, AnthonyLittleton, Gayle E. | | 5449 |
| | Executive Vice President, and General Counsel, PECO | | 2019 - Present | | | | | Vice President, Governmental and External Affairs, PECO | | 2016 - 2019 | | | | | Associate General Counsel, Exelon | | 2010 - 20162020- Present | | | | | Partner, Jenner & Block LLP | | 2015 -2020 | Bailey, Scott A. | | 43 |
| | Vice President and Controller, PECO | | 2012 - Present |
BGE
| | | | | | | | | Name | | Age |
| | Position | | Period | Khouzami, Carim V. | | 44 |
| | Chief Executive Officer, BGE | | 2019 - Present | | | | | Senior Vice President, Chief Operating Officer, Exelon Utilities | | 2018 - 2019 | | | | | Senior Vice President, Chief Financial Officer, Exelon Utilities | | 2016 - 2018 | | | | | Senior Vice President, Chief Integration Officer, Exelon | | 2014 - 2016 | | | | | | | | Woerner, Stephen J. | | 52 |
| | President, BGE | | 2014 - Present | | | | | Chief Operating Officer, BGE | | 2012 - Present | | | | | | | | Vahos, David M. | | 47 |
| | Senior Vice President, Chief Financial Officer and Treasurer, BGE | | 2016 - Present | | | | | Vice President, Chief Financial Officer and Treasurer, BGE | | 2014 - 2016 | | | | | | | | Núñez, Alexander G. | | 48 |
| | Senior Vice President, Regulatory Affairs and Strategy, BGE | | 2020 - Present | | | | | Senior Vice President, Regulatory and External Affairs, BGE | | 2016 - 2020 | | | | | Vice President, Governmental and External Affairs, BGE | | 2013 - 2016 | | | | | | | | Case, Mark D. | | 58 |
| | Vice President, Strategy and Regulatory Affairs, BGE | | 2012 - Present | | | | | | | | Oddoye, Rodney | | 43 |
| | Senior Vice President, Governmental and External Affairs, BGE | | 2020 - Present | | | | | Vice President, Customer Operations, BGE | | 2018 - 2020 | | | | | Director, Northeast Regional Electric Operations, BGE | | 2016 - 2018 | | | | | Director, Financial Operations, BGE | | 2015 - 2016 | | | | | Manager, Distribution Operations, BGE | | 2013 - 2015 | | | | | | | | Olivier, Tamla | | 47 |
| | Senior Vice President, Customer Operations, BGE | | 2020 - Present | | | | | Senior Vice President, Constellation NewEnergy, Inc. | | 2016 - 2020 | | | | | VP, Human Resources, Exelon Business Services Company | | 2012 - 2016 | | | | | | | | Corse, John | | 59 |
| | Vice President and General Counsel, BGE | | 2018 - Present | | | | | Associate General Counsel, Exelon | | 2012 - 2018 | | | | | | | | Holmes, Andrew W. | | 51 |
| | Vice President and Controller, BGE | | 2016 - Present | | | | | Director, Generation Accounting, Exelon | | 2013 - 2016 |
PHI, Pepco, DPL and ACE
| | | | | | | | Quiniones, Gil | | 55 | | | Chief Executive Officer, ComEd | | 2021 - Present | | | | | President and Chief Executive Officer, New York Power Authority | | 2011 - 2021 | | | | | | | | NameInnocenzo, Michael A. | | Age56 |
| | PositionPresident and Chief Executive Officer, PECO | | Period2018 - Present | Velazquez, David M. | | 60 |
| Senior Vice President and Chief Operations Officer, PECO | | 2012 - 2018 | | | | | | | | Khouzami, Carim V. | | 46 | | | Chief Executive Officer, BGE | | 2019 - Present | | | | | Senior Vice President, Chief Operating Officer, Exelon Utilities | | 2018 - 2019 | | | | | Senior Vice President, Chief Financial Officer, Exelon Utilities | | 2016 - 2018 | | | | | | | | Anthony, J. Tyler | | 57 | | | President and Chief Executive Officer, PHI | | 20162021 - Present | | | | | Executive Vice President, Pepco Holdings, Inc. | | 2009 - 2016 | | | | | President and Chief Executive Officer, Pepco, DPL and ACE | | 2009 - Present | | | | | | | | Anthony, J. Tyler | | 55 |
| | Senior Vice President and Chief Operating Officer, PHI, Pepco, DPL, and ACE | | 2016 - Present2021 | | | | | | | | Nigro, Joseph | | 57 | | | Senior Executive Vice President and Chief Financial Officer, Exelon | | 2018 - Present | | | | | Executive Vice President, Exelon; Chief Executive Officer, Constellation | | 2013 - 2018 | | | | | | | | Souza, Fabian E. | | 51 | | | Senior Vice President and Corporate Controller, Exelon | | 2018 - Present | | | | | Senior Vice President and Deputy Controller, Exelon | | 2017 - 2018 | | | | | Vice President, Controller and Chief Accounting Officer, The AES Corporation | | 2015 - 2017 |
ComEd | | | | | | | | | | | | | | | | | | | | | Name | | Age | | Position | | Period | Quiniones, Gil | | 55 | | | Chief Executive Officer, ComEd | | 2021 - Present | | | | | President and Chief Executive Officer, New York Power Authority | | 2011 - 2021 | | | | | | | | Donnelly, Terence R. | | 61 | | | President and Chief Operating Officer, ComEd | | 2018 - Present | | | | | Executive Vice President and Chief Operating Officer, ComEd | | 2012 - 2018 | | | | | | | | Trpik, Joseph | | 52 | | | Interim Senior Vice President, Chief Financial Officer and Treasurer, ComEd | | 2021 - Present | | | | | Senior Vice President, Chief Financial Officer, Exelon Utilities | | 2018 - Present | | | | | Senior Vice President, Chief Financial Officer and Treasurer, ComEd | | 2009 - 2018 | | | | | | | | Rippie, E. Glenn | | 61 | | | Senior Vice President and General Counsel, ComEd | | 2022 - Present | | | | | Partner, Jenner & Block LLP | | 2019 - 2021 | | | | | Partner and Chief Financial Officer, Rooney, Rippie & Ratnaswamy, LLP | | 2010 - 2019 | | | | | | | | Washington, Melissa | | 52 | | | Senior Vice President, Customer Operations and Chief Customer Officer, ComEd | | 2021 - Present | | | | | | | | | | | | Senior Vice President, Governmental and External Affairs, ComEd | | 2019 - 2021 | | | | | Vice President, Governmental and External Affairs, ComEd | | 2019 -2019 | | | | | Vice President, External Affairs and Large Customer Services, ComEd | | 2016 - 2019 | | | | | | | | Perez, David | | 52 | | | Senior Vice President, Distribution Operations, ComEd | | 20102019 - 2016Present | | | | | Vice President, Transmission and Substation, ComEd | | 2016 - 2019 | | | | | | | | Blaise, M. Michelle | | 60 | | | Senior Vice President, Technical Services, ComEd | | 2014 - Present | | | | | | | |
PECO | | | | | | | | | | | | | | | | | | | | | Name | | Age | | Position | | Period | Innocenzo, Michael A. | | 56 | | | President and Chief Executive Officer, PECO | | 2018 - Present | | | | | Senior Vice President and Chief Operations Officer, PECO | | 2012 - 2018 | | | | | | | | McDonald, John | | 64 | | | Senior Vice President and Chief Operations Officer, PECO | | 2018 - Present | | | | | Vice President, Integration, PHI | | 2016 - 2018 | Stefani, Robert J. | | 48 | | | Senior Vice President, Chief Financial Officer and Treasurer, PECO | | 2018 - Present | | | | | Vice President, Corporate Development, Exelon | | 2015 - 2018 | | | | | | | | Murphy, Elizabeth A. | | 62 | | | Senior Vice President, Governmental and External Affairs, PECO | | 2016 - Present | | | | | | | | | | | | | | | Webster Jr., Richard G. | | 60 | | | Vice President, Regulatory Policy and Strategy, PECO | | 2012 - Present | | | | | | | | | | | | | | | Williamson, Olufunmilayo | | 43 | | | Senior Vice President, Customer Operations, PECO | | 2020 - Present | | | | | Senior Vice President, Chief Commercial Risk Officer, Exelon | | 2017 - 2020 | | | | | Vice President, Commercial Risk Management, Exelon | | 2015 - 2017 | | | | | | | | Gay, Anthony | | 56 | | | Vice President and General Counsel, PECO | | 2019 - Present | | | | | | | | | | | | Vice President, Governmental and External Affairs, PECO | | 2016 - 2019 | | | | | | | |
BGE | | | | | | | | | | | | | | | | | | | | | Name | | Age | | Position | | Period | Khouzami, Carim V. | | 46 | | | Chief Executive Officer, BGE | | 2019 - Present | | | | | Senior Vice President, Chief Operating Officer, Exelon Utilities | | 2018 - 2019 | | | | | Senior Vice President, Chief Financial Officer, Exelon Utilities | | 2016 - 2018 | | | | | | | | Dickens, Derrick | | 56 | | | Senior Vice President and Chief Operating Officer, BGE | | 2021 - Present | | | | | Senior Vice President, Customer Operations, PHI | | 2020 - 2021 | | | | | Vice President, Technical Services, BGE | | 2016 - 2020 | | | | | | | | | | | | | | | Vahos, David M. | | 49 | | | Senior Vice President, Chief Financial Officer and Treasurer, BGE | | 2016 - Present | | | | | | | | | | | | | | | Núñez, Alexander G. | | 50 | | | Senior Vice President, Governmental, External and Regulatory Affairs, BGE | | 2021 - Present | | | | | Senior Vice President, Regulatory Affairs and Strategy, BGE | | 2020 - 2021 | | | | | Senior Vice President, Regulatory and External Affairs, BGE | | 2016 - 2020 | | | | | | | | Case, Mark D. | | 60 | | | Vice President, Strategy and Regulatory Affairs, BGE | | 2012 - Present | | | | | | | | | | | | | | | Galambos, Denise | | 59 | | | Senior Vice President, Customer Operations, BGE | | 2021 - Present | | | | | Vice President, Utility Oversight, Exelon Utilities | | 2020 - 2021 | | | | | VP, Human Resources, BGE | | 2018 - 2020 | | | | | Associate General Counsel, Exelon | | 2012 - 2017 | | | | | | | | Ralph, David | | 55 | | | Vice President and General Counsel, BGE | | 2021 - Present | | | | | Associate General Counsel, BGE | | 2019 - 2021 | | | | | Assistant General Counsel, Exelon | | 2017 - 2019 | | | | | City Attorney, City of Baltimore | | 2016 - 2017 |
PHI, Pepco, DPL, and ACE | | | | | | | | | | | | | | | | | | | | | Name | | Age | | Position | | Period | Anthony, J. Tyler | | 57 | | | President and Chief Executive Officer, PHI | | 2021 - Present | | | | | Senior Vice President and Chief Operating Officer, PHI, Pepco, DPL, and ACE | | 2016 - 2021 | | | | | | | | Olivier, Tamla | | 49 | | | Senior Vice President and Chief Operating Officer, PHI, Pepco, DPL, and ACE | | 2021 - Present | | | | | Senior Vice President, Customer Operations, BGE | | 2020 - 2021 | | | | | Senior Vice President, Constellation NewEnergy, Inc. | | 2016 - 2020 | | | | | | | | Barnett, Phillip S. | | 5658 |
| | Senior Vice President, Chief Financial Officer and Treasurer, PHI, Pepco, DPL, and ACE | | 2018 - Present | | | | | Senior Vice President and Chief Financial Officer, PECO | | 2007 - 2018 | | | | | Treasurer, PECO | | 2012 - 2018 | | | | | | | | Lavinson, MelissaOddoye, Rodney | | 5045 |
| | Senior Vice President, Governmental & External Affairs, PHI, Pepco, DPL, and ACE | | 20182021 - Present | | | | | Vice President, Federal Affairs and Policy and Chief Sustainability Officer, PG&E Corporation | | 2015 - 2018 | | | | | Vice President, Federal Affairs, PG&E Corporation | | 2012 - 2015 | | | | | | | | Stark, Wendy E. | | 47 |
| | Senior Vice President, LegalGovernmental and Regulatory Strategy and General Counsel, PHI, Pepco, DPL and ACEExternal Affairs, BGE | | 20192020 - Present2021 | | | | | Vice President, Customer Operations, BGE | | 2018 - 2020 | | | | | Director, Northeast Regional Electric Operations, BGE | | 2016 - 2018 | | | | | | | | Bancroft, Anne | | 55 | | | Vice President and General Counsel, PHI Pepco DPL and ACE | | 2021 - Present | | | | | Associate General Counsel, Exelon | | 2017 - 2021 | | | | | Assistant General Counsel, Exelon | | 2010 - 2017 | | | | | | | | Bell-Izzard, Morlon | | 56 | | | Senior Vice President, Customer Operations & Chief Customer Officer, PHI | | 2021 - Present | | | | | Vice President, Customer Operations, PHI | | 2019 - 2021 | | | | | Director, Utility Performance Assessment, Exelon | | 2016 - 20182019 | | | | | Deputy General Counsel, Pepco Holdings, Inc. | | 2012 - 2016 | O'Donnell, Morgan | | 46 | | | Vice President, Regulatory Policy and Strategy, DC/MD | | 2021 - Present | McGowan, Kevin M. | | 58 |
| Director, Financial Planning and Analysis, PHI | | 2020 - 2021 | | | | | Director, Regulatory Strategy & Revenue Policy, PHI | | 2019 - 2020 | | | | | Manager, Regulatory Analysis, PHI | | 2016 - 2019 | | | | | | | | Humphrey, Marissa | | 42 | | Vice President, Regulatory Policy and Strategy, PHI, Pepco, DPL, and ACE | | 20162021 - Present | | | | | Vice President, Regulatory Affairs, Pepco Holdings, Inc. | | 2012 - 2016 | | | | | | | | Dickens, Derrick | | 55 |
| | Senior Vice President, Customer Operations, PHI | | 2020 - Present | | | | | Vice President, Technical Services, BGE | | 2016 - 2020 | | | | | Director, Advanced Meter Infrastructure, PECO | | 2012 - 2016 | | | | | | | | Aiken, Robert | | 53 |
| | Vice President and Controller, PHI, Pepco, DPL and ACE | | 2016 - Present | | | | | Vice President and Controller, Generation | | 2012 - 2016 |
| | | | | Vice President Finance, Exelon Utilities | | 2019 - 2020 | | | | | Vice President, Finance, PHI | | 2016 - 2019 | | | | | | | |
On February 21, 2021, Exelon’s Board of Directors approved a plan to separate the Utility Registrants and Generation, creating two publicly traded companies. The separation was completed on February 1, 2022. See Note 26 — Separation of the Combined Notes to Consolidated Financial Statements for additional information. As such, the risk factors discussed below do not include those associated with Generation. Each of the Registrants operates in a complex market and regulatory environment that involves significant risks, many of which are beyond that Registrant’s direct control. Such risks, which could negatively affect one or more of the Registrants’ consolidated financial statements, fall primarily under the categories below:
Risks related to market and Financial Factorsfinancial factors primarily include: the price of fuels, in particular the price of natural gas, which affects power prices,
the generation resources in the markets in which the Registrants operate,
•the demand for electricity, reliability of service, and affordability in the markets where the Utility Registrants conduct their business, •the ability of the Utility Registrants to operate their respective transmission and distribution assets, their ability to access capital markets, and the impacts on their results of on-going competition,operations due to the global outbreak (pandemic) of the 2019 novel coronavirus (COVID-19), and •emerging technologies and business models.models, including those related to climate change mitigation and transition to a low carbon economy. RegulatoryRisks related to legislative, regulatory, and Legislative Factorslegal factors primarily include changes to, and compliance with, the laws and regulations that govern:
the design of power markets,
zero emission credit programs,
•utility regulatory business model,models, regulations•environmental and other standards,
environmentalclimate policy, and
•tax policy. Operational FactorsRisks related to operational factors primarily include:
•changes in the global climate could produce extreme weather events, which could put the Registrant’s facilities at risk, and such changes could also affect the effectslevels and patterns of climate change regulation could impact the GHG emissions from the Registrant’s operations,demand for energy and related services, the safe, secure and effective operation of Generation’s nuclear facilities and the ability to effectively manage the associated decommissioning obligations,
•the ability of the Utility Registrants to maintain the reliability, resiliency, and safety of their energy delivery systems, which could affect the operating costs of the Registrants and the opinions oftheir ability to deliver energy to their customers and regulators,affect their operating costs, and the Registrants face •physical and cyber security risks for the Utility Registrants as the owner-operators of generation, transmission and distribution facilitiesfacilities.
Risks related to the separation primarilyinclude: •challenges to achieving the benefits of separation and as participants in commodities trading. •performance by Exelon and Generation under the transaction agreements, including indemnification responsibilities. There may be further risks and uncertainties that are not presently known or that are not currently believed by the Registrants to be material that could negatively affect itsthe Registrants' consolidated financial statements in the future. Risks Related to Market and Financial Factors Generation is exposed to price volatility associated with both the wholesale and retail power markets and the procurement of nuclear and fossil fuel (Exelon and Generation).
Generation is exposed to commodity price risk for the unhedged portion of its electricity generation supply portfolio. Generation’s earnings and cash flows are therefore exposed to variability of spot and forward market prices in the markets in which it operates.
Price of Fuels.The spot market price of electricity for each hour is generally determined by the marginal cost of supplying the next unit of electricity to the market during that hour. Thus, the market price of power is affected by the market price of the marginal fuel used to generate the electricity unit.
Demand and Supply.The market price for electricity is also affected by changes in the demand for electricity and the available supply of electricity. Unfavorable economic conditions, milder than normal weather, and the growth of energy efficiency and demand response programs could each depress demand. In addition, in some markets, the supply of electricity could often exceed demand during some hours of the day, resulting in loss of revenue for base-load generating plants such as Generation's nuclear plants.
Retail Competition.Generation’s retail operations compete for customers in a competitive environment, which affects the margins that Generation can earn and the volumes that it is able to serve. In periods of sustained low
natural gas and power prices and low market volatility, retail competitors can aggressively pursue market share because the barriers to entry can be low and wholesale generators (including Generation) use their retail operations to hedge generation output.
The impact of sustained low market prices or depressed demand and over-supply could be emphasized given Generation’s concentration of base-load electric generating capacity within primarily two geographic market regions, namely the Midwest and the Mid-Atlantic. These impacts could adversely affect Generation’s ability to fund regulated utility growth for the benefit of customers, reduce debt and provide attractive shareholder returns. In addition, such conditions may no longer support the continued operation of certain generating facilities, which could adversely affect Generation's financial statements primarily through accelerated depreciation and amortization expenses and one-time charges. See Note 6 — Early Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information.
Cost of Fuel. Generation depends on nuclear fuel and fossil fuels to operate most of its generating facilities. The supply markets for nuclear fuel, natural gas and oil are subject to price fluctuations, availability restrictions and counterparty default.
Market Designs. The wholesale markets vary from region to region with distinct rules, practices and procedures. Changes in these market rules, problems with rule implementation, or failure of any of these markets could adversely affect Generation’s business. In addition, a significant decrease in market participation could affect market liquidity and have a detrimental effect on market stability.
The Registrants are potentially affected by emerging technologies that could over time affect or transform the energy industry (All Registrants). SomeAdvancements in power generation technology, including commercial and residential solar generation installations and commercial micro turbine installations, are improving the cost-effectiveness of these technologies include, but are not limitedcustomer self-supply of electricity. Improvements in energy storage technology, including batteries and fuel cells, could also better position customers to further development or applications of technologies related to shale gas production, renewable energy technologies,meet their around-the-clock electricity requirements. Improvements in energy efficiency distributedof lighting, appliances, equipment and building materials will also affect energy consumption by customers. Changes in power generation, storage, and use technologies could have significant effects on customer behaviors and their energy storage devices. Suchconsumption.
These developments could affect the price of energy, levels of customer-owned generation, customer expectations, and current business models and make portions of our electric system power supply andthe Utility Registrants' transmission and/or distribution facilities obsoleteuneconomic prior to the end of their useful lives. Such technologies could also result in further declines in commodity prices or demand for delivered energy. Each of theseThese factors could affect the Registrants’ consolidated financial statements through, among other things, reduced operating revenues, increased operating and maintenance expenses, increased capital
expenditures, and potential asset impairment charges or accelerated depreciation and decommissioning expenses over shortened remaining asset useful lives. Market performance and other factors could decrease the value of NDT funds and employee benefit plan assets and could increase the related employee benefit plan obligations, which then could require significant additional funding (All Registrants). Disruptions in the capital markets and their actual or perceived effects on particular businesses and the greater economy could adversely affect the value of the investments held within Generation’s NDTs and Exelon’s employee benefit plan trusts. The Registrants have significant obligations in these areas and Exelon and Generation hold substantial assets in these trusts to meet those obligations. The asset values are subject to market fluctuations and will yield uncertain returns, which could fall below the Registrants’Exelon's projected return rates. A decline in the market value of the NDT fund investments could increase Generation’s funding requirements to decommission its nuclear plants. A decline in the market value of the pension and OPEB plan assets willwould increase the funding requirements associated with Exelon’s pension and OPEB plan obligations. Additionally, Exelon’s pension and OPEB plan liabilities are sensitive to changes in interest rates. As interest rates decrease, the liabilities increase, potentially increasing benefit costs and funding requirements. Changes in demographics, including increased numbers of retirements or changes in life expectancy assumptions or changes to Social Security or Medicare eligibility requirements could also increase the costs and funding requirements of the obligations related to the pension and OPEB plans. See Note 9 — Asset Retirement Obligations and Note 1415 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information. The Registrants could be negatively affected by unstable capital and credit markets and increased volatility in commodity markets (All Registrants). The Registrants rely on the capital markets, particularly for publicly offered debt, as well as the banking and commercial paper markets, to meet their financial commitments and short-term liquidity needs. Disruptions in the
capital and credit markets in the United States or abroad could negatively affect the Registrants’ ability to access the capital markets or draw on their respective bank revolving credit facilities. The banks may not be able to meet their funding commitments to the Registrants if they experience shortages of capital and liquidity or if they experience excessive volumes of borrowing requests within a short period of time. The inability to access capital markets or credit facilities, and longer-term disruptions in the capital and credit markets as a result of uncertainty, changing or increased regulation, reduced alternatives, or failures of significant financial institutions could result in the deferral of discretionary capital expenditures, Generation’s ability to hedge effectively its generation portfolio, changes to Generation’s hedging strategy in order to reduce collateral posting requirements, or require a reduction in dividend payments or other discretionary uses of cash. In addition, the Registrants have exposure to worldwide financial markets, including Europe, Canada, and Asia. Disruptions in these markets could reduce or restrict the Registrants’ ability to secure sufficient liquidity or secure liquidity at reasonable terms. As of December 31, 2019,2021, approximately 23%20%, 19%17%, and 18%16% of the Registrants’ available credit facilities (not including Generation's credit facilities) were with European, Canadian, and Asian banks, respectively. See Note 1617 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the credit facilities. The strength and depth of competition in energy markets depend heavily on active participation by multiple trading parties, which could be negatively affected by disruptions in the capital and credit markets and legislative and regulatory initiatives that could affect participants in commodities transactions. Reduced capital and liquidity and failures of significant institutions that participate in the energy markets could diminish the liquidity and competitiveness of energy markets that are important to the respective businesses of the Registrants. Perceived weaknesses in the competitive strength of the energy markets could lead to pressures for greater regulation of those markets or attempts to replace market structures with other mechanisms for the sale of power, including the requirement of long-term contracts.
If any of the Registrants were to experience a downgrade in its credit ratings to below investment grade or otherwise fail to satisfy the credit standards in its agreements with its counterparties or regulatory financial requirements, it would be required to provide significant amounts of collateral underthat could affect its agreements with counterpartiesliquidity and could experience higher borrowing costs (All Registrants). Generation’s business is subject to credit quality standards that could require market participants to post collateral for their obligations. If Generation were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating) or otherwise fail to satisfy the credit standards of trading counterparties, it would be required under its hedging arrangements to provide collateral in the form of letters of credit or cash, which could have a material adverse effect upon its liquidity. The amount of collateral required to be provided by Generation at any point in time depends on a variety of factors, including (1) the notional amount of the applicable hedge, (2) the nature of counterparty and related agreements, and (3) changes in power or other commodity prices. In addition, if Generation were downgraded, it could experience higher borrowing costs as a result of the downgrade. Changes in ratings methodologies by the credit rating agencies could also have a negative impact on the ratings of Generation.
Generation has project-specific financing arrangements and must meet the requirements of various agreements relating to those financings. Failure to meet those arrangements could give rise to a project-specific financing default which, if not cured or waived, could result in the specific project being required to repay the associated debt or other borrowings earlier than otherwise anticipated, and if such repayment were not made, the lenders or security holders would generally have broad remedies, including rights to foreclose against the project assets and related collateral or to force the Exelon subsidiaries in the project-specific financings to enter into bankruptcy proceedings. The impact of bankruptcy could result in the impairment of certain project assets.
The Utility Registrants' operating agreements with PJM and PECO's, BGE's, and DPL's natural gas procurement contracts contain collateral provisions that are affected by their credit rating and market prices. If certain wholesale market conditions were to exist and the Utility Registrants were to lose their investment grade credit ratings (based on their senior unsecured debt ratings), they would be required to provide collateral in the forms of letters of credit or cash, which could have a material adverse effect upon their remaining sources of liquidity. PJM collateral posting requirements will generally increase as market prices rise and decrease as market prices fall. Collateral posting requirements for PECO, BGE, and DPL, with respect to their natural gas supply contracts, will generally increase as forward market prices fall and decrease as forward market prices rise. If the Utility Registrants were downgraded, they could experience higher borrowing costs as a result of the downgrade. In addition, changes in ratings methodologies by the agencies could also have an adverse negative impact on the ratings of the Utility Registrants.
The Utility Registrants conduct their respective businesses and operate under governance models and other arrangements and procedures intended to assure that the Utility Registrants are treated as separate,
independent companies, distinct from Exelon and other Exelon subsidiaries in order to isolate the Utility Registrants from Exelon and other Exelon subsidiaries in the event of financial difficulty at Exelon or another Exelon subsidiary. These measures (commonly referred to as “ring-fencing”) could help avoid or limit a downgrade in the credit ratings of the Utility Registrants in the event of a reduction in the credit rating of Exelon. Despite these ring-fencing measures, the credit ratings of the Utility Registrants could remain linked, to some degree, to the credit ratings of Exelon. Consequently, a reduction in the credit rating of Exelon could result in a reduction of the credit rating of some or all of the Utility Registrants. A reduction in the credit rating of a Utility Registrant could have a material adverse effect on the Utility Registrant. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Liquidity and Capital Resources — Credit Matters — Market Conditions and Security Ratings for additional information regarding the potential impacts of credit downgrades on the Registrants’ cash flows. Generation’s risk management policies cannot fully eliminate the risk associated with its commodity trading activities (Exelon and Generation).
Generation’s asset-based power position as well as its power marketing, fuel procurement and other commodity trading activities expose Generation to risks of commodity price movements. Generation buys and sells energy and other products and enters into financial contracts to manage risk and hedge various positions in Generation’s power generation portfolio. Generation is exposed to volatility in financial results for unhedged positions as well as the risk of ineffective hedges. Generation attempts to manage this exposure through enforcement of established risk limits and risk management procedures. These risk limits and risk management procedures may not work as planned and cannot eliminate all risks associated with these activities. Even when its policies and procedures are followed, and decisions are made based on projections and estimates of future performance, results of operations could be diminished if the judgments and assumptions underlying those decisions prove to be incorrect. Factors, such as future prices and demand for power and other energy-related commodities, become more difficult to predict and the calculations become less reliable the further into the future estimates are made. As a result, Generation cannot predict the impact that its commodity trading activities and risk management decisions could have on its consolidated financial statements.
Financial performance and load requirements could be negatively affected if Generation is unable to effectively manage its power portfolio (Exelon and Generation).
A significant portion of Generation’s power portfolio is used to provide power under procurement contracts with the Utility Registrants and other customers. To the extent portions of the power portfolio are not needed for that purpose, Generation’s output is sold in the wholesale power markets. To the extent its power portfolio is not sufficient to meet the requirements of its customers under the related agreements, Generation must purchase power in the wholesale power markets. Generation’s financial results could be negatively affected if it is unable to cost-effectively meet the load requirements of its customers, manage its power portfolio or effectively address the changes in the wholesale power markets.
The impacts of significant economic downturns or increases in customer rates, could lead to decreased volumes delivered and increased expense for uncollectible customer balances (All Registrants). The impacts of significant economic downturns on the Utility Registrants' customers such as less demand for products and services provided by commercial and industrial customers, and the related regulatory limitations on residential service terminations for the Utility Registrants, could result in an increase in the number of uncollectible customer balances.balances and related expense. Further, increases in customer rates, including those related to increases in purchased power and natural gas prices, could result in declines in customer usage and lower revenues for the Utility Registrants that do not have decoupling mechanisms. Generation's customer-facing energy delivery activities face similar economic downturn risks, such as lower volumes sold and increased expense for uncollectible customer balances.
See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for additional information ofon the Registrants’ credit risk.
The Registrants' results were negatively affected by the impacts of COVID-19 (All Registrants).
COVID-19 has disrupted economic activity in the Registrants’ respective markets and negatively affected the Registrants’ results of operations. The estimated impact of COVID-19 to the Utility Registrants’ Net income was approximately $75 million for the year ended December 31, 2020 and was not material for the year ended December 31, 2021. The Registrants cannot predict the full extent of the impacts of COVID-19, which will depend on, among other things, the rate, and public perceptions of the effectiveness, of vaccinations and rate of resumption of business activity. In addition, any future widespread pandemic or other local or global health issue could adversely affect customer demand and the Registrants’ ability to operate their transmission and distribution assets. See Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - Executive Overview for additional information.
The Registrants could be negatively affected by the impacts of weather (All Registrants). Weather conditions directly influence the demand for electricity and natural gas and affect the price of energy commodities. Temperatures above normal levels in the summer tend to increase summer cooling electricity demand and revenues, and temperatures below normal levels in the winter tend to increase winter heating electricity and gas demand and revenues. Moderate temperatures adversely affect the usage of energy and resulting operating revenues at PECO and DPL Delaware and ACE.Delaware. Due to revenue decoupling, operating revenues from electric distribution at ComEd, BGE, Pepco, and DPL Maryland, recognize revenues at MDPSC and DCPSC-approved levels per customer, regardless of what actual distribution volumes are for a billing period andACE are not affected by actual weather with the exception of major storms. ComEd’s customer rates are adjusted to eliminate the favorable and unfavorable impacts of weather and customer usage patterns on distribution revenue.abnormal weather. Extreme weather conditions or damage resulting from storms could stress the Utility Registrants' transmission and distribution systems, communication systems, and technology, resulting in increased maintenance and capital costs and limiting each company’s ability to meet peak customer demand. First and third quarter financial results, in particular, are substantially dependent on weather conditions, and could make period comparisons less relevant. Generation’s operations are also affected by weather, which affects demand for electricityClimate change projections suggest increases to summer temperature and humidity trends, as well as operating conditions. Tomore erratic precipitation and storm patterns over the extent that weather is warmerlong-term in the summer or colderareas where the Utility Registrants have transmission and distribution assets. The frequency in the winter than assumed, Generation could require greater resources to meet its contractual commitments. Extremewhich weather conditions or stormsemerge outside the current expected climate norms could affect the availabilitycontribute to weather-related impacts discussed above.
Long-lived assets, goodwill, and other assets could become impaired (All Registrants). Long-lived assets represent the single largest asset class on the Registrants’ statements of financial position. In addition, Exelon, ComEd, and PHI have material goodwill balances. The Registrants evaluate the recoverability of the carrying value of long-lived assets to be held and used whenever events or circumstances indicating a potential impairment exist. Factors such as, but not limited to, the business climate, including current and future energy and market conditions, environmental regulation, and the condition of assets are considered. ComEd and PHI perform an assessment for possible impairment of their goodwill at least annually or more frequently if an event occurs or circumstances change that would more likely than not reduce the fair value of the reporting units below their carrying amount. Regulatory actions or changes in significant assumptions, including discount and growth rates, utility sector market performance and transactions, projected operating and capital cash flows for ComEd’s, Pepco’s, DPL’s, and ACE’s business, and the fair value of debt, could potentially result in future impairments of Exelon’s, PHI’s,ComEd's, and ComEd’sPHI’s goodwill. An impairment would require the Registrants to reduce the carrying value of the long-lived asset or goodwill to fair value through a non-cash charge to expense by the amount of the impairment. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Critical Accounting Policies and Estimates, Note 78 — Property, Plant, and Equipment, Note 1112 — Asset Impairments and Note 1213 — Intangible Assets of the Combined Notes to the Consolidated Financial Statements for additional information on long-lived asset impairments and goodwill impairments. The Registrants could incur substantial costs in the event of non-performance by third-parties under indemnification agreements, or when the Registrants have guaranteed their performance. Generation is exposed to other credit risks in the power markets that are beyond its controlperformance (All Registrants). The Registrants have entered into various agreements with counterparties that require those counterparties to reimburse a Registrant and hold it harmless against specified obligations and claims. To the extent that any of these counterparties are affected by deterioration in their creditworthiness or the agreements are otherwise determined to be unenforceable, the affected Registrant could be held responsible for the obligations. Each of the Utility
Registrants has transferred its former generation business to a third party and in each case the transferee has agreed to assume certain obligations and to indemnify the applicable Utility Registrant for such obligations. In connection with the restructurings under which ComEd, PECO, and BGE transferred their generating assets to Generation, Generation assumed certain of ComEd’s, PECO’s, and BGE's rights and obligations with respect to their former generation businesses. Further, ComEd, PECO, and BGE have entered into agreements with third parties under which the third-party agreed to indemnify ComEd, PECO, or BGE for certain obligations related to their respective former generation businesses that have been assumed by Generation as part of the restructuring. If the third-party, Generation, or the transferee of Pepco's, DPL's, or ACE’s generation facilities experienced events that reduced its creditworthiness or the indemnity arrangement became unenforceable, the applicable Utility Registrant could be liable for any existing or future claims. In addition, the Utility Registrants have residual liability under certain laws in connection with their former generation facilities. The Registrants have issued indemnities to third parties regarding environmental or other matters in connection with purchases and sales of assets, and a Registrantincluding several of the Utility Registrants in connection with Generation's absorption of their former generating assets. The Registrants could incur substantial costs to fulfill itstheir obligations under these indemnities. The Registrants have issued guarantees of the performance of third parties, which obligate the RegistrantRegistrants to perform in the event that the third parties do not perform. In the event of non-performance by those third parties, a Registrantthe Registrants could incur substantial cost to fulfill itstheir obligations under these guarantees. In the bilateral markets, Generation is exposed
Risks Related to the risk that counterparties that owe Generation money or are obligated to purchase energy or fuel from Generation, will not perform under their obligations for operational or financial reasons. In the event the counterparties to these arrangements fail to perform, Generation could be forced to purchase or sell energy or fuel in the wholesale markets at less favorable prices and incur additional losses, to the extent of amounts, if any, were already paid to the counterparties. In the spot markets, Generation is exposed to risk as a result of default sharing mechanisms that exist within certain markets, primarily RTOs and ISOs. Generation is also a party to agreements with entities in the energy sector that have experienced rating downgrades or other financial difficulties. In addition, Generation’s retail sales subject it to credit risk through competitive electricity and natural gas supply activities to serve commercial and industrial companies, governmental entities and residential customers. Retail credit risk results when customers default on their contractual obligations. This risk represents the loss that could be incurred due to the nonpayment of a customer’s account balance, as well as the loss from the resale of energy previously committed to serve the customer. Legislative, Regulatory, and LegislativeLegal Factors Federal or state legislative or regulatory actions could negatively affect the scope and functioning of the wholesale markets (Exelon and Generation).
Approximately 70% of Generation’s generating resources, which include directly owned assets and capacity obtained through long-term contracts, are located in the area encompassed by PJM. Generation’s future results of operations are impacted by (1) FERC’s and PJM's support for policies that favor the preservation of competitive wholesale power markets and recognize the value of zero-carbon electricity and resiliency and for states' energy objectives and policies (2) the absence of material changes to market structures that would limit or otherwise negatively affect Exelon or Generation. Generation could also be affected by state laws, regulations or initiatives to subsidize existing or new generation.
FERC’s requirements for market-based rate authority could pose a risk that Generation may no longer satisfy FERC’s tests for market-based rates.
The Registrants’Registrants' businesses are highly regulated and could be negatively affected by legislative and/or regulatory and legislative actions (All Registrants). Substantially allSubstantial aspects of the Registrants' businesses of the Registrants are subject to comprehensive Federal or state regulation and legislation.
Generation’s consolidated financial statements are significantly affected by its sales and purchases of commodities at market-based rates, as opposed to cost-based legislation and/or other similarly regulated rates and Federal and state regulatory and legislative developments related to emissions, climate change, capacity market mitigation, energy price information, resilience, fuel diversity and RPS. Legislative and regulatory efforts in Illinois, New York and New Jersey
to preserve the environmental attributes and reliability benefits of zero-emission nuclear-powered generating facilities through ZEC programs are or could be subject to legal and regulatory challenges and, if overturned, could result in the early retirement of certain of Generation’s nuclear plants. See Note 3 — Regulatory Matters and Note 6 — Early Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information.regulation.
The Utility Registrants' consolidated financial statements are heavily dependent on the ability of the Utility Registrants to recover their costs for the retail purchase and distribution of power and natural gas to their customers. Fundamental changes in regulations or other adverse legislative actions affecting the Registrants’ businesses would require changes in their business planning models and operations. The Registrants cannot predict when or whether legislative andor regulatory proposals could become law or what their effect willwould be on the Registrants. Changes in the Utility Registrants' respective terms and conditions of service, including their respective rates, are subject to regulatory approval proceedings and/or negotiated settlements that are at times contentious, lengthy, and subject to appeal, which lead to uncertainty as to the ultimate result and which could introduce time delays in effectuating rate changes (Exelon and the Utility(All Registrants). The Utility Registrants are required to engage in regulatory approval proceedings as a part of the process of establishing the terms and rates for their respective services. These proceedings typically involve multiple parties, including governmental bodies and officials, consumer advocacy groups, and various consumers of energy, who have differing concerns but who have the common objective of limiting rate increases or even reducing rates. Decisions are subject to appeal, potentially leading to additional uncertainty associated with the approval proceedings. The potential duration of such proceedings creates a risk that rates ultimately approved by the applicable regulatory body may not be sufficient for a Utility Registrant to recover its costs by the time the rates become effective. Established rates are also subject to subsequent prudency reviews by state regulators, whereby various portions of rates could be adjusted, subject to refund or disallowed, including recovery mechanisms for costs associated with the procurement of electricity or gas, bad debt,credit losses, MGP remediation, smart grid infrastructure, and energy efficiency and demand response programs. In certain instances, the Utility Registrants could agree to negotiated settlements related to various rate matters, customer initiatives, or franchise agreements. These settlements are subject to regulatory approval. The ultimate outcome and timing of regulatory rate proceedings have a significant effect on the ability of the Utility Registrants to recover their costs or earn an adequate return. See Note 3 — Regulatory Matters of the Combined Notes to the Consolidated Financial Statements for additional information. NRC actions could negatively affect the operations and profitability of Generation’s nuclear generating fleet (Exelon and Generation).
Regulatory risk.A change in the Atomic Energy Act or the applicable regulations or licenses could require a substantial increase in capital expenditures or could result in increased operating or decommissioning costs. Events at nuclear plants owned by others, as well as those owned by Generation, could cause the NRC to initiate such actions.
Spent nuclear fuel storage.The approval of a national repository for the storage of SNF and the timing of such facility opening, will significantly affect the costs associated with storage of SNF, and the ultimate amounts received from the DOE to reimburse Generation for these costs.
Any regulatory action relating to the timing and availability of a repository for SNF could adversely affect Generation’s ability to decommission fully its nuclear units. Generation cannot predict what, if any, fee may be established in the future for SNF disposal. See Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information on the SNF obligation.
The Registrants could be subject to higher costs and/or penalties related to mandatory reliability standards, including the likely exposure of the Utility Registrants to the results of PJM’s RTEP and NERC compliance requirements (All Registrants). The Utility Registrants as users, owners, and operators of the bulk power transmission system including Generation and the Utility Registrants, are subject to mandatory reliability standards promulgated by NERC and enforced by FERC.
PECO, BGE, and DPL, as operators of natural gas distribution systems, PECO, BGE and DPL are also subject to mandatory reliability standards of the U.S. Department of Transportation. The standards are based on the functions that need to be performed to ensure the bulk power system operates reliably and are guided by reliability and market interface principles. Compliance with or changes in the reliability standards could subject the Registrants to higher operating costs and/or increased capital expenditures. In addition, the ICC, PAPUC, MDPSC, DCPSC, DPSCDEPSC, and NJBPU impose certain distribution reliability standards on the Utility Registrants. If the Utility Registrants were found not to be in compliancenon-compliance with the Federal and Statestate mandatory reliability standards, they could be subject to remediation costs as well as sanctions, which could include substantial monetary penalties.
The Registrants could incur substantial costs to fulfill their obligations related to environmental and other matters (All Registrants). The businesses which the Registrants operate are subject to extensive environmental regulation and legislation by local, state, and Federal authorities. These laws and regulations affect the manner in which the Registrants conduct their operations and make capital expenditures including how they handle air and water emissions, hazardous and solid waste, disposal.and activities affecting surface waters, groundwater, and aquatic and other species. Violations of these emission and disposal requirements could subject the Registrants to enforcement actions, capital expenditures to bring existing facilities into compliance, additional operating costs for remediation and clean-up costs, civil penalties and exposure to third parties’ claims for alleged health or property damages, or operating restrictions to achieve compliance. In addition, the Registrants are subject to liability under these laws for the remediation costs for environmental contamination of property now or formerly owned by the Registrants and of property contaminated by hazardous substances they generate.generated or released. Remediation activities associated with MGP operations conducted by predecessor companies are one component of such costs. Also, the Registrants are currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and could be subject to additional proceedings in the future. If application of Section 316(b) of the Clean Water Act, which establishes a national requirement for reducing the adverse impacts to aquatic organisms at existing generating stations, requires the retrofitting of cooling water intake structures at Salem or other Exelon power plants, this development could result in material costs of compliance. See ITEM 1. BUSINESS — Environmental Matters and Regulation for additional information.
The Registrants could be negatively affected by federal and state RPS and/or energy conservation legislation, along with energy conservation by customers (All Registrants). Changes to current state legislation or the development of Federal legislation that requires the use of clean, renewable, and alternate fuel sources could significantly impact the Utility Registrants, especially if timely cost recovery is not allowed. Federal and state legislation mandating the implementation of energy conservation programs that require the implementation of new technologies, such as smart meters and smart grid, could increase capital expenditures and could significantly impact the Utility Registrants consolidated financial statements if timely cost recovery is not allowed. These energy conservation programs, regulated energy consumption reduction targets, and new energy consumption technologies could cause declines in customer energy consumption and lead to a decline in the Registrants' revenues. See ITEM 1. BUSINESS — Environmental Matters and Regulation — Renewable and Clean Energy Standards and "The Registrants are potentially affected by emerging technologies that could over time affect or transform the energy industry" above for additional information. The Registrants could be negatively affected by challenges to tax positions taken, tax law changes, and the inherent difficulty in quantifying potential tax effects of business decisions. (All Registrants). The Registrants are required to make judgments in order to estimate their obligations to taxing authorities. These tax obligations include income, real estate, sales and use, and employment-related taxes and ongoing appeal issues related to these tax matters. These judgments include reserves established for potential adverse outcomes regarding tax positions that have been taken that could be subject to challenge by the tax authorities. See Note 1 — Significant Accounting Policies and Note 1314 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information. The Registrants could be negatively affected by federal and state RPS and/or energy conservation legislation, along with energy conservation by customers (All Registrants).
Changes to current state legislation or the development of Federal legislation that requires the use of clean, renewable and alternate fuel sources could significantly impact Generation and the Utility Registrants, especially if timely cost recovery is not allowed for Utility Registrants. The impact could include increased costs and increased rates for customers.
Federal and state legislation mandating the implementation of energy conservation programs that require the implementation of new technologies, such as smart meters and smart grid, could increase capital expenditures and could significantly impact the Utility Registrants consolidated financial statements if timely cost recovery is not allowed. Furthermore, regulated energy consumption reduction targets and declines in customer energy consumption resulting from the implementation of new energy conservation technologies could lead to a decline in the revenues of the Registrants. See ITEM 1. BUSINESS — Environmental Regulation — Renewable and Alternative Energy Portfolio Standards for additional information.
Generation’s affiliation with the Utility Registrants, together with the presence of a substantial percentage of Generation’s physical asset base within the Utility Registrants' service territories, could increase Generation’s cost of doing business to the extent future complaints or challenges regarding the Utility Registrants' retail rates result in settlements or legislative or regulatory requirements funded in part by Generation (Exelon and Generation).
Generation has significant generating resources within the service areas of the Utility Registrants and makes significant sales to each of them. Those facts tend to cause Generation to be directly affected by developments in those markets. Government officials, legislators and advocacy groups are aware of Generation’s affiliation with the Utility Registrants and its sales to each of them. In periods of rising utility rates, particularly when driven by increased costs of energy production and supply, those officials and advocacy groups could question or challenge costs and transactions incurred by the Utility Registrants with Generation, irrespective of any previous regulatory processes or approvals underlying those transactions. These challenges could increase the time, complexity and cost of the associated regulatory proceedings, and the occurrence of such challenges could subject Generation to a level of scrutiny not faced by other unaffiliated competitors in those markets. In addition, government officials and legislators could seek ways to force Generation to contribute to efforts to mitigate potential or actual rate increases, through measures such as generation-based taxes.
The Registrants could be subject to adverse publicity and reputational risks, which make them vulnerable to negative customer perception and could lead to increased regulatory oversight or other consequences (All Registrants).
The Registrants could be the subject of public criticism. Adverse publicity of this nature could render public service commissions and other regulatory and legislative authorities less likely to view energy companies such as Exelon and its subsidiaries in a favorable light, and could cause Exelon and its subsidiaries to be susceptible to less favorable legislative and regulatory outcomes, as well as increased regulatory oversight and more stringent legislative or regulatory requirements (e.g. disallowances of costs, lower ROEs).
Legal proceedings could result in a negative outcome, which the Registrants cannot predict (All Registrants). The Registrants are involved in legal proceedings, claims, and litigation arising out of their business operations. The material ones are summarized in Note 1819 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements. Adverse outcomes in these proceedings could require significant expenditures, result in lost revenue, or restrict existing business activities. Generation’s financial performanceThe Registrants could be negatively affected bysubject to adverse publicity and reputational risks, arising from its ownershipwhich make them vulnerable to negative customer perception and operationcould lead to increased regulatory oversight or other consequences (All Registrants).
FERC has the exclusive authority to license most non-Federal hydropower projects located on navigable waterways, Federal lands or connected to the interstate electric grid. Generation cannot predict whether it will receive all the regulatory approvals for the renewed licenses of its hydroelectric facilities. If FERC does not issue new operating licenses for Generation’s hydroelectric facilities or a station cannot be operated through the end of its operating license, Generation’s results of operations
The Registrants could be adversely affected by increased depreciation rates and accelerated future decommissioning costs, since depreciation rates and decommissioning cost estimates currently include assumptions that license renewal will be received. Generation could also lose revenue and incur increased fuel and purchased power expense to meet supply commitments. In addition, conditions could be imposed as partthe subject of the license renewal process that could adversely affect operations, could require a substantial increase in capital expenditures, could result in increased operating costs orpublic criticism. Adverse publicity of this nature could render public service commissions and other regulatory and legislative authorities less likely to view energy companies in a favorable light, and could cause those companies, including the project uneconomic. Similar effects could result from a change in the Federal Power Act or the applicable regulations dueRegistrants, to events at hydroelectric facilities owned by others,be susceptible to less favorable legislative and regulatory outcomes, as well as those owned by Generation.increased regulatory oversight and more stringent legislative or regulatory requirements. Exelon and ComEd have received requests for information related to government investigations.an SEC investigation into their lobbying activities. The outcome of the investigations could have a material adverse effect on their reputation and consolidated financial statements (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 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 U.S. Attorney’s Office for the Northern District of Illinois requiring production of records of any communications with certain individuals and entities. On October 22, 2019, the SEC notified Exelon and ComEd that it has alsohad opened an investigation into their lobbying activities.activities in the state of Illinois. Exelon and ComEd have cooperated fully, including by providing additionalall information requested by the U.S. Attorney’s Office and the SEC, and intend to continue to cooperate fully and expeditiously with the U.S. Attorney’s Office and the SEC. The outcome of the U.S. Attorney’s Office and SEC investigationsSEC’s investigation cannot be predicted and could subject Exelon and ComEd to criminal or civil penalties, sanctions, or other remedial measures. Any of the foregoing, as well as the appearance of non-compliance with anti-corruption and anti-bribery laws, could have an adverse impact on Exelon’s and ComEd’s reputationreputations or relationshiprelationships with regulatory and legislative authorities, customers, and other stakeholders, as well as their consolidated financial statements. See Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements.
If ComEd violates its Deferred Prosecution Agreement announced on July 17, 2020, it could have an adverse effect on the reputation and consolidated financial statements of Exelon and ComEd (Exelon and ComEd). On July 17, 2020, ComEd entered into a Deferred Prosecution Agreement (DPA) with the U.S. Attorney’s Office for the Northern District of Illinois (USAO) to resolve the USAO’s investigation into Exelon’s and ComEd’s lobbying activities in the State of Illinois. Exelon was not made a party to the DPA and the investigation by the USAO into Exelon’s activities ended with no charges being brought against Exelon. 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, but not limited to, the following: (i) payment to the United States Treasury of $200 million; (ii) continued full cooperation with the government’s investigation; and (iii) ComEd’s adoption and maintenance of remedial measures involving compliance and reporting undertakings as specified in the DPA. If ComEd is found to have breached the terms of the DPA, the USAO may elect to prosecute, or bring a civil action against, ComEd for conduct alleged in the DPA or known to the government, which could result in fines or penalties and could have an adverse impact on Exelon’s and ComEd’s reputation or relationships with regulatory and legislative authorities, customers and other stakeholders, as well as their consolidated financial statements. See Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements. Risks Related to Operational Factors The Registrants are subject to risks associated with climate change (All Registrants). Physical plants could be placed at greaterClimate adaptation risk of damage shouldrefers to risks to the Registrants' facilities or operations that may result from changes in the globalphysical climate, produce unusual variations insuch as changes to temperature, and weather patterns resulting in more intense, frequent and extreme weather events, unprecedented levels of precipitation and a change in sea level.
The Registrants’Registrants periodically perform analyses to better understand how climate change could affect their facilities and operations. The Registrants primarily operate in the Midwest and East Coast of the United States, areas that historically have been prone to various types of severe weather events, and as such that the Registrants have well developedwell-developed response and recovery programs based on these historical events. Still disruption or failureHowever, the Registrants’ physical facilities could be placed at greater risk of electric generation, transmission or distribution systems or natural gas production, transmission, storage or distribution systemsdamage should changes in the eventglobal climate impact temperature and weather patterns, and result in more intense, frequent and extreme weather events, unprecedented levels of a hurricane, tornado precipitation, sea level rise, increased surface water temperatures, and/or other severe weather event, or otherwise, could preventeffects.
Over time, the Registrants may need to make additional investments to protect their facilities from operating their businessphysical climate-related risks. In addition, changes to the climate may impact levels and patterns of demand for energy and related services, which could affect Registrants’ operations. Over time, the Registrants may need to make additional investments to adapt to changes in operational requirements as a result of climate change. Climate mitigation and transition risks include changes to the normal course.energy systems as a result of new technologies, changing customer expectations and/or voluntary GHG goals, as well as local, state or federal regulatory requirements intended to reduce GHG emissions. The Registrants are considering waysalso periodically perform analyses of potential pathways to address the effect ofreduce power sector and economy-wide GHG emissions onto mitigate climate change. If carbonTo the extent additional GHG reduction regulation legislation and/or legislationregulation becomes effective at the Federal and/or state levels, the Registrants could incur costs either to further limit further the GHG emissions from their operations or to procure emission allowance credits for Generation’s fossil fuel-fired generation.otherwise comply with applicable requirements. See ITEM 1. BUSINESS — GlobalEnvironmental Matters and Regulation — Climate Change. Generation’s financial performance could be negativelyChange and "The Registrants are potentially affected by matters arising from its ownership and operation of nuclear facilities (Exelon and Generation).
Nuclear capacity factors.Capacity factors for nuclear generating units, significantly affect Generation’s results of operations. Lower capacity factors could decrease Generation’s revenues and increase operating costs by requiring Generation to produce additional energy from primarily its fossil facilities or purchase additional energy in the spot or forward markets in order to satisfy Generation’s obligations to committed third-party sales, including the Utility Registrants. These sources generally have higher costs than Generation incurs to produce energy from its nuclear stations.
Nuclear refueling outages.In general, refueling outages are planned to occur once every 18 to 24 months. The total number of refueling outages, along with their duration, could have a significant impact on Generation’s results of operations. When refueling outages last longer than anticipated or Generation experiences unplanned outages, capacity factors decrease, and Generation faces lower margins due to higher energy replacement costs and/or lower energy sales and higher operating and maintenance costs.
Nuclear fuel quality.The quality of nuclear fuel utilized by Generation could affect the efficiency and costs of Generation’s operations. Remediation actions could result in increased costs due to accelerated fuel amortization, increased outage costs and/or increased costs due to decreased generation capabilities.
Operational risk.Operations at any of Generation’s nuclear generation plants could degrade to the point where Generation must shut down the plant or operate at less than full capacity. If this were to happen, identifying and correcting the causes could require significant time and expense. Generation could choose to close a plant rather than incur the expense of restarting it or returning the plant to full capacity. In either event, Generation could lose revenue and incur increased fuel and purchased power expense to meet supply commitments.
For plants operated but not wholly owned by Generation, Generation could also incur liability to the co-owners. For nuclear plants not operated and not wholly owned by Generation, from which Generation receives a portion of the plants’ output, Generation’s results of operations are dependent on the operational performance of the operators and could be adversely affected by a significant event at those plants. Additionally, poor operating performance at
nuclear plants not owned by Generation could result in increased regulation and reduced public support for nuclear-fueled energy. In addition, closure of generating plants owned by others, or extended interruptions of generating plants or failure of transmission lines, could affect transmission systemsemerging technologies that could adverselyover time affect or transform the sale and delivery of electricity in markets served by Generation.
Nuclear major incident risk and insurance.The consequences of a major incident could be severe and include loss of life and property damage. Any resulting liability from a nuclear plant major incident within the United States, owned or operated by Generation or owned by others, could exceed Generation’s resources, including insurance coverage. Generation is a member of an industry mutual insurance company, NEIL, which provides property and business interruption insurance for Generation’s nuclear operations. Uninsured losses and other expenses, to the extent not recovered from insurers or the nuclear industry, could be borne by Generation. Additionally, an accident or other significant event at a nuclear plant within the United States or abroad, whether owned Generation or others, could result in increased regulation and reduced public support for nuclear-fueled energy.
As required by the Price-Anderson Act, Generation carries the maximum available amount of nuclear liability insurance, $450 million for each operating site. Claims exceeding that amount are covered through mandatory participation in a financial protection pool. In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay claims exceeding the $13.9 billion limit for a single incident.
See Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statementsenergy industry" above for additional information of nuclear insurance.
Decommissioning obligation and funding.NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in certain minimum amounts at the end of the life of the facility to decommission the facility.
Generation recognizes as a liability the present value of the estimated future costs to decommission its nuclear facilities. The estimated liability is based on assumptions in the approach and timing of decommissioning the nuclear facilities, estimation of decommissioning costs and Federal and state regulatory requirements. The costs of such decommissioning may substantially exceed such liability, as facts, circumstances or our estimates may change, including changes in the approach and timing of decommissioning activities, changes in decommissioning costs, changes in Federal or state regulatory requirements on the decommissioning of such facilities, other changes in our estimates or Generation’s ability to effectively execute on its planned decommissioning activities.
Generation makes contributions to certain trust funds of the former PECO units based on amounts being collected by PECO from its customers and remitted to Generation. While Generation, through PECO, has recourse to collect additional amounts from PECO customers (subject to certain limitations and thresholds), it has no recourse to collect additional amounts from utility customers for any of its other nuclear units if there is a shortfall of funds necessary for decommissioning. If circumstances changed such that Generation would be unable to continue to make contributions to the trust funds of the former PECO units based on amounts collected from PECO customers, or if Generation no longer had recourse to collect additional amounts from PECO customers if there was a shortfall of funds for decommissioning, the adequacy of the trust funds related to the former PECO units could be negatively affected.
Should the expected value of the NDT fund for any former ComEd unit fall below the amount of the expected decommissioning obligation for that unit, the accounting to offset decommissioning-related activities in the Consolidated Statement of Operations and Comprehensive Income for that unit would be discontinued, the decommissioning-related activities would be recognized in the Consolidated Statements of Operations and Comprehensive Income and the adverse impact to Exelon’s and Generation’s financial statements could be material. Any changes to the PECO regulatory agreements could impact Exelon’s and Generation’s ability to offset decommissioning-related activities within the Consolidated Statement of Operations and Comprehensive Income, and the impact to Exelon’s and Generation’s financial statements could be material.
Forecasting trust fund investment earnings and costs to decommission nuclear generating stations requires significant judgment, and actual results could differ significantly from current estimates. If the investments held by Generation’s NDTs are not sufficient to fund the decommissioning of Generation’s nuclear units, Generation could be required to take steps, such as providing financial guarantees through letters of credit or parent company guarantees or making additional contributions to the trusts, which could be significant, to ensure that the trusts are adequately funded and that current and future NRC minimum funding requirements are met.
See Note 9 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information.
The Utility Registrants' operating costs are affected by their ability to maintain the availability and reliability of their delivery and operational systems (Exelon and the Utility(All Registrants). Failures of the equipment or facilities used in the Utility Registrants' delivery systems could interrupt the electric transmission and electric and natural gas delivery, which could result in a loss of revenues and an increase in maintenance and capital expenditures. Equipment or facilities failures can be due to a number of factors, including natural causes such as weather or information systems failure. Specifically, if the implementation of advanced metering infrastructure,AMI, smart grid, or other technologies in the Utility Registrants' service territory fail to perform as intended or are not successfully integrated with billing and other information systems, or if any of the financial, accounting, or other data processing systems fail or have other significant shortcomings, the Utility Registrants' financial results could be negatively impacted. In addition, dependence upon automated systems could further increase the risk that operational system flaws or internal and/or external tampering or manipulation of those systems will result in losses that are difficult to detect. Regulated utilities, which are required to provide service to all customers within their service territory, have generally been afforded liability protections against claims by customers relating to failure of service. Under Illinois law, however, ComEd could be required to pay damages to its customers in some circumstances involving extended outages affecting large numbers of its customers, which could be material. The Registrants are subject to physical security and cybersecurity risks (All Registrants). The Registrants face physical security and cybersecurity risks. Threat sources continue to seek to exploit potential vulnerabilities in the electric and natural gas utility industry, associated with protection of sensitive and confidential information, grid infrastructure, and other energy infrastructures, and suchthese attacks and disruptions, both physical and cyber, are becoming increasingly sophisticated and dynamic. Continued implementation of advanced digital technologies increases the potentially unfavorable impacts of such attacks. A security breach of the Registrants' physical assets or information systems or those of the Registrants their 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 hashave directly experienced a material breach or disruption to its network or information systems or our service 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 of the Registrants 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. The Registrants’ employees, contractors, customers, and the general public could be exposed to a risk of injury due to the nature of the energy industry (All Registrants). Employees and contractors throughout the organization work in, and customers and the general public could be exposed to, potentially dangerous environments near the Registrants’ operations. As a result, employees, contractors, customers, and the general public are at some risk for serious injury, including loss of life. These risks include nuclear accidents, dam failure, gas explosions, pole strikes, and electric contact cases.
Natural disasters, war, acts and threats of terrorism, pandemic, and other significant events could negatively impact the Registrants' results of operations, their ability to raise capital and their future growth (All Registrants). Generation’s fleet of power plants and theThe Utility Registrants' distribution and transmission infrastructures could be affected by natural disasters and extreme weather events, which could result in increased costs, including supply chain costs. An extreme weather event within the Utility Registrants’ service areas can also directly affect their capital assets, causing disruption in service to customers due to downed wires and poles or damage to other operating equipment. Natural disasters and other significant events increase the risk to Generation that the NRC or other regulatory or legislative bodies could change the laws or regulations governing, among other things, operations, maintenance, licensed lives, decommissioning, SNF storage, insurance, emergency planning, security and environmental and radiological matters. In addition, natural disasters could affect the availability of a secure and economical supply of water in some locations, which is essential for Generation’s continued operation, particularly the cooling of generating units.
The impact that potential terrorist attacks could have on the industry and on Exelonthe Registrants is uncertain. The Registrants face a risk that their operations would be direct targets or indirect casualties of an act of terror. Any retaliatory military strikes or sustained military campaign could affect their operations in unpredictable ways, such as changes in insurance markets and disruptions of fuel supplies and markets, particularly oil. Furthermore, these catastrophic events could compromise the physical or cybersecurity of Exelon’sthe Registrants' facilities, which could adversely affect Exelon’sthe Registrants' ability to manage its businesstheir businesses effectively. Instability in the financial markets as a result of terrorism, war, natural disasters, pandemic, credit crises, recession, or other factors also could result in a decline in energy consumption or interruption of fuel or the supply chain. In addition, the implementation of security guidelines and measures has resulted in and is expected to continue to result in increased costs. The Registrants could be significantly affected by the outbreak of a pandemic. Exelon has plans in place to respond to a pandemic. However, depending on the severity of a pandemic and the resulting impacts to workforce and other resource availability, the ability to operate Exelon's generating and transmission and distribution assets could be adversely affected. See "The Registrants' results were negatively affected by the impacts of COVID-19" above for additional information. In addition, Exelon maintains a level of insurance coverage consistent with industry practices against property, casualty and cybersecurity losses subject to unforeseen occurrences or catastrophic events that could damage or destroy assets or interrupt operations. However, there can be no assurance that the amount of insurance will be adequate to address such property and casualty losses. The Registrants’ businesses are capital intensive, and their assets could require significant expenditures to maintain and are subject to operational failure, which could result in potential liability (All Registrants). The Utility Registrants’ businesses are capital intensive and require significant investments by Generation in electric generating facilities and by the Utility Registrants in transmission and distribution infrastructure projects. Equipment, even if maintained in accordance with good utility practices, is subject to operational failure, including events that are beyond the Utility Registrants’ control, and could require significant expenditures to operate efficiently. The Registrants consolidated financial statements could be negatively affected if they were unable to effectively manage their capital projects or raise the necessary capital.
See ITEM 1. BUSINESS7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Liquidity and Capital Resources for additional information regarding the Registrants’ potential future capital expenditures. The Utility Registrants' respective ability to deliver electricity, their operating costs, and their capital expenditures could be negatively impacted by transmission congestion and failures of neighboring transmission systems (Exelon and the Utility(All Registrants). Demand for electricity within the Utility Registrants' service areas could stress available transmission capacity requiring alternative routing or curtailment of electricity usage. Also, insufficient availability of electric supply to meet customer demand could jeopardize the Utility Registrants' ability to comply with reliability standards and strain customer and regulatory agency relationships. As with all utilities, potential concerns over transmission capacity or generation facility retirements could result in PJM or FERC requiring the Utility Registrants to upgrade or expand their respective transmission systems through additional capital expenditures.
PJM’s systems and operations are designed to ensure the reliable operation of the transmission grid and prevent the operations of one utility from having an adverse impact on the operations of the other utilities. However, service interruptions at other utilities may cause interruptions in the Utility Registrants’ service areas. The Registrants consolidated financial statementsRegistrants' performance could be negatively affected if they fail to attract and retain an appropriately qualified workforce (All Registrants). Certain events, such as the separation transaction, an employee strike, loss of employees, loss of contract resources due to a major event, and an aging workforce without appropriate replacements, could lead to operating challenges and increased costs for the Registrants. The challenges include lack of resources, loss of knowledge and a lengthy time period associated with skill development. In this case, costs, including costs for contractors to replace employees, productivity costs, and safety costs, could arise. The Registrants are particularly affected due to the specialized knowledge required of the technical and support employees for their generation, transmission and distribution operations. The Registrants could make acquisitions or investments in new business initiatives and new markets, which may not be successful or achieve the intended financial results (All Registrants). Generation could continue to pursue growth in its existing businesses and markets and further diversification across the competitive energy value chain. This could include investment opportunities in renewables, development of natural gas generation, nuclear advisory or operating services for third parties, distributed generation, potential expansion of the existing wholesale gas businesses and entry into LNG. Such initiatives could involve significant risks and uncertainties, including distraction of management from current operations, inadequate return on capital, and unidentified issues not discovered during diligence performed prior to launching an initiative or entering a market. Additionally, it is possible that FERC, state public utility commissions or others could impose certain other restrictions on such transactions. All of these factors could result in higher costs or lower revenues than expected, resulting in lower than planned returns on investment.
The Utility Registrants face risks associated with their regulatory-mandated initiatives, such as smart grids and utility of the future. These risks include, but are not limited to, cost recovery, regulatory concerns, cybersecurity, and obsolescence of technology. Such initiatives may not be successful. Risks Related to the Separation (Exelon) The separation may not achieve some or all of the benefits anticipated by Exelon and, following the separation, Exelon's common stock price may underperform relative to Exelon's expectations. By separating the Utility Registrants and Generation, Exelon created two publicly traded companies with the resources necessary to best serve customers and sustain long-term investment and operating excellence. The separate companies are expected to create value by having the strategic flexibility to focus on their unique customer, market and community priorities. However, the separation may not provide such results on the scope or scale that Exelon anticipates, and Exelon may not realize or achieve the anticipated cost savings throughbenefits of the cost management efforts (All Registrants).separation. Failure to do so could have a material adverse effect on Exelon's financial statements and its common stock price. In connection with the separation into two public companies, Exelon and Generation will indemnify each other for certain liabilities. If Exelon is required to pay under these indemnities to Generation, Exelon's financial results could be negatively impacted. The Registrants’ future financial performanceGeneration indemnities may not be sufficient to hold Exelon harmless from the full amount of liabilities for which Generation will be allocated responsibility, and level of profitability is dependent,Generation may not be able to satisfy its indemnification obligations in part, on various cost reduction initiatives. The Registrants may encounter challenges in executing these cost reduction initiatives and not achieve the intended cost savings.
Pursuant to the separation agreement and certain other agreements between Exelon and Generation, each party will agree to indemnify the other for certain liabilities, in each case for uncapped amounts. Indemnities that Exelon may be required to provide Generation are not subject to any cap, may be significant and could negatively impact its business. Third parties could also seek to hold Exelon responsible for any of the liabilities that Generation has agreed to retain. Any amounts Exelon is required to pay pursuant to these indemnification obligations and other liabilities could require Exelon to divert cash that would otherwise have been used in furtherance of its operating business. Further, the indemnities from Generation for Exelon's benefit may not be sufficient to protect Exelon against the full amount of such liabilities, and Generation may not be able to fully satisfy its indemnification obligations. Moreover, even if Exelon ultimately succeeds in recovering from Generation any amounts for which Exelon is held liable, Exelon may be temporarily required to bear these losses. Each of these risks could negatively affect Exelon's business, results of operations and financial condition. | | | | | | ITEM 1B. | UNRESOLVED STAFF COMMENTS |
All Registrants None.
Generation The following table presents Generation’s interests in net electric generating capacity by station at December 31, 2019:2021: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Station(a) | | Location | | No. of Units | | Percent Owned(b) | | Primary Fuel Type | | Primary Dispatch Type(c) | | Net Generation Capacity (MW)(d) | | Midwest | | | | | | | | | | | | | | Braidwood | | Braidwood, IL | | 2 | | | | | Uranium | | Base-load | | 2,386 | | | Byron | | Byron, IL | | 2 | | | | | Uranium | | Base-load | | 2,347 | | (e) | LaSalle | | Seneca, IL | | 2 | | | | | Uranium | | Base-load | | 2,320 | | | Dresden | | Morris, IL | | 2 | | | | | Uranium | | Base-load | | 1,845 | | (e) | Quad Cities | | Cordova, IL | | 2 | | | 75 | | | Uranium | | Base-load | | 1,403 | | (f) | Clinton | | Clinton, IL | | 1 | | | | | Uranium | | Base-load | | 1,080 | | | Michigan Wind 2 | | Sanilac Co., MI | | 50 | | | 51 | | (g) | Wind | | Intermittent | | 46 | | (f) | Beebe | | Gratiot Co., MI | | 34 | | | 51 | | (g) | Wind | | Intermittent | | 42 | | (f) | Michigan Wind 1 | | Huron Co., MI | | 46 | | | 51 | | (g) | Wind | | Intermittent | | 35 | | (f) | Harvest 2 | | Huron Co., MI | | 33 | | | 51 | | (g) | Wind | | Intermittent | | 30 | | (f) | Harvest | | Huron Co., MI | | 32 | | | 51 | | (g) | Wind | | Intermittent | | 27 | | (f) | Beebe 1B | | Gratiot Co., MI | | 21 | | | 51 | | (g) | Wind | | Intermittent | | 26 | | (f) | Blue Breezes | | Faribault Co., MN | | 2 | | | | | Wind | | Intermittent | | 3 | | | CP Windfarm | | Faribault Co., MN | | 2 | | | 51 | | (g) | Wind | | Intermittent | | 2 | | (f) | Southeast Chicago | | Chicago, IL | | 8 | | | | | Gas | | Peaking | | 296 | | (h) | Clinton Battery Storage | | Blanchester, OH | | 1 | | | | | Energy Storage | | Peaking | | 10 | | | Total Midwest | | | | | | | | | | | | 11,898 | | | | | | | | | | | | | | | | | Mid-Atlantic | | | | | | | | | | | | | | Limerick | | Sanatoga, PA | | 2 | | | | | Uranium | | Base-load | | 2,317 | | | Calvert Cliffs | | Lusby, MD | | 2 | | | | | Uranium | | Base-load | | 1,789 | | | Peach Bottom | | Delta, PA | | 2 | | | 50 | | | Uranium | | Base-load | | 1,324 | | (f) | Salem | | Lower Alloways Creek Township, NJ | | 2 | | | 42.59 | | | Uranium | | Base-load | | 995 | | (f) | Conowingo | | Darlington, MD | | 11 | | | | | Hydroelectric | | Base-load | | 572 | | | Criterion | | Oakland, MD | | 28 | | | 51 | | (g) | Wind | | Intermittent | | 36 | | (f) | Fair Wind | | Garrett County, MD | | 12 | | | | | Wind | | Intermittent | | 30 | | | Fourmile Ridge | | Garrett County, MD | | 16 | | | 51 | | (g) | Wind | | Intermittent | | 20 | | (f) | Solar Horizons | | Emmitsburg, MD | | 1 | | | 51 | | (g) | Solar | | Intermittent | | 16 | | (f) | Solar New Jersey 3 | | Middle Township, NJ | | 4 | | | 51 | | (g) | Solar | | Intermittent | | 2 | | (f) | Muddy Run | | Drumore, PA | | 8 | | | | | Hydroelectric | | Intermediate | | 1,070 | | | Eddystone 3, 4 | | Eddystone, PA | | 2 | | | | | Oil/Gas | | Peaking | | 760 | | | Perryman | | Aberdeen, MD | | 5 | | | | | Oil/Gas | | Peaking | | 404 | | | Croydon | | West Bristol, PA | | 8 | | | | | Oil | | Peaking | | 391 | | | Handsome Lake | | Kennerdell, PA | | 5 | | | | | Gas | | Peaking | | 268 | | |
| | | | | | | | | | | | | Station(a) | Location | No. of Units | Percent Owned(b) | | Primary Fuel Type | Primary Dispatch Type(c) | Net Generation Capacity (MW)(d) | | Midwest | | Braidwood | Braidwood, IL | 2 |
| | | Uranium | Base-load | 2,386 |
| | Byron | Byron, IL | 2 |
| | | Uranium | Base-load | 2,347 |
| | LaSalle | Seneca, IL | 2 |
| | | Uranium | Base-load | 2,320 |
| | Dresden | Morris, IL | 2 |
| | | Uranium | Base-load | 1,845 |
| | Quad Cities | Cordova, IL | 2 |
| 75 |
| | Uranium | Base-load | 1,403 |
| (e) | Clinton | Clinton, IL | 1 |
| | | Uranium | Base-load | 1,069 |
| | Michigan Wind 2 | Sanilac Co., MI | 50 |
| 51 |
| (g) | Wind | Base-load | 46 |
| (e) | Beebe | Gratiot Co., MI | 34 |
| 51 |
| (g) | Wind | Base-load | 42 |
| (e) | Michigan Wind 1 | Huron Co., MI | 46 |
| 51 |
| (g) | Wind | Base-load | 35 |
| (e) | Harvest 2 | Huron Co., MI | 33 |
| 51 |
| (g) | Wind | Base-load | 30 |
| (e) | Harvest | Huron Co., MI | 32 |
| 51 |
| (g) | Wind | Base-load | 27 |
| (e) | Beebe 1B | Gratiot Co., MI | 21 |
| 51 |
| (g) | Wind | Base-load | 26 |
| (e) | Ewington | Jackson Co., MN | 10 |
| 99 |
| | Wind | Base-load | 20 |
| (e) | City Solar | Chicago, IL | 1 |
| | | Solar | Base-load | 9 |
| | Solar Ohio | Toledo, OH | 2 |
| | | Solar | Base-load | 4 |
| | Blue Breezes | Faribault Co., MN | 2 |
| | | Wind | Base-load | 3 |
| | CP Windfarm | Faribault Co., MN | 2 |
| 51 |
| (g) | Wind | Base-load | 2 |
| (e) | Southeast Chicago | Chicago, IL | 8 |
| | | Gas | Peaking | 296 |
| (k) | Clinton Battery Storage | Blanchester, OH | 1 |
| | | Energy Storage | Peaking | 10 |
| | Total Midwest | 11,920 |
| | | | | | | | | | | Mid-Atlantic | | Limerick | Sanatoga, PA | 2 |
| | | Uranium | Base-load | 2,317 |
| | Peach Bottom | Delta, PA | 2 |
| 50 |
| | Uranium | Base-load | 1,324 |
| (e) | Salem | Lower Alloways Creek Township, NJ | 2 |
| 42.59 |
| | Uranium | Base-load | 998 |
| (e) | Calvert Cliffs | Lusby, MD | 2 |
| 50.01 |
| (f) | Uranium | Base-load | 895 |
| (e) | Conowingo | Darlington, MD | 11 |
| | | Hydroelectric | Base-load | 572 |
| | Criterion | Oakland, MD | 28 |
| 51 |
| (g) | Wind | Base-load | 36 |
| (e) | Fair Wind | Garrett County, MD | 12 |
| | | Wind | Base-load | 30 |
| | Solar MC | Various, MD | 41 |
| | | Solar | Base-load | 39 |
| | Fourmile Ridge | Garrett County, MD | 16 |
| 51 |
| (g) | Wind | Base-load | 20 |
| (e) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Station(a) | | Location | | No. of Units | | Percent Owned(b) | | Primary Fuel Type | | Primary Dispatch Type(c) | | Net Generation Capacity (MW)(d) | | Richmond | | Philadelphia, PA | | 2 | | | | | Oil | | Peaking | | 98 | | | Philadelphia Road | | Baltimore, MD | | 4 | | | | | Oil | | Peaking | | 61 | | | Eddystone | | Eddystone, PA | | 4 | | | | | Oil | | Peaking | | 60 | | | Delaware | | Philadelphia, PA | | 4 | | | | | Oil | | Peaking | | 56 | | | Southwark | | Philadelphia, PA | | 4 | | | | | Oil | | Peaking | | 52 | | | Falls | | Morrisville, PA | | 3 | | | | | Oil | | Peaking | | 51 | | | Moser | | Lower Pottsgrove Twp., PA | | 3 | | | | | Oil | | Peaking | | 51 | | | Chester | | Chester, PA | | 3 | | | | | Oil | | Peaking | | 39 | | | Schuylkill | | Philadelphia, PA | | 2 | | | | | Oil | | Peaking | | 30 | | | Salem | | Lower Alloways Creek Township, NJ | | 1 | | | 42.59 | | | Oil | | Peaking | | 16 | | (f) | Total Mid-Atlantic | | | | | | | | | | | | 10,508 | | | | | | | | | | | | | | | | | ERCOT | | | | | | | | | | | | | | Whitetail | | Webb County, TX | | 57 | | | 51 | | (g) | Wind | | Intermittent | | 47 | | (f) | Sendero | | Jim Hogg and Zapata County, TX | | 39 | | | 51 | | (g) | Wind | | Intermittent | | 40 | | (f) | Colorado Bend II | | Wharton, TX | | 3 | | | | | Gas | | Intermediate | | 1,143 | | | Wolf Hollow II | | Granbury, TX | | 3 | | | | | Gas | | Intermediate | | 1,115 | | | Handley 3 | | Fort Worth, TX | | 1 | | | | | Gas | | Intermediate | | 395 | | | Handley 4, 5 | | Fort Worth, TX | | 2 | | | | | Gas | | Peaking | | 870 | | | Total ERCOT | | | | | | | | | | | | 3,610 | | | | | | | | | | | | | | | | | New York | | | | | | | | | | | | | | Nine Mile Point | | Scriba, NY | | 2 | | | | (i) | Uranium | | Base-load | | 1,675 | | (f) | FitzPatrick | | Scriba, NY | | 1 | | | | | Uranium | | Base-load | | 842 | | | Ginna | | Ontario, NY | | 1 | | | | | Uranium | | Base-load | | 576 | | | Total New York | | | | | | | | | | | | 3,093 | | | | | | | | | | | | | | | | | Other | | | | | | | | | | | | | | Antelope Valley | | Lancaster, CA | | 1 | | | | | Solar | | Intermittent | | 242 | | | Bluestem | | Beaver County, OK | | 60 | | | 51 | | (g)(j) | Wind | | Intermittent | | 101 | | (f) | Shooting Star | | Kiowa County, KS | | 65 | | | 51 | | (g) | Wind | | Intermittent | | 53 | | (f) | Sacramento PV Energy | | Sacramento, CA | | 4 | | | 51 | | (g) | Solar | | Intermittent | | 30 | | (f) | Bluegrass Ridge | | King City, MO | | 27 | | | 51 | | (g) | Wind | | Intermittent | | 29 | | (f) |
| | | | | | | | | | | | | Station(a) | Location | No. of Units | Percent Owned(b) | | Primary Fuel Type | Primary Dispatch Type(c) | Net Generation Capacity (MW)(d) | | Solar New Jersey 1 | Various, NJ | 5 |
| | | Solar | Base-load | 18 |
| | Solar New Jersey 2 | Various, NJ | 2 |
| | | Solar | Base-load | 11 |
| | Solar Horizons | Emmitsburg, MD | 1 |
| 51 |
| (g) | Solar | Base-load | 8 |
| (e) | Solar Maryland | Various, MD | 11 |
| | | Solar | Base-load | 8 |
| | Solar Maryland 2 | Various, MD | 3 |
| | | Solar | Base-load | 8 |
| | JBAB Solar | District of Columbia | 4 |
| | | Solar | Base-load | 7 |
| | Gateway Solar | Berlin, MD | 1 |
| | | Solar | Base-load | 7 |
| | Constellation New Energy | Gaithersburg, MD | 3 |
| | | Solar | Base-load | 6 |
| | Solar Federal | Trenton, NJ | 1 |
| | | Solar | Base-load | 5 |
| | Solar New Jersey 3 | Middle Township, NJ | 5 |
| 51 |
| (g) | Solar | Base-load | 1 |
| (e) | Solar DC | District of Columbia | 1 |
| | | Solar | Base-load | 1 |
| | Muddy Run | Drumore, PA | 8 |
| | | Hydroelectric | Intermediate | 1,070 |
| | Eddystone 3, 4 | Eddystone, PA | 2 |
| | | Oil/Gas | Peaking | 760 |
| | Perryman | Aberdeen, MD | 5 |
| | | Oil/Gas | Peaking | 404 |
| | Croydon | West Bristol, PA | 8 |
| | | Oil | Peaking | 391 |
| | Handsome Lake | Kennerdell, PA | 5 |
| | | Gas | Peaking | 268 |
| | Notch Cliff | Baltimore, MD | 8 |
| | | Gas | Peaking | 117 |
| (j) | Westport | Baltimore, MD | 1 |
| | | Gas | Peaking | 116 |
| (j) | Richmond | Philadelphia, PA | 2 |
| | | Oil | Peaking | 98 |
| | Philadelphia Road | Baltimore, MD | 4 |
| | | Oil | Peaking | 61 |
| | Eddystone | Eddystone, PA | 4 |
| | | Oil | Peaking | 60 |
| | Fairless Hills | Fairless Hills, PA | 2 |
| | | Landfill Gas | Peaking | 60 |
| (j) | Delaware | Philadelphia, PA | 4 |
| | | Oil | Peaking | 56 |
| | Southwark | Philadelphia, PA | 4 |
| | | Oil | Peaking | 52 |
| | Falls | Morrisville, PA | 3 |
| | | Oil | Peaking | 51 |
| | Moser | Lower PottsgroveTwp., PA | 3 |
| | | Oil | Peaking | 51 |
| | Chester | Chester, PA | 3 |
| | | Oil | Peaking | 39 |
| | Schuylkill | Philadelphia, PA | 2 |
| | | Oil | Peaking | 30 |
| | Salem | Lower Alloways Creek Township, NJ | 1 |
| 42.59 |
| | Oil | Peaking | 16 |
| (e) | Pennsbury | Morrisville, PA | 2 |
| | | Landfill Gas | Peaking | 4 |
| (e) | Total Mid-Atlantic | 10,015 |
| | | | | | | | | | | ERCOT | | Whitetail | Webb County, TX | 57 |
| 51 |
| (g) | Wind | Base-load | 46 |
| (e) | Sendero | Jim Hogg and Zapata County, TX | 39 |
| 51 |
| (g) | Wind | Base-load | 40 |
| (e) |
| | | | | | | | | | | | | Station(a) | Location | No. of Units | Percent Owned(b) | | Primary Fuel Type | Primary Dispatch Type(c) | Net Generation Capacity (MW)(d) | | Constellation Solar Texas | Various, TX | 11 |
| | | Solar | Base-load | 13 |
| | Colorado Bend II | Wharton, TX | 3 |
| | | Gas | Intermediate | 1,140 |
| | Wolf Hollow II | Granbury, TX | 3 |
| | | Gas | Intermediate | 1,115 |
| | Handley 3 | Fort Worth, TX | 1 |
| | | Gas | Intermediate | 395 |
| | Handley 4, 5 | Fort Worth, TX | 2 |
| | | Gas | Peaking | 870 |
| | Total ERCOT | 3,619 |
| | | | | | | | | | | New York | | Nine Mile Point | Scriba, NY | 2 |
| 50.01 |
| (f) | Uranium | Base-load | 838 |
| (e) | FitzPatrick | Scriba, NY | 1 |
| | | Uranium | Base-load | 842 |
| | Ginna | Ontario, NY | 1 |
| 50.01 |
| (f) | Uranium | Base-load | 288 |
| (e) | Solar New York | Bethlehem, NY | 1 |
| | | Solar | Base-load | 3 |
| | Total New York | 1,971 |
| | | | | | | | | | | Other | | Antelope Valley | Lancaster, CA | 1 |
| | | Solar | Base-load | 242 |
| | Bluestem | Beaver County, OK | 60 |
| 51 |
| (g)(h) | Wind | Base-load | 101 |
| (e) | Shooting Star | Kiowa County, KS | 65 |
| 51 |
| (g) | Wind | Base-load | 53 |
| (e) | Albany Green Energy | Albany, GA | 1 |
| 99 |
| (i) | Biomass | Base-load | 53 |
| | Solar Arizona | Various, AZ | 127 |
| | | Solar | Base-load | 46 |
| | Bluegrass Ridge | King City, MO | 27 |
| 51 |
| (g) | Wind | Base-load | 29 |
| (e) | California PV Energy 2 | Various, CA | 90 |
| | | Solar | Base-load | 28 |
| | Conception | Barnard, MO | 24 |
| 51 |
| (g) | Wind | Base-load | 26 |
| (e) | Cow Branch | Rock Port, MO | 24 |
| 51 |
| (g) | Wind | Base-load | 26 |
| (e) | Solar Arizona 2 | Various, AZ | 56 |
| | | Solar | Base-load | 34 |
| | California PV Energy | Various, CA | 53 |
| | | Solar | Base-load | 21 |
| | Mountain Home | Glenns Ferry, ID | 20 |
| 51 |
| (g) | Wind | Base-load | 21 |
| (e) | High Mesa | Elmore Co., ID | 19 |
| 51 |
| (g) | Wind | Base-load | 20 |
| (e) | Echo 1 | Echo, OR | 21 |
| 50.49 |
| (g) | Wind | Base-load | 17 |
| (e) | Sacramento PV Energy | Sacramento, CA | 4 |
| 51 |
| (g) | Solar | Base-load | 15 |
| (e) | Cassia | Buhl, ID | 14 |
| 51 |
| (g) | Wind | Base-load | 15 |
| (e) | Wildcat | Lovington, NM | 13 |
| 51 |
| (g) | Wind | Base-load | 14 |
| (e) | Echo 2 | Echo, OR | 10 |
| 51 |
| (g) | Wind | Base-load | 10 |
| (e) | High Plains | Panhandle, TX | 8 |
| 99.5 |
| | Wind | Base-load | 10 |
| (e) | Solar Georgia 2 | Various, GA | 8 |
| | | Solar | Base-load | 10 |
| | Tuana Springs | Hagerman, ID | 8 |
| 51 |
| (g) | Wind | Base-load | 9 |
| (e) | Solar Georgia | Various, GA | 10 |
| | | Solar | Base-load | 8 |
| | Greensburg | Greensburg, KS | 10 |
| 51 |
| (g) | Wind | Base-load | 7 |
| (e) | Solar Massachusetts | Various, MA | 10 |
| | | Solar | Base-load | 7 |
| | Outback Solar | Christmas Valley, OR | 1 |
| | | Solar | Base-load | 6 |
| | Echo 3 | Echo, OR | 6 |
| 50.49 |
| (g) | Wind | Base-load | 5 |
| (e) |
| | Station(a) | Location | No. of Units | Percent Owned(b) | | Primary Fuel Type | Primary Dispatch Type(c) | Net Generation Capacity (MW)(d) | | Station(a) | | Location | | No. of Units | | Percent Owned(b) | | Primary Fuel Type | | Primary Dispatch Type(c) | | Net Generation Capacity (MW)(d) | | Holyoke Solar | Various, MA | 2 |
| | | Solar | Base-load | 5 |
| | | Conception | | Conception | | Barnard, MO | | 24 | | | 51 | | (g) | Wind | | Intermittent | | 26 | | (f) | Cow Branch | | Cow Branch | | Rock Port, MO | | 24 | | | 51 | | (g) | Wind | | Intermittent | | 26 | | (f) | Mountain Home | | Mountain Home | | Glenns Ferry, ID | | 20 | | | 51 | | (g) | Wind | | Intermittent | | 21 | | (f) | High Mesa | | High Mesa | | Elmore Co., ID | | 19 | | | 51 | | (g) | Wind | | Intermittent | | 20 | | (f) | Echo 1 | | Echo 1 | | Echo, OR | | 21 | | | 50.49 | | (g) | Wind | | Intermittent | | 17 | | (f) | Cassia | | Cassia | | Buhl, ID | | 14 | | | 51 | | (g) | Wind | | Intermittent | | 15 | | (f) | Wildcat | | Wildcat | | Lovington, NM | | 13 | | | 51 | | (g) | Wind | | Intermittent | | 14 | | (f) | Echo 2 | | Echo 2 | | Echo, OR | | 10 | | | 51 | | (g) | Wind | | Intermittent | | 10 | | (f) | Tuana Springs | | Tuana Springs | | Hagerman, ID | | 8 | | | 51 | | (g) | Wind | | Intermittent | | 9 | | (f) | Greensburg | | Greensburg | | Greensburg, KS | | 10 | | | 51 | | (g) | Wind | | Intermittent | | 6 | | (f) | Echo 3 | | Echo 3 | | Echo, OR | | 6 | | | 50.49 | | (g) | Wind | | Intermittent | | 5 | | (f) | Three Mile Canyon | Boardman, OR | 6 |
| 51 |
| (g) | Wind | Base-load | 5 |
| (e) | Three Mile Canyon | | Boardman, OR | | 6 | | | 51 | | (g) | Wind | | Intermittent | | 5 | | (f) | Loess Hills | Rock Port, MO | 4 |
| | | Wind | Base-load | 5 |
| | Loess Hills | | Rock Port, MO | | 4 | | | Wind | | Intermittent | | 5 | | | California PV Energy 3 | Various, CA | 19 |
| | | Solar | Base-load | 6 |
| | | Mohave Sunrise Solar | Fort Mohave, AZ | 1 |
| | | Solar | Base-load | 5 |
| | | Denver Airport Solar | Denver, CO | 1 |
| 51 |
| (g) | Solar | Base-load | 2 |
| (e) | Denver Airport Solar | | Denver, CO | | 1 | | | 51 | | (g) | Solar | | Intermittent | | 4 | | (f) | Solar Net Metering | Uxbridge, MA | 1 |
| | | Solar | Base-load | 2 |
| | | Solar Connecticut | Various, CT | 1 |
| | | Solar | Base-load | 1 |
| | | Mystic 8, 9 | Charlestown, MA | 6 |
| | | Gas | Intermediate | 1,417 |
| | Mystic 8, 9 | | Charlestown, MA | | 6 | | | Gas | | Intermediate | | 1,417 | | (e) | Hillabee | Alexander City, AL | 3 |
| | | Gas | Intermediate | 753 |
| | Hillabee | | Alexander City, AL | | 3 | | | Gas | | Intermediate | | 753 | | | Mystic 7 | Charlestown, MA | 1 |
| | | Oil/Gas | Intermediate | 542 |
| (j) | | Wyman 4 | Yarmouth, ME | 1 |
| 5.9 |
| | Oil | Intermediate | 35 |
| (e) | Wyman 4 | | Yarmouth, ME | | 1 | | | 5.9 | | | Oil | | Intermediate | | 34 | | (f) | West Medway II | | West Medway II | | West Medway, MA | | 2 | | | Oil/Gas | | Peaking | | 189 | | | West Medway | | West Medway | | West Medway, MA | | 3 | | | Oil | | Peaking | | 124 | | | Grand Prairie | Alberta, Canada | 1 |
| | | Gas | Peaking | 105 |
| | Grand Prairie | | Alberta, Canada | | 1 | | | Gas | | Peaking | | 105 | | | West Medway | West Medway, MA | 3 |
| | | Oil | Peaking | 123 |
| | | West Medway II | West Medway, MA | 2 |
| | | Oil/Gas | Peaking | 190 |
| | | Framingham | Framingham, MA | 3 |
| | | Oil | Peaking | 31 |
| | Framingham | | Framingham, MA | | 3 | | | Oil | | Peaking | | 31 | | | Mystic Jet | Charlestown, MA | 1 |
| | | Oil | Peaking | 9 |
| (j) | | Total Other | Total Other | 4,069 |
| | Total Other | | 3,291 | | | Total | Total | 31,594 |
| | Total | | 32,400 | | |
__________ | | (a) | All nuclear stations are boiling water reactors except Braidwood, Byron, Calvert Cliffs, Ginna, and Salem, which are pressurized water reactors. |
| | (b) | 100%, unless otherwise indicated. |
| | (c) | Base-load units are plants that normally operate to take all or part of the minimum continuous load of a system and, consequently, produce electricity at an essentially constant rate. Intermediate units are plants that normally operate to take load of a system during the daytime higher load hours and, consequently, produce electricity by cycling on and off daily. Peaking units consist of lower-efficiency, quick response steam units, gas turbines and diesels normally used during the maximum load periods. |
| | (d) | For nuclear stations, capacity reflects the annual mean rating. Fossil stations reflect a summer rating. Wind and solar facilities reflect name plate capacity. |
| | (e) | Net generation capacity is stated at proportionate ownership share. |
| | (f) | Reflects Generation’s interest in CENG, a joint venture with EDF. See ITEM 1. — BUSINESS — Exelon Generation Company, LLC — Nuclear Facilities for additional information. |
| | (g) | Reflects the prior sale of 49% of EGRP to a third party. See Note 22 — Variable Interest Entities of the Combined Notes to Consolidated Financial Statements for additional information. |
| | (h) | EGRP owns 100% of the Class A membership interests and a tax equity investor owns 100% of the Class B membership interests of the entity that owns the Bluestem generating assets. |
| | (i) | Generation directly owns a 50% interest in the Albany Green Energy station and an additional 49% through the consolidation of a Variable Interest Entity. |
| | (j) | Generation has plans to retire and cease generation operations at certain plants in 2020 and 2021. |
| | (k) | Generation has deactivated the site and is evaluating for potential return of service or retirement in 2020. |
(a)All nuclear stations are boiling water reactors except Braidwood, Byron, Calvert Cliffs, Ginna, and Salem, which are pressurized water reactors. (b)100%, unless otherwise indicated. (c)Base-load units are plants that normally operate to take all or part of the minimum continuous load of a system and, consequently, produce electricity at an essentially constant rate. Intermittent units are plants with output controlled by the natural variability of the energy resource rather than dispatched based on system requirements. Intermediate units are plants that normally operate to take load of a system during the daytime higher load hours and, consequently, produce electricity by cycling on and off daily. Peaking units consist of lower-efficiency, quick response steam units, gas turbines and diesels normally used during the maximum load periods. (d)For nuclear stations, capacity reflects the annual mean rating. Fossil stations and wind and solar facilities reflect a summer rating. (e)On August 9, 2020, Generation announced it would permanently cease generation operations at Byron and Dresden nuclear facilities in 2021 and Mystic Unit 8 and 9 in 2024. On September 15, 2021, Generation reversed its previous decision to retire Byron and Dresden. See Note 7 — Early Plant Retirements of the Combined Notes to the Consolidated Financial Statements for additional information. (f)Net generation capacity is stated at proportionate ownership share. (g)Reflects the prior sale of 49% of CRP to a third party. See Note 23 — Variable Interest Entities of the Combined Notes to Consolidated Financial Statements for additional information. (h)Generation has deactivated the site and is evaluating for potential return of service or retirement beyond 2023. (i)Generation wholly owns Nine Mile Point Unit 1 and has an 82% undivided ownership interest in Nine Mile Point Unit 2. (j)CRP owns 100% of the Class A membership interests and a tax equity investor owns 100% of the Class B membership interests of the entity that owns the Bluestem generating assets. The net generation capability available for operation at any time may be less due to regulatory restrictions, transmission congestion, fuel restrictions, efficiency of cooling facilities, level of water supplies, or generating
units being temporarily out of service for inspection, maintenance, refueling, repairs, or modifications required by regulatory authorities. Generation maintains property insurance against loss or damage to its principal plants and properties by fire or other perils, subject to certain exceptions. For additional information regarding nuclear insurance of generating
facilities, see ITEM 1. BUSINESS — Exelon Generation Company, LLC.Generation. For its insured losses, Generation is self-insured to the extent that any losses are within the policy deductible or exceed the amount of insurance maintained. Any such losses could have a material adverse effect inon Generation’s consolidated financial condition or results of operations. The Utility Registrants
The Utility Registrants The Utility Registrants' electric substations and a portion of their transmission rights are located on property that they own. A significant portion of their electric transmission and distribution facilities are located above or underneath highways, streets, other public places, or property that others own. The Utility Registrants believe that they have satisfactory rights to use those places or property in the form of permits, grants, easements, licenses, and franchise rights; however, they have not necessarily undertaken to examine the underlying title to the land upon which the rights rest. Transmission and Distribution The Utility Registrants’ high voltage electric transmission lines owned and in service at December 31, 20192021 were as follows: | | Voltage | | Circuit Miles | | Voltage | Circuit Miles | (Volts) | | ComEd | PECO | | BGE | | Pepco | | DPL | | ACE | | (Volts) | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE | 765,000 | | 90 | — | | — | | — | | — | | — | | 765,000 | 90 | | — | | — | | — | | — | | — | 500,000(a) | | — | 188 | (a) | 216 | | 109 | | 16 | (a) | — | (a) | 500,000(a) | — | | 188 | | 216 | | 109 | | 16 | | — | 345,000 | | 2,716 | — | | — | | — | | — | | — | | 345,000 | 2,676 | | — | | — | | — | | — | | — | 230,000 | | — | 549 | | 358 | | 769 | | 472 | | 274 | | 230,000 | — | | 550 | | 358 | | 770 | | 472 | | 274 | 138,000 | | 2,224 | 135 | | 55 | | 50 | | 586 | | 209 | | 138,000 | 2,246 | | 135 | | 55 | | 61 | | 586 | | 214 | 115,000 | | — | | 705 | | 25 | | — | | — | | 115,000 | — | | — | | 700 | | 25 | | — | | — | 69,000 | | — | 177 | | — | | — | | 569 | | 661 | | 69,000 | — | | 177 | | — | | — | | 567 | | 667 |
___________ | | (a) | In addition, PECO, DPL, and ACE have an ownership interest located in Delaware and New Jersey. See Note 8 - Jointly Owned Electric Utility Plant - for additional information. |
(a) In addition, PECO, DPL, and ACE have an ownership interest located in Delaware and New Jersey. See Note 9 - Jointly Owned Electric Utility Plant of the Combined Notes to the Consolidated Financial Statements for additional information. The Utility Registrant’sRegistrants' electric distribution system includes the following number of circuit miles of overhead and underground lines: | | Circuit Miles | | ComEd | PECO | BGE | Pepco | DPL | ACE | Circuit Miles | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE | Overhead | | 35,385 | 12,964 | 9,176 | 4,104 | 6,010 | 7,350 | Overhead | 35,387 | | 12,981 | | 9,164 | | 4,127 | | 6,006 | | 7,364 | Underground | | 31,799 | 9,417 | 17,489 | 6,993 | 6,316 | 2,942 | Underground | 32,498 | | 9,555 | | 17,796 | | 7,162 | | 6,427 | | 2,951 |
Gas The following table presents PECO’s, BGE’s, and DPL’s natural gas pipeline miles at December 31, 2019:2021: | | | | | | | | | | | | | | | | | | | PECO | | BGE | | DPL | Transmission(a) | 9 | | 152 | | 8 | Distribution | 6,956 | | 7,482 | | 2,166 | Service piping | 6,479 | | 6,407 | | 1,473 | Total | 13,444 | | 14,041 | | 3,647 |
| | | | | | | PECO | BGE | DPL | | Transmission | 9 | 161 | 8 | (a) | Distribution | 6,932 | 7,386 | 2,114 | | Service piping | 6,414 | 6,345 | 1,447 | | Total | 13,355 | 13,892 | 3,569 | |
___________ | | (a) | DPL has a 10% undivided interest in approximately 8 miles of natural gas transmission mains located in Delaware which are used by DPL for its natural gas operations and by 90% owner for distribution of natural gas to its electric generating facilities. |
(a) DPL has a 10% undivided interest in approximately 8 miles of natural gas transmission mains located in Delaware which are used by DPL for its natural gas operations and by 90% owner for distribution of natural gas to its electric generating facilities.
The following table presents PECO’s, BGE’s, and DPL’s natural gas facilities: | | | | | | | | | | | | | | | | | | | | | | | | Registrant | Facility | | Location | | Storage Capacity (mmcf) | | Send-out or Peaking Capacity (mmcf/day) | PECO | LNG Facility | | West Conshohocken, PA | | 1,200 | | 160 | PECO | Propane Air Plant | | Chester, PA | | 105 | | 25 | BGE | LNG Facility | | Baltimore, MD | | 1,056 | | 332 | BGE | Propane Air Plant | | Baltimore, MD | | 550 | | 85 | DPL | LNG Facility | | Wilmington, DE | | 250 | | 25 |
PECO, BGE, and DPL also own 30, 32,30, and 10 natural gas city gate stations and direct pipeline customer delivery points at various locations throughout their gas service territory, respectively. First Mortgage and Insurance The principal properties of ComEd, PECO, PEPCO, DPL, and ACE are subject to the lien of their respective Mortgages under which their respective First Mortgage Bonds are issued. See Note 1617 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.
The Utility Registrants maintain property insurance against loss or damage to their properties by fire or other perils, subject to certain exceptions. For their insured losses, the Utility Registrants are self-insured to the extent that any losses are within the policy deductible or exceed the amount of insurance maintained. Any such losses could have a material adverse effect in the consolidated financial condition or results of operations of the Utility Registrants.
Exelon Security Measures The Registrants have initiated and work to maintain security measures. On a continuing basis, the Registrants evaluate enhanced security measures at certain critical locations, enhanced response and recovery plans, long-term design changes, and redundancy measures. Additionally, the energy industry has strategic relationships with governmental authorities to ensure that emergency plans are in place and critical infrastructure vulnerabilities are addressed in order to maintain the reliability of the country’s energy systems.
All Registrants 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 Note 3 — Regulatory Matters and Note 1819 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements. Such descriptions are incorporated herein by these references.
| | | | | | ITEM 4. | MINE SAFETY DISCLOSURES |
All Registrants
Not Applicable to the Registrants.
PART II (Dollars in millions except per share data, unless otherwise noted) | | | | | | ITEM 5. | MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES |
Exelon Exelon’s common stock is listed on the Nasdaq (trading symbol: EXC). As of January 31, 2020,2022, there were 974,319,565980,136,968 shares of common stock outstanding and approximately 95,06485,423 record holders of common stock. Stock Performance Graph The performance graph below illustrates a five-year comparison of cumulative total returns based on an initial investment of $100 in Exelon common stock, as compared with the S&P 500 Stock Index and the S&P Utility Index, for the period 20152017 through 2019.2021. This performance chart assumes: •$100 invested on December 31, 20142016 in Exelon common stock, the S&P 500 Stock Index, and the S&P Utility Index; and •All dividends are reinvested.
| | | | | | | | Value of Investment at December 31, | | 2014 | 2015 | 2016 | 2017 | 2018 | 2019 | Exelon Corporation | $100 | $77.83 | $103.37 | $118.92 | $140.72 | $146.74 | S&P 500 | $100 | $101.38 | $113.51 | $138.29 | $132.23 | $173.86 | S&P Utilities | $100 | $95.15 | $110.65 | $124.05 | $129.14 | $163.17 |
Generation
As of January 31, 2020, Exelon indirectly held the entire membership interest in Generation. | | | | | | | | | | | | | | | | | | | | | Value of Investment at December 31, | | 2016 | 2017 | 2018 | 2019 | 2020 | 2021 | Exelon Corporation | $100 | $115.05 | $136.13 | $141.96 | $136.44 | $192.94 | S&P 500 | $100 | $121.83 | $116.49 | $153.17 | $181.35 | $233.41 | S&P Utilities | $100 | $112.11 | $116.71 | $147.46 | $148.18 | $174.36 |
ComEd As of January 31, 2020,2022, there were 127,021,349127,021,391 outstanding shares of common stock, $12.50 par value, of ComEd, of which 127,002,904 shares were indirectly held by Exelon. At January 31, 2020,2022, in addition to Exelon, there were 296285 record holders of ComEd common stock. There is no established market for shares of the common stock of ComEd. PECO As of January 31, 2020,2022, there were 170,478,507 outstanding shares of common stock, without par value, of PECO, all of which were indirectly held by Exelon.
BGE As of January 31, 2020,2022, there were 1,000 outstanding shares of common stock, without par value, of BGE, all of which were indirectly held by Exelon. PHI As of January 31, 2020,2022, Exelon indirectly held the entire membership interest in PHI. Pepco As of January 31, 2020,2022, there were 100 outstanding shares of common stock, $0.01 par value, of Pepco, all of which were indirectly held by Exelon. DPL As of January 31, 2020,2022, there were 1,000 outstanding shares of common stock, $2.25 par value, of DPL, all of which were indirectly held by Exelon. ACE As of January 31, 2020,2022, there were 8,546,017 outstanding shares of common stock, $3.00 par value, of ACE, all of which were indirectly held by Exelon. All Registrants Dividends Under applicable Federal law, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE can pay dividends only from retained, undistributed or current earnings. A significant loss recorded at, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL, or ACE may limit the dividends that these companies can distribute to Exelon. ComEd has agreed in connection with a financing arranged through ComEd Financing III that ComEd will not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debt securities issued to ComEd Financing III; (2) it defaults on its guarantee of the payment of distributions on the preferred trust securities of ComEd Financing III; or (3) an event of default occurs under the Indenture under which the subordinated debt securities are issued. No such event has occurred.
PECO has agreed in connection with financings arranged through PEC L.P. and PECO Trust IV that PECO will not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debentures which were issued to PEC L.P. or PECO Trust IV; (2) it defaults on its guarantee of the payment of distributions on the Series D Preferred Securities of PEC L.P. or the preferred trust securities of PECO Trust IV; or (3) an event of default occurs under the Indenture under which the subordinated debentures are issued. No such event has occurred. BGE is subject to restrictions established by the MDPSC that prohibit BGE from paying a dividend on its common shares if (a) after the dividend payment, BGE’s equity ratio would be below 48% as calculated pursuant to the MDPSC’s ratemaking precedents or (b) BGE’s senior unsecured credit rating is rated by two of the three major credit rating agencies below investment grade. No such event has occurred. Pepco is subject to certain dividend restrictions established by settlements approved in Maryland and the District of Columbia. Pepco is prohibited from paying a dividend on its common shares if (a) after the dividend payment, Pepco's equity ratio would be below 48% as equity levels are calculated under the ratemaking precedents of the MDPSC and DCPSC or (b) Pepco’s senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. No such event has occurred. DPL is subject to certain dividend restrictions established by settlements approved in Delaware and Maryland. DPL is prohibited from paying a dividend on its common shares if (a) after the dividend payment, DPL's equity ratio would be below 48% as equity levels are calculated under the ratemaking precedents of the DPSCDEPSC and MDPSC or (b) DPL’s
senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. No such event has occurred. ACE is subject to certain dividend restrictions established by settlements approved in New Jersey. ACE is prohibited from paying a dividend on its common shares if (a) after the dividend payment, ACE's equity ratio would be below 48% as equity levels are calculated under the ratemaking precedents of the NJBPU or (b) ACE's senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. ACE is also subject to a dividend restriction which requires ACE to obtain the prior approval of the NJBPU before dividends can be paid if its equity as a percent of its total capitalization, excluding securitization debt, falls below 30%. No such events have occurred. Exelon’s Board of Directors approved an updated dividend policy providing an increase of 5% each year for the period covering 2018 through 2020, beginning with the March 2018 dividend.2022. The 2022 quarterly dividend will be $0.3375 per share. At December 31, 2019,2021, Exelon had retained earnings of $16,267 million, including Generation’s undistributed earnings of $3,950$16,942 million, ComEd’s retained earnings of $1,517$1,691 million consisting of retained earnings appropriated for future dividends of $3,156$3,330 million, partially offset by $1,639 million of unappropriated accumulated deficits, PECO’s retained earnings of $1,412$1,684 million, BGE’s retained earnings of $1,776$1,995 million, and PHI's undistributed losses of $10$210 million. The following table sets forth Exelon’s quarterly cash dividends per share paid during 20192021 and 2018:2020: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2021 | | 2020 | (per share) | Fourth Quarter | | Third Quarter | | Second Quarter | | First Quarter | | Fourth Quarter | | Third Quarter | | Second Quarter | | First Quarter | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exelon | $ | 0.3825 | | | $ | 0.3825 | | | $ | 0.3825 | | | $ | 0.3825 | | | $ | 0.3825 | | | $ | 0.3825 | | | $ | 0.3825 | | | $ | 0.3825 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2019 | | 2018 | (per share) | Fourth Quarter | | Third Quarter | | Second Quarter | | First Quarter | | Fourth Quarter | | Third Quarter | | Second Quarter | | First Quarter | Exelon | $ | 0.363 |
| | $ | 0.363 |
| | $ | 0.363 |
| | $ | 0.363 |
| | $ | 0.345 |
| | $ | 0.345 |
| | $ | 0.345 |
| | $ | 0.345 |
|
The following table sets forth Generation's and PHI's quarterly distributions and ComEd’s, PECO’s, BGE's, Pepco's, DPL's, and ACE's quarterly common dividend payments: | | | 2019 | | 2018 | | 2021 | | 2020 | (in millions) | 4th Quarter | | 3rd Quarter | | 2nd Quarter | | 1st Quarter | | 4th Quarter | | 3rd Quarter | | 2nd Quarter | | 1st Quarter | (in millions) | 4th Quarter | | 3rd Quarter | | 2nd Quarter | | 1st Quarter | | 4th Quarter | | 3rd Quarter | | 2nd Quarter | | 1st Quarter | Generation | $ | 225 |
| | $ | 225 |
| | $ | 224 |
| | $ | 225 |
| | $ | 313 |
| | $ | 311 |
| | $ | 189 |
| | $ | 188 |
| | | ComEd | 128 |
| | 126 |
| | 127 |
| | 127 |
| | 114 |
| | 116 |
| | 115 |
| | 114 |
| ComEd | 127 | | | 127 | | | 126 | | | 127 | | | 126 | | | 124 | | | 124 | | | 125 | | PECO | 90 |
| | 88 |
| | 90 |
| | 90 |
| | 6 |
| | 7 |
| | 6 |
| | 287 |
| PECO | 85 | | | 85 | | | 84 | | | 85 | | | 85 | | | 85 | | | 85 | | | 85 | | BGE | 55 |
| | 57 |
| | 56 |
| | 56 |
| | 52 |
| | 52 |
| | 53 |
| | 52 |
| BGE | 73 | | | 73 | | | 72 | | | 74 | | | 60 | | | 62 | | | 62 | | | 62 | | PHI | 97 |
| | 213 |
| | 88 |
| | 128 |
| | 94 |
| | 123 |
| | 38 |
| | 71 |
| PHI | 98 | | | 191 | | | 333 | | | 81 | | | 102 | | | 183 | | | 134 | | | 134 | | Pepco | 40 |
| | 101 |
| | 48 |
| | 24 |
| | 41 |
| | 78 |
| | 25 |
| | 25 |
| Pepco | 47 | | | 98 | | | 95 | | | 28 | | | 58 | | | 73 | | | 73 | | | 28 | | DPL | 34 |
| | 35 |
| | 29 |
| | 41 |
| | 38 |
| | 18 |
| | 4 |
| | 36 |
| DPL | 41 | | | 43 | | | 23 | | | 40 | | | 42 | | | 33 | | | 14 | | | 52 | | ACE | 24 |
| | 76 |
| | 12 |
| | 12 |
| | 13 |
| | 27 |
| | 10 |
| | 9 |
| ACE | 8 | | | 51 | | | 215 | | | 14 | | | 3 | | | 76 | | | 12 | | | 23 | |
First Quarter 20202022 Dividend On January 28, 2020, the ExelonFebruary 8, 2022, Exelon's Board of Directors declared a first quarter 2020 regular quarterly dividend of $0.3825$0.3375 per share on Exelon’s common stock for the first quarter of 2022. The dividend is payable on Monday, March 10, 2020,2022, to shareholders of record of Exelon at the endas of the day5 p.m. Eastern time on Friday, February 20, 2020.25, 2022.
| | | | | | ITEM 6. | SELECTED FINANCIAL DATA |
The selected financial data presented below has been derived from the audited consolidated financial statements of Exelon. This data is qualified in its entirety by reference to and should be read in conjunction with Exelon’s Consolidated Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
| | | | | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | (In millions, except per share data) | 2019 | | 2018(a) | | 2017(a) | | 2016(b) | | 2015 | Statement of Operations data: | | | | | | | | | | Operating revenues | $ | 34,438 |
| | $ | 35,978 |
| | $ | 33,558 |
| | $ | 31,366 |
| | $ | 29,447 |
| Operating income | 4,374 |
| | 3,891 |
| | 4,388 |
| | 3,212 |
| | 4,554 |
| Net income | 3,028 |
|
| 2,079 |
|
| 3,869 |
|
| 1,196 |
|
| 2,250 |
| Net income attributable to common shareholders | 2,936 |
| | 2,005 |
| | 3,779 |
| | 1,121 |
| | 2,269 |
| Earnings per average common share (diluted): | | | | | | | | | | Net income | $ | 3.01 |
| | $ | 2.07 |
| | $ | 3.98 |
| | $ | 1.21 |
| | $ | 2.54 |
| Dividends per common share | $ | 1.45 |
| | $ | 1.38 |
| | $ | 1.31 |
| | $ | 1.26 |
| | $ | 1.24 |
|
| | | | | | | | | | | | | | | | | | | | | | December 31, | (In millions) | 2019 | | 2018(a) | | 2017(a) | | 2016 | | 2015 | Balance Sheet data: | | | | | | | | | | Current assets | $ | 12,037 |
| | $ | 13,328 |
| | $ | 11,872 |
| | $ | 12,451 |
| | $ | 15,334 |
| Property, plant and equipment, net | 80,233 |
| | 76,707 |
| | 74,202 |
| | 71,555 |
| | 57,439 |
| Total assets | 124,977 |
|
| 119,634 |
|
| 116,746 |
|
| 114,952 |
|
| 95,384 |
| Current liabilities | 14,185 |
| | 11,404 |
| | 10,798 |
| | 13,463 |
| | 9,118 |
| Long-term debt, including long-term debt to financing trusts | 31,719 |
| | 34,465 |
| | 32,565 |
| | 32,216 |
| | 24,286 |
| Shareholders’ equity | 32,224 |
| | 30,741 |
| | 29,878 |
| | 25,860 |
| | 25,793 |
|
__________
| | | | | | (a) | Amounts have been revised to reflect the correction of an error related to Pepco's decoupling mechanism. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional information.
|
| | (b) | The 2016 financial results include the activity of PHI from the merger effective date of March 24, 2016 through December 31, 2016. |
Generation
The selected financial data presented below has been derived from the audited consolidated financial statements of Generation. This data is qualified in its entirety by reference to and should be read in conjunction with Generation’s Consolidated Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
| | | | | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | (In millions) | 2019 | | 2018 | | 2017 | | 2016 | | 2015 | Statement of Operations data: | | | | | | | | | | Operating revenues | $ | 18,924 |
| | $ | 20,437 |
| | $ | 18,500 |
| | $ | 17,757 |
| | $ | 19,135 |
| Operating income | 1,323 |
| | 975 |
| | 947 |
| | 820 |
| | 2,275 |
| Net income | 1,217 |
| | 443 |
| | 2,798 |
| | 550 |
| | 1,340 |
|
| | | | | | | | | | | | | | | | | | | | | | December 31, | (In millions) | 2019 | | 2018 | | 2017 | | 2016 | | 2015 | Balance Sheet data: | | | | | | | | | | Current assets | $ | 7,076 |
| | $ | 8,433 |
| | $ | 6,882 |
| | $ | 6,567 |
| | $ | 6,342 |
| Property, plant and equipment, net | 24,193 |
| | 23,981 |
| | 24,906 |
| | 25,585 |
| | 25,843 |
| Total assets | 48,995 |
|
| 47,556 |
|
| 48,457 |
|
| 47,022 |
|
| 46,529 |
| Current liabilities | 7,289 |
| | 5,769 |
| | 4,191 |
| | 5,689 |
| | 4,933 |
| Long-term debt, including long-term debt to affiliates | 4,792 |
| | 7,887 |
| | 8,644 |
| | 8,124 |
| | 8,869 |
| Member’s equity | 13,484 |
| | 13,204 |
| | 13,669 |
| | 11,505 |
| | 11,635 |
|
ComEd
The selected financial data presented below has been derived from the audited consolidated financial statements of ComEd. This data is qualified in its entirety by reference to and should be read in conjunction with ComEd’s Consolidated Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
| | | | | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | (In millions) | 2019 | | 2018 | | 2017 | | 2016 | | 2015 | Statement of Operations data: | | | | | | | | | | Operating revenues | $ | 5,747 |
| | $ | 5,882 |
| | $ | 5,536 |
| | $ | 5,254 |
| | $ | 4,905 |
| Operating income | 1,171 |
| | 1,146 |
| | 1,323 |
| | 1,205 |
| | 1,017 |
| Net income | 688 |
| | 664 |
| | 567 |
| | 378 |
| | 426 |
|
| | | | | | | | | | | | | | | | | | | | | | December 31, | (In millions) | 2019 | | 2018 | | 2017 | | 2016 | | 2015 | Balance Sheet data: | | | | | | | | | | Current assets | $ | 1,583 |
| | $ | 1,570 |
| | $ | 1,364 |
| | $ | 1,554 |
| | $ | 1,518 |
| Property, plant and equipment, net | 23,107 |
| | 22,058 |
| | 20,723 |
| | 19,335 |
| | 17,502 |
| Total assets | 32,765 |
|
| 31,213 |
|
| 29,726 |
|
| 28,335 |
|
| 26,532 |
| Current liabilities | 2,117 |
| | 1,925 |
| | 2,294 |
| | 2,938 |
| | 2,766 |
| Long-term debt, including long-term debt to financing trusts | 8,196 |
| | 8,006 |
| | 6,966 |
| | 6,813 |
| | 6,049 |
| Shareholders’ equity | 10,677 |
| | 10,247 |
| | 9,542 |
| | 8,725 |
| | 8,243 |
|
PECO
The selected financial data presented below has been derived from the audited consolidated financial statements of PECO. This data is qualified in its entirety by reference to and should be read in conjunction with PECO’s Consolidated Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
| | | | | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | (In millions) | 2019 | | 2018 | | 2017 | | 2016 | | 2015 | Statement of Operations data: | | | | | | | | | | Operating revenues | $ | 3,100 |
| | $ | 3,038 |
| | $ | 2,870 |
| | $ | 2,994 |
| | $ | 3,032 |
| Operating income | 713 |
| | 587 |
| | 655 |
| | 702 |
| | 630 |
| Net income | 528 |
| | 460 |
| | 434 |
| | 438 |
| | 378 |
|
| | | | | | | | | | | | | | | | | | | | | | December 31, | (In millions) | 2019 | | 2018 | | 2017 | | 2016 | | 2015 | Balance Sheet data: | | | | | | | | | | Current assets | $ | 722 |
| | $ | 782 |
| | $ | 822 |
| | $ | 757 |
| | $ | 842 |
| Property, plant and equipment, net | 9,292 |
| | 8,610 |
| | 8,053 |
| | 7,565 |
| | 7,141 |
| Total assets | 11,469 |
|
| 10,642 |
|
| 10,170 |
|
| 10,831 |
|
| 10,367 |
| Current liabilities | 722 |
| | 809 |
| | 1,267 |
| | 727 |
| | 944 |
| Long-term debt, including long-term debt to financing trusts | 3,589 |
| | 3,268 |
| | 2,587 |
| | 2,764 |
| | 2,464 |
| Shareholder's equity | 4,178 |
| | 3,820 |
| | 3,577 |
| | 3,415 |
| | 3,236 |
|
BGE
The selected financial data presented below has been derived from the audited consolidated financial statements of BGE. This data is qualified in its entirety by reference to and should be read in conjunction with BGE’s Consolidated Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
| | | | | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | (In millions) | 2019 | | 2018 | | 2017 | | 2016 | | 2015 | Statement of Operations data: | | | | | | | | | | Operating revenues | $ | 3,106 |
| | $ | 3,169 |
| | $ | 3,176 |
| | $ | 3,233 |
| | $ | 3,135 |
| Operating income | 532 |
| | 474 |
| | 614 |
| | 550 |
| | 558 |
| Net income | 360 |
| | 313 |
| | 307 |
| | 294 |
| | 288 |
|
| | | | | | | | | | | | | | | | | | | | | | December 31, | (In millions) | 2019 | | 2018 | | 2017 | | 2016 | | 2015 | Balance Sheet data: | | | | | | | | | | Current assets | $ | 833 |
| | $ | 786 |
| | $ | 811 |
| | $ | 842 |
| | $ | 845 |
| Property, plant and equipment, net | 8,990 |
| | 8,243 |
| | 7,602 |
| | 7,040 |
| | 6,597 |
| Total assets | 10,634 |
|
| 9,716 |
|
| 9,104 |
|
| 8,704 |
|
| 8,295 |
| Current liabilities | 753 |
| | 774 |
| | 760 |
| | 707 |
| | 1,134 |
| Long-term debt, including long-term debt to financing trusts | 3,270 |
| | 2,876 |
| | 2,577 |
| | 2,533 |
| | 1,732 |
| Shareholder's equity | 3,683 |
| | 3,354 |
| | 3,141 |
| | 2,848 |
| | 2,687 |
|
PHI
The selected financial data presented below has been derived from the audited consolidated financial statements of PHI. This data is qualified in its entirety by reference to and should be read in conjunction with PHI’s Consolidated Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
| | | | | | | | | | | | | | | | | | | | | | | | | | Successor | | | Predecessor | | For the Years Ended December 31, | | March 24 to December 31, | | | January 1 to March 23, | | For the Year Ended December 31, | (In millions) | 2019 | | 2018(a) | | 2017(a) | | 2016 | | | 2016 | | 2015 | Statement of Operations data: | | | | | | | | | | | | | Operating revenues | $ | 4,806 |
| | $ | 4,798 |
| | $ | 4,672 |
| | $ | 3,643 |
| | | $1,153 | | $ | 4,935 |
| Operating income | 722 |
| | 643 |
| | 762 |
| | 93 |
| | | 105 |
| | 673 |
| Net income (loss) from continuing operations | 477 |
| | 393 |
| | 355 |
| | (61 | ) | | | 19 |
| | 318 |
| Net income (loss) | 477 |
| | 393 |
| | 355 |
| | (61 | ) | | | 19 |
| | 327 |
|
| | | | | | | | | | | | | | | | | | | | | | Successor | | | Predecessor | | December 31, | | | | (In millions) | 2019 | | 2018(a) | | 2017(a) | 2016 | | | 2015 | Balance Sheet data: | | | | | | | | | | Current assets | $ | 1,480 |
| | $ | 1,501 |
| | $ | 1,527 |
| $ | 1,838 |
| | | $ | 1,474 |
| Property, plant and equipment, net | 14,296 |
| | 13,446 |
| | 12,498 |
| 11,598 |
| | | 10,864 |
| Total assets | 22,719 |
| | 21,952 |
| | 21,223 |
| 21,025 |
| | | 16,188 |
| Current liabilities | 1,612 |
| | 1,592 |
| | 1,931 |
| 2,284 |
| | | 2,327 |
| Long-term debt | 6,460 |
| | 6,134 |
| | 5,478 |
| 5,645 |
| | | 4,823 |
| Preferred Stock | — |
| | — |
| | — |
| — |
| | | 183 |
| Member’s equity/Shareholders' equity | 9,608 |
| | 9,259 |
| | 8,807 |
| 8,016 |
| | | 4,413 |
|
__________
| | (a) | Amounts have been revised to reflect the correction of an error related to Pepco's decoupling mechanism. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional information.
|
Pepco
The selected financial data presented below has been derived from the audited consolidated financial statements of Pepco. This data is qualified in its entirety by reference to and should be read in conjunction with Pepco’s Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
| | | | | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | (In millions) | 2019 | | 2018(a) | | 2017(a) | | 2016 | | 2015 | Statement of Operations data: | | | | | | | | | | Operating revenues | $ | 2,260 |
| | $ | 2,232 |
| | $ | 2,151 |
| | $ | 2,186 |
| | $ | 2,129 |
| Operating income | 361 |
| | 313 |
| | 392 |
| | 174 |
| | 385 |
| Net income | 243 |
| | 205 |
| | 198 |
| | 42 |
| | 187 |
|
| | | | | | | | | | | | | | | | | | | | | | December 31, | (In millions) | 2019 | | 2018(a) | | 2017(a) | | 2016 | | 2015 | Balance Sheet data: | | | | | | | | | | Current assets | $ | 696 |
| | $ | 728 |
| | $ | 686 |
| | $ | 684 |
| | $ | 726 |
| Property, plant and equipment, net | 6,909 |
| | 6,460 |
| | 6,001 |
| | 5,571 |
| | 5,162 |
| Total assets | 8,661 |
| | 8,267 |
| | 7,808 |
| | 7,335 |
| | 6,908 |
| Current liabilities | 657 |
| | 628 |
| | 550 |
| | 596 |
| | 455 |
| Long-term debt | 2,862 |
| | 2,704 |
| | 2,521 |
| | 2,333 |
| | 2,340 |
| Shareholder's equity | 2,907 |
| | 2,717 |
| | 2,515 |
| | 2,300 |
| | 2,240 |
|
__________
| | (a) | Amounts have been revised to reflect the correction of an error related to Pepco's decoupling mechanism. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional information.
|
DPL
The selected financial data presented below has been derived from the audited consolidated financial statements of DPL. This data is qualified in its entirety by reference to and should be read in conjunction with DPL’s Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
| | | | | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | (In millions) | 2019 | | 2018 | | 2017 | | 2016 | | 2015 | Statement of Operations data: | | | | | | | | | | Operating revenues | $ | 1,306 |
| | $ | 1,332 |
| | $ | 1,300 |
| | $ | 1,277 |
| | $ | 1,302 |
| Operating income | 217 |
| | 190 |
| | 229 |
| | 50 |
| | 165 |
| Net income (loss) | 147 |
| | 120 |
| | 121 |
| | (9 | ) | | 76 |
|
| | | | | | | | | | | | | | | | | | | | | | December 31, | (In millions) | 2019 | | 2018 | | 2017 | | 2016 | | 2015 | Balance Sheet data: | | | | | | | | | | Current assets | $ | 325 |
| | $ | 336 |
| | $ | 325 |
| | $ | 370 |
| | $ | 388 |
| Property, plant and equipment, net | 4,035 |
| | 3,821 |
| | 3,579 |
| | 3,273 |
| | 3,070 |
| Total assets | 4,830 |
| | 4,588 |
| | 4,357 |
| | 4,153 |
| | 3,969 |
| Current liabilities | 414 |
| | 375 |
| | 547 |
| | 381 |
| | 564 |
| Long-term debt | 1,487 |
| | 1,403 |
| | 1,217 |
| | 1,221 |
| | 1,061 |
| Shareholder's equity | 1,580 |
| | 1,509 |
| | 1,335 |
| | 1,326 |
| | 1,237 |
|
ACE
The selected financial data presented below has been derived from the audited consolidated financial statements of ACE. This data is qualified in its entirety by reference to and should be read in conjunction with ACE’s Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
| | | | | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | (In millions) | 2019 | | 2018 | | 2017 | | 2016 | | 2015 | Statement of Operations data: | | | | | | | | | | Operating revenues | $ | 1,240 |
| | $ | 1,236 |
| | $ | 1,186 |
| | $ | 1,257 |
| | $ | 1,295 |
| Operating income | 151 |
| | 149 |
| | 157 |
| | 7 |
| | 134 |
| Net income (loss) | 99 |
| | 75 |
| | 77 |
| | (42 | ) | | 40 |
|
| | | | | | | | | | | | | | | | | | | | | | December 31, | (In millions) | 2019 | | 2018 | | 2017 | | 2016 | | 2015 | Balance Sheet data: | | | | | | | | | | Current assets | $ | 270 |
| | $ | 240 |
| | $ | 258 |
| | $ | 399 |
| | $ | 546 |
| Property, plant and equipment, net | 3,190 |
| | 2,966 |
| | 2,706 |
| | 2,521 |
| | 2,322 |
| Total assets | 3,933 |
| | 3,699 |
| | 3,445 |
| | 3,457 |
| | 3,387 |
| Current liabilities | 360 |
| | 422 |
| | 619 |
| | 320 |
| | 297 |
| Long-term debt | 1,307 |
| | 1,170 |
| | 840 |
| | 1,120 |
| | 1,153 |
| Shareholder's equity | 1,276 |
| | 1,126 |
| | 1,043 |
| | 1,034 |
| | 1,000 |
|
| | | Item 7. | 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 As of December 31, 2021, Exelon iswas 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 eleven 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. During the first quarter of 2019, due to a change in economics in our New England region, Generation changed the way that information is reviewed by the CODM. The New England region is no longer regularly reviewed as a separate region by the CODM nor presented separately in any external information presented to third parties. Information for the New England region is reviewed by the CODM as part of Other Power Regions. 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.and its subsidiary Generation. The following combined Management’s Discussion and Analysis of Financial Condition and Results of Operations summarizes results for the year ended December 31, 20192021 compared to the year ended December 31, 2018,2020, and 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. For discussion of the year ended December 31, 20182020 compared to the year ended December 31, 2017,2019, refer to ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS in the 2018-Form2020 Form 10-K, which was filed with the SEC on February 8, 2019.24, 2021. COVID-19. The Registrants have taken steps to mitigate the potential risks posed by the global outbreak (pandemic) of COVID-19. The Registrants provide a critical service to our customers which means that it is paramount that we keep our employees who operate our businesses safe and minimize unnecessary risk of exposure to the virus by taking extra precautions for employees who work in the field and in our facilities. The Registrants have implemented work from home policies where appropriate, and imposed travel limitations on employees.
The Registrants continue to implement strong physical and cyber-security measures to ensure that our systems remain functional in order to both serve our operational needs with a remote workforce and keep them running to ensure uninterrupted service to our customers. There were no changes in internal control over financial reporting as a result of COVID-19 that materially affected, or are reasonably likely to materially affect, any of the Registrants’ internal control over financial reporting. See ITEM 9A. CONTROLS AND PROCEDURES for additional information. Unfavorable economic conditions due to COVID-19 resulted in an estimated reduction to Exelon’s Net income of approximately $245 million for the year ended December 31, 2020. The impact was not material for the year ended December 31, 2021. To offset the unfavorable impacts from COVID-19, Exelon identified approximately $250 million in cost savings in 2020. The cost savings achieved in 2020 were higher than originally anticipated. The Registrants assessed long-lived assets, goodwill, and investments for recoverability and there were no material impairment charges recorded in 2020 or 2021 as a result of COVID-19. See Note 12 — Asset Impairments of the Combined Notes to Consolidated Financial Statements for additional information related to other impairment assessments. The Registrants will continue to monitor developments affecting their workforce, customers, and suppliers and will take additional precautions that they determine to be necessary in order to mitigate the impacts. The Registrants cannot predict the full extent of the impacts of COVID-19, which will depend on, among other things, the rate, and public perceptions of the effectiveness, of vaccinations and rate of resumption of business activity.
Financial Results of Operations GAAP Results of Operations. The following table sets forth Exelon's GAAP consolidated Net Income attributable to common shareholders by Registrant or subsidiary for the year ended December 31, 20192021 compared to the same period in 2018 and 2017.2020. For additional information regarding the financial results for the years ended December 31, 20192021 and 2018and2020 see the discussions of Results of Operations by Registrant.Registrant or subsidiary. | | | 2019 | | 2018(a) | | Favorable (unfavorable) 2019 vs. 2018 variance | | 2017(a) | | Favorable (unfavorable) 2018 vs. 2017 variance | | 2021 | | 2020 | | (Unfavorable) Favorable Variance | Exelon | $ | 2,936 |
| | $ | 2,005 |
| | $ | 931 |
| | $ | 3,779 |
| | $ | (1,774 | ) | Exelon | $ | 1,706 | | | $ | 1,963 | | | $ | (257) | | Generation | 1,125 |
| | 370 |
| | 755 |
| | 2,710 |
| | (2,340 | ) | | | ComEd | 688 |
| | 664 |
| | 24 |
| | 567 |
| | 97 |
| ComEd | 742 | | | 438 | | | 304 | | PECO | 528 |
| | 460 |
| | 68 |
| | 434 |
| | 26 |
| PECO | 504 | | | 447 | | | 57 | | BGE | 360 |
| | 313 |
| | 47 |
| | 307 |
| | 6 |
| BGE | 408 | | | 349 | | | 59 | | PHI | 477 |
| | 393 |
| | 84 |
| | 355 |
| | 38 |
| PHI | 561 | | | 495 | | | 66 | | Pepco | 243 |
| | 205 |
| | 38 |
| | 198 |
| | 7 |
| Pepco | 296 | | | 266 | | | 30 | | DPL | 147 |
| | 120 |
| | 27 |
| | 121 |
| | (1 | ) | DPL | 128 | | | 125 | | | 3 | | ACE | 99 |
| | 75 |
| | 24 |
| | 77 |
| | (2 | ) | ACE | 146 | | | 112 | | | 34 | | Generation | | Generation | (205) | | | 589 | | | (794) | | Other(b)(a) | (242 | ) | | (195 | ) | | (47 | ) | | (594 | ) | | 399 |
| (304) | | | (355) | | | 51 | |
__________ | | (a) | Exelon’s, PHI’s and Pepco’s amounts have been revised to reflect the correction of an error related to Pepco’s decoupling mechanism. See Note 1 - Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional information. |
| | (b) | Primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities and other financing and investing activities. |
(a)Primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities, and other financing and investing activities. Year Ended December 31, 20192021 Compared to Year Ended December 31, 2018.2020. Net income attributable to common shareholders increaseddecreased by $931$257 million and diluted earnings per average common share increaseddecreased to $3.01$1.74 in 20192021 from $2.07$2.01 in 20182020 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; •Higher net unrealized and realized losses on equity investments; and •The absence of prior year one-time tax settlements. The decreases were partially offset by;
•Higher electric distribution earnings from higher rate base and higher allowed ROE due to an increase in treasury rates at ComEd; •The favorable impacts of the multi-year plan at BGE and Pepco and regulatory rate increases at DPL and ACE; •Favorable weather conditions at PECO and DPL's Delaware service territory; •Favorable volume at PECO and ACE; •Lower storm costs at PECO and DPL due to the absence of the June 2020 and August 2020 storms, respectively; •Lower operating and maintenance expense at ComEd due to the payments that ComEd made in 2020 under the Deferred Prosecution Agreement; •Higher mark-to-market gains; •Higher net unrealized and realized gains on NDT funds; | | • | Decreased accelerated depreciation and amortization due to the early retirement of the Oyster Creek nuclear facility in September 2018 and TMI in September 2019and the absence of a charge associated with the remeasurement of the Oyster Creek ARO in 2018;
|
Decreased Operating
•Absence of one time charges recorded in the third quarter of 2020 associated with Generation's decision to early retire the Byron and maintenance expense at Generation which includesDresden nuclear facilities and Mystic Units 8 and 9, and the impactsreversal of one-time charges resulting from the reversal of the previous cost management programs,decision to early retire Byron and Dresden on September 15, 2021; •Favorable sales and hedges of excess emission credits; •Favorable commodity prices on fuel hedges; •Lower nuclear fuel costs due to accelerated amortization of nuclear fuel and lower pensionprices; and OPEB costs •Higher New York ZEC revenues due to higher generation and increased NEIL insurance distributions; | | • | A benefit associated with the remeasurement of the TMI ARO in the first quarter of 2019an increase in ZEC prices.and the annual nuclear ARO update in the third quarter of 2019;
|
Decreased nuclear outage days;
Lower mark-to-market losses;
Regulatory rate increases at PECO, BGE, Pepco, DPL, and ACE;
Increased electric distribution, energy efficiency and transmission earnings at ComEd;
Decreased storms costs at PECO and BGE; and
Research and development income tax benefits.
The increases were partially offset by;
Lower realized energy prices;
Lower capacity prices;
Unfavorable weather conditions at PECO, DPL and ACE; and
Unfavorable volume at PECO.
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 table provides a reconciliation between Net income attributable to common shareholders as determined in accordance with GAAP and Adjusted (non-GAAP) operating earnings for the year ended December 31, 20192021 as compared to 2018 and 2017:2020: | | | | | | | | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | | 2019 | | 2018(a) | 2017(a) | (All amounts in millions after tax) | | | Earnings per Diluted Share | | | | Earnings per Diluted Share | | | Earnings per Diluted Share | Net Income Attributable to Common Shareholders | $ | 2,936 |
| | $ | 3.01 |
| | $ | 2,005 |
| | $ | 2.07 |
| $ | 3,779 |
| | $ | 3.98 |
| Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $66, $89 and $68, respectively) | 197 |
| | 0.20 |
| | 252 |
| | 0.26 |
| 107 |
| | 0.11 |
| Unrealized (Gains) Losses Related to NDT Fund Investments (net of taxes of $269, $289 and $286, respectively)(b) | (299 | ) | | (0.31 | ) | | 337 |
| | 0.35 |
| (318 | ) | | (0.34 | ) | Amortization of Commodity Contract Intangibles (net of taxes of $22) | — |
| | — |
| | — |
| | — |
| 34 |
| | 0.04 |
| PHI Merger and Integration Costs (net of taxes of $2 and $25, respectively) | — |
| | — |
| | 3 |
| | — |
| 40 |
| | 0.04 |
| Merger Commitments (net of taxes of $137) | — |
| | — |
| | — |
| | — |
| (137 | ) | | (0.14 | ) | Asset Impairments (net of taxes of $56, $13 and $204, respectively)(c) | 123 |
| | 0.13 |
| | 35 |
| | 0.04 |
| 321 |
| | 0.34 |
| Plant Retirements and Divestitures (net of taxes of $9, $181, and $134, respectively)(d) | 118 |
| | 0.12 |
| | 512 |
| | 0.53 |
| 207 |
| | 0.22 |
| Cost Management Program (net of taxes of $17, $16, and $21, respectively)(e) | 51 |
| | 0.05 |
| | 48 |
| | 0.05 |
| 34 |
| | 0.04 |
| Asset Retirement Obligation (net of taxes of $9, $7, and $1, respectively)(f) | (84 | ) | | (0.09 | ) | | 20 |
| | 0.02 |
| (2 | ) | | — |
| Vacation Policy Change (net of taxes of $21) | — |
| | — |
| | — |
| | — |
| (33 | ) | | (0.03 | ) | Change in Environmental Liabilities (net of taxes of $8, $0, and $17, respectively) | 20 |
| | 0.02 |
| | (1 | ) | | — |
| 27 |
| | 0.03 |
| Bargain Purchase Gain (net of taxes of $0) | — |
| | — |
| | — |
| | — |
| (233 | ) | | (0.25 | ) | Gain on Deconsolidation of Business (net of taxes of $83) | — |
| | — |
| | — |
| | — |
| (130 | ) | | (0.14 | ) | Gain on Contract Settlement (net of taxes of $20)(g) | — |
| | — |
| | (55 | ) | | (0.06 | ) | — |
| | — |
| Litigation Settlement Gain (net of taxes of $7) | (19 | ) | | (0.02 | ) | | — |
| | — |
| — |
| | — |
| Income Tax-Related Adjustments (entire amount represents tax expense)(h) | 5 |
| | 0.01 |
| | (22 | ) | | (0.02 | ) | (1,330 | ) | | (1.41 | ) | Noncontrolling Interests (net of taxes of $26, $24, and $24, respectively)(i) | 90 |
| | 0.09 |
| | (113 | ) | | (0.12 | ) | 114 |
| | 0.12 |
| Adjusted (non-GAAP) Operating Earnings | $ | 3,139 |
| | $ | 3.22 |
| | $ | 3,021 |
| | $ | 3.12 |
| $ | 2,480 |
| | $ | 2.61 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | | 2021 | | 2020 | (In millions, except per share data) | | | Earnings per Diluted Share | | | | Earnings per Diluted Share | Net Income Attributable to Common Shareholders | $ | 1,706 | | | $ | 1.74 | | | $ | 1,963 | | | $ | 2.01 | | Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $145 and $73, respectively) | (421) | | | (0.43) | | | (213) | | | (0.22) | | Unrealized Gains Related to NDT Fund Investments (net of taxes of $141 and $278, respectively)(a) | (139) | | | (0.14) | | | (256) | | | (0.26) | | | | | | | | | | Asset Impairments (net of taxes of $136 and $135, respectively)(b) | 405 | | | 0.41 | | | 396 | | | 0.41 | | Plant Retirements and Divestitures (net of taxes of $290 and $244, respectively)(c) | 865 | | | 0.88 | | | 718 | | | 0.74 | | Cost Management Program (net of taxes of $2 and $14, respectively)(d) | 9 | | | 0.01 | | | 45 | | | 0.05 | | | | | | | | | | Asset Retirement Obligation (net of taxes of $12 and $16, respectively)(e) | (35) | | | (0.04) | | | 48 | | | 0.05 | | Change in Environmental Liabilities (net of taxes of $3 and $6, respectively) | 9 | | | 0.01 | | | 18 | | | 0.02 | | COVID-19 Direct Costs (net of taxes of $13 and $19, respectively)(f) | 36 | | | 0.04 | | | 50 | | | 0.05 | | Deferred Prosecution Agreement Payments (net of taxes of $0)(g) | — | | | — | | | 200 | | | 0.20 | | Acquisition Related Costs (net of taxes of $5 and $1, respectively)(h) | 15 | | | 0.02 | | | 4 | | | — | | ERP System Implementation Costs (net of taxes of $4 and $1, respectively)(i) | 13 | | | 0.01 | | | 3 | | | — | | Separation Costs (net of taxes of $31)(j) | 90 | | | 0.09 | | | — | | | — | | Costs Related to Suspension of Contractual Offset (net of taxes of $45)(k) | 148 | | | 0.15 | | | — | | | — | | Income Tax-Related Adjustments (entire amount represents tax expense)(l) | 47 | | | 0.05 | | | 71 | | | 0.07 | | Noncontrolling Interests (net of taxes of $2 and $19, respectively)(m) | 16 | | | 0.02 | | | 103 | | | 0.11 | | Adjusted (non-GAAP) Operating Earnings | $ | 2,764 | | | $ | 2.82 | | | $ | 3,149 | | | $ | 3.22 | |
__________ Note: Amounts may not sum due to rounding. Unless otherwise noted, the income tax impact of each reconciling item between GAAP Net Income 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 funds, the marginal statutory income tax rates for 20192021 and 20182020 ranged from 26.0 percent25.0% to 29.0 percent.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 funds were 47.3 percent50.4% and 46.2 percent52.1% for the years ended December 31, 20192021 and 2018,2020, 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 of 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 of the New England asset group in the third quarter of 2020 at Generation. (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.
| | (a) | Net Income Attributable to Common Shareholders and Adjusted (non-GAAP) Operating Earnings have been revised to reflect the correction of an error related to Pepco’s decoupling mechanism. See Note 1 - Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional information. |
| | (b) | Reflects the impact of net unrealized gains and losses on Generation’s NDT fund investments for Non-Regulatory and Regulatory Agreement Units. The impacts of the Regulatory Agreement Units, including the associated income taxes, are contractually eliminated, resulting in no earnings impact. |
| | (c) | In 2018, primarily reflects the impairment of certain wind projects at Generation. In 2019, primarily reflects the impairment of equity method investments in certain distributed energy companies. The impact of such impairment net of noncontrolling interest is $0.02. |
| | (d) | (d)Primarily represents reorganization and severance costs related to cost management programs. (e)For Generation, reflects an adjustment to the nuclear asset obligation for the Non-Regulatory Agreement Units resulting from the annual update in the third quarter of 2021 and fourth quarter of 2020, respectively. (f)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. (g)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. (h)Reflects costs related to the acquisition of EDF's interest in CENG, which was completed in the third quarter of 2021. (i)Reflects costs related to a multi-year Enterprise Resource Program (ERP) system implementation. (j)Represents costs related to the 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. (k)Decommissioning-related activities for 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 consolidated statements of operations. These costs reflect the 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. (l)In 2021, primarily reflects the recognition of a valuation allowance against a deferred tax asset associated with Delaware net operating loss carryforwards due to a change in Delaware tax law. In 2021 and 2020, also 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. In 2018, primarily reflects accelerated depreciation and amortization expenses and one-time charges associated with Generation's decision to early retire the Oyster Creek and TMI nuclear facilities, a charge associated with a remeasurement of the Oyster Creek ARO, partially offset by a gain associated with Generation's sale of its electrical contracting business. In 2019, primarily reflects accelerated depreciation and amortization expenses associated with the early retirement of the TMI nuclear facility and certain fossil sites and the loss on the sale of Oyster Creek to Holtec, partially offset by net realized gains related to Oyster Creek's NDT fund investments, a net benefit associated with remeasurements of the TMI ARO and a gain on the sale of certain wind assets.
|
| | (e) | Primarily represents severance and reorganization costs related to cost management programs. |
| | (f) | In 2018, reflects an increase at Pepco related primarily to asbestos identified at its Buzzard Point property. In 2019, reflects a benefit related to Generation's annual nuclear ARO update for non-regulatory units. |
| | (g) | Represents the gain on the settlement of a long-term gas supply agreement at Generation. |
| | (h) | In 2018, reflects an adjustment to the remeasurement of deferred income taxes as a result of the TCJA. In 2019, primarily reflects the adjustment to deferred income taxes due to changes in forecasted apportionment. |
| | (i) | Represents elimination from Generation’s results of the noncontrolling interests related to certain exclusion items. In 2018, primarily related to the impact of unrealized losses on NDT fund investments for CENG units. In 2019, primarily related to the impact of unrealized gains on NDT fund investments and the impact of the Generation's annual nuclear ARO update for CENG units, partially offset by the impairment of certain equity investments in distributed energy companies. |
Significant 20192021 Transactions and Developments Utility Rates and Base Rate ProceedingsSeparation
TheOn February 21, 2021, Exelon’s Board of Directors approved a plan to separate the Utility Registrants file base rate casesand Generation, creating two publicly traded companies with their regulatory commissions seeking increases or decreasesthe resources necessary to their electric transmissionbest serve customers and distribution,sustain long-term investment and gas distribution ratesoperating excellence ("the separation"). The separation gives each company the financial and strategic independence to recover their costs and earn a fair returnfocus on their investments.its specific customer needs, while executing its core business strategy. Exelon completed the separation on February 1, 2022. The outcomes of these regulatory proceedings impact the Utility Registrants’ current and future results of operations, cash flows and financial position.
The following tables show the Utility Registrants’ completed and pending distribution base rate case proceedings in 2019.new publicly traded company is Constellation Energy Corporation. See Note 326 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on other regulatory proceedings.
Completed Utility Distribution Base Rate Case Proceedings
| | | | | | | | | | | | | Registrant/Jurisdiction | Filing Date | Requested Revenue Requirement Increase (Decrease) | Approved Revenue Requirement Increase (Decrease) | Approved ROE | Approval Date | Rate Effective Date | ComEd - Illinois (Electric) | April 16, 2018 | $ | (23 | ) | $ | (24 | ) | 8.69 | % | December 4, 2018 | January 1, 2019 | ComEd - Illinois (Electric) | April 8, 2019 | $ | (6 | ) | $ | (17 | ) | 8.91 | % | December 4, 2019 | January 1, 2020 | PECO - Pennsylvania (Electric) | March 29, 2018 | $ | 82 |
| $ | 25 |
| N/A | December 20, 2018 | January 1, 2019 | BGE - Maryland (Natural Gas) | June 8, 2018 (amended October 12, 2018) | $ | 61 |
| 43 |
| 9.8 | % | January 4, 2019 | January 4, 2019 | BGE - Maryland (Electric) | May 24, 2019 (amended December 17, 2019) | $ | 74 |
| $ | 18 |
| 9.7 | % | December 17, 2019 | December 17, 2019 | BGE - Maryland (Natural Gas) | May 24, 2019 (amended December 17, 2019) | $ | 59 |
| $ | 45 |
| 9.75 | % | December 17, 2019 | December 17, 2019 | ACE - New Jersey (Electric) | August 21, 2018 (amended November 19, 2018) | $ | 122 |
| $ | 70 |
| 9.6 | % | March 13, 2019 | April 1, 2019 | Pepco - Maryland (Electric) | January 15, 2019 (amended May 16, 2019) | $ | 27 |
| $ | 10.3 |
| 9.6 | % | August 12, 2019 | August 13, 2019 |
Pending Distribution Base Rate Case Proceedings
| | | | | | | | | Registrant/Jurisdiction | Filing Date | Requested Revenue Requirement Increase | Requested ROE | Expected Approval Timing | Pepco - District of Columbia (Electric) | May 30, 2019 (amended September 16, 2019) | $ | 160 |
| 10.3 | % | Fourth quarter of 2020 | DPL - Maryland (Electric) | December 5, 2019 | $ | 19 |
| 10.3 | % | Third quarter of 2020 |
Transmission Formula Rate
The following total (decreases)/increases were included in ComEd's, BGE's, Pepco's, DPL's and ACE's 2019 annual electric transmission formula rate updates.
| | | | | | | | | | | | | | | Registrant | Initial Revenue Requirement Increase/(Decrease) | Annual Reconciliation (Decrease)/Increase | Total Revenue Requirement Increase/(Decrease) | Allowed Return on Rate Base | Allowed ROE | ComEd | $ | 21 |
| $ | (16 | ) | $ | 5 |
| 8.21 | % | 11.50 | % | BGE | (10 | ) | (23 | ) | (19 | ) | 7.35 | % | 10.50 | % | Pepco | 15 |
| 11 |
| 26 |
| 7.75 | % | 10.50 | % | DPL | 17 |
| (1 | ) | 16 |
| 7.14 | % | 10.50 | % | ACE | 11 |
| (2 | ) | 9 |
| 7.79 | % | 10.50 | % |
PECO Transmission Formula Rate
On May 1, 2017, PECO filed a request with FERC seeking approval to update its transmission rates and change the manner in which PECO’s transmission rate is determined from a fixed rate to a formula rate. The formula rate will be updated annually to ensure that under this rate customers pay the actual costs of providing transmission services. PECO’s initial formula rate filing included a requested increase of $22 million to PECO’s annual transmission revenue requirement, which reflected a ROE of 11%, inclusive of a 50 basis point adder for being a member of a RTO. On June 27, 2017, FERC issued an Order accepting the filing and suspending the proposed rates until December 1, 2017, subject to refund, and set the matter for hearing and settlement judge procedures.
On December 5, 2019, FERC issued an Order accepting without modification the settlement agreement filed by PECO and other parties in July 2019. The settlement results in an increase of approximately $14 million with a return on rate base of 7.62% compared to PECO's initial formula rate filing and allows for an ROE of 10.35%, inclusive of a 50 basis point adder for being a member of the RTO. The settlement did not have a material impact on PECO's 2017, 2018, or 2019 annual transmission revenue requirements. PECO will update its rates in 2020 and refund estimated overcollections totaling approximately $28 million related to the amounts billed under the proposed rates in effect since 2017.
Pursuant to the transmission formula rate request discussed above, PECO made its annual formula rate updates in May 2018 and 2019, which included a decrease of $6 million and an increase of $8 million, respectively, to the annual transmission revenue requirement. The updated transmission formula rates were effective on June 1, 2018 and 2019, respectively, subject to refund.
Cost Management Programs
Exelon continues to be committed to managing its costs. On October 31, 2019, Exelon announced additional annual cost savings of approximately $100 million, at Generation, to be achieved by 2022. These actions are in response to the continuing economic challenges confronting Generation’s business, necessitating continued focus on cost management through enhanced efficiency and productivity.
FERC Order on the PJM MOPR
On December 19, 2019, FERC issued an order directing PJM to extend the MOPR to include new and existing resources, including nuclear, that receive state subsidies, effective as of PJM’s next capacity auction. Unless Illinois and New Jersey can implement an FRR program in their PJM zones, the MOPR will apply to Generation's nuclear plants in those states receiving ZEC benefits, resulting in higher offers for those units that may not clear the capacity market. On January 21, 2020, Exelon, PJM and a number of other entities submitted individual requests for rehearing. Exelon is currently working with PJM and other stakeholders to pursue the FRR option but cannot predict whether the legislative and regulatory changes can be implemented prior to the next capacity auction in PJM. If Generation’s state-supported nuclear plants in PJM or NYISO are subjected to the MOPR without compensation under an FRR or similar program, it could have a material adverse impact on Exelon's and Generation's financial
statements. See Note 3 — Regulatory MattersSeparation of the Combined Notes to Consolidated Financial Statements for additional information.
Early Plant Retirements
Oyster Creek. Generation permanently ceased generation operations at Oyster CreekIn connection with the separation, Exelon incurred transaction costs of $122 million on September 17, 2018. On July 31, 2018, Generation entered into an agreement with Holtec International and its wholly owned subsidiary, Oyster Creek Environmental Protection, LLC, for the sale and decommissioning of Oyster Creek. The sale was completed on July 1, 2019. Exelon and Generation recognized a loss on the sale in the third quarter 2019, which was immaterial. See Note 2 — Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information.
Three Mile Island. Generation permanently ceased operations at TMI on September 20, 2019. As a result of the decision to early retire TMI, Exelon and Generation recorded a $176 million incremental pre-tax net chargebasis for the year ended December 31, 20192021, which are recorded in Operating and maintenance expense. Exelon expects to incur incremental transaction costs of approximately $90 million in 2022. These costs are excluded from Adjusted (non-GAAP) Operating Earnings. The transaction costs are primarily duecomprised of system-related costs, third-party costs paid to accelerated depreciation of the plant assets, partially offset by a benefit associated with the remeasurement of the TMI AROadvisors, consultants, lawyers, and other experts assisting in the first quarter of 2019.
Salem. In 2017, PSEG announced that its New Jersey nuclear plants, including Salem, of which Generation owns a 42.59% ownership interest, were showing increased signs of economic distress, which could lead to an early retirement. PSEG is the operator of Salemseparation, and also has the decision-making authority to retire Salem. In 2018, New Jersey enacted legislation that established a ZEC program that provides compensation for nuclear plants that demonstrate to the NJBPU that they meet certain requirements, including that they make a significant contribution to air quality in the state and that their revenues are insufficient to cover their costs and risks. On April 18, 2019, the NJBPU approved the award of ZECs to Salem Unit 1 and Salem Unit 2. Assuming the continued effectiveness of the New Jersey ZEC program, Generation no longer considers Salem to be at heightened risk for early retirement.employee-related severance costs.
Dresden, Byron and Braidwood. Generation’s Dresden, Byron and Braidwood nuclear plants in Illinois are also showing increased signs of economic distress, which could lead to an early retirement, in a market that does not currently compensate them for their unique contribution to grid resiliency and their ability to produce large amounts of energy without carbon and air pollution. The May 2018 PJM capacity auction for the 2021-2022 planning year resulted in the largest volume of nuclear capacity ever not selected in the auction, including all of Dresden, and portions of Byron and Braidwood. Exelon continues to work with stakeholders on state policy solutions, while also advocating for broader market reforms at the regional and federal level.
See Note 3 — Regulatory Matters, Note 6 — Early Plant Retirements and Note 9 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information.
CENG Put OptionWater Quality
On November 20, 2019, Generation received noticeUnder the federal Clean Water Act, NPDES permits for discharges into waterways are required to be obtained from the EPA or from the state environmental agency to which the permit program has been delegated, and
permits must be renewed periodically. Certain of Exelon's facilities discharge water into waterways and are therefore subject to exercisethese regulations and operate under NPDES permits. Under Clean Water Act Section 404 and state laws and regulations, the put optionRegistrants may be required to obtain permits for projects involving dredge or fill activities in Waters of the United States. Where Registrants’ facilities are required to secure a federal license or permit for activities that may result in a discharge to covered waters, they may be required to obtain a state water quality certification under Clean Water Act section 401. Solid and sell its 49.99% equity interestHazardous Waste and Environmental Remediation CERCLA provides for response and removal actions coordinated by the EPA in CENGthe event of threatened releases of hazardous substances and authorizes the EPA either to Generationclean up sites at which hazardous substances have created actual or potential environmental hazards or to order persons responsible for the situation to do so. Under CERCLA, generators and transporters of hazardous substances, as well as past and present owners and operators of hazardous waste sites, are strictly, jointly and severally liable for the cleanup costs of hazardous waste at sites, many of which are listed by the EPA on the National Priorities List (NPL). These PRPs can be ordered to perform a cleanup, can be sued for costs associated with an EPA-directed cleanup, may voluntarily settle with the EPA concerning their liability for cleanup costs, or may voluntarily begin a site investigation and site remediation under state oversight. Most states have also enacted statutes that contain provisions substantially similar to CERCLA. Such statutes apply in many states where the Registrants currently own or operate, or previously owned or operated, facilities, including Delaware, Illinois, Maryland, New Jersey, and Pennsylvania and the put automatically exercisedDistrict of Columbia. In addition, RCRA governs treatment, storage and disposal of solid and hazardous wastes and cleanup of sites where such activities were conducted. The Registrants’ operations have in the past, and may in the future, require substantial expenditures in order to comply with these Federal and state environmental laws. Under these laws, the Registrants may be 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 January 19, 2020 atwhich their operations or the endoperations of others may have resulted in contamination by substances that are considered hazardous under environmental laws. The Registrants and their subsidiaries are, or could become in the sixty-day advance notice period. Underfuture, parties to proceedings initiated by the termsEPA, state agencies, and/or other responsible parties under CERCLA and RCRA or similar state laws with respect to a number of the Put Option, the purchase price issites or may undertake to be determined by agreement of the parties, or absent such agreement, by a third-party arbitration process. Any resulting sale wouldinvestigate and remediate sites for which they may be subject to enforcement actions by an agency or third-party. ComEd’s and PECO’s environmental liabilities primarily arise from contamination at former MGP sites. ComEd, pursuant to an ICC order, and PECO, pursuant to settlements of natural gas distribution rate cases with the approvalPAPUC, have an on-going process to recover environmental remediation costs of the NYPSC, the FERCMGP sites through a provision within customer rates. BGE, ACE, Pepco, and the NRC.DPL do not have material contingent liabilities relating to MGP sites. The processamount to be expended in 2022 for compliance with environmental remediation related to contamination at former MGP sites and regulatory approvals could take one to two years or more to complete. See Note 2 - Mergers, Acquisitions and Dispositions for additional information. Conowingo Hydroelectric Project
In connection with Generation’s pursuit of a new FERC license for Conowingo, on October 29, 2019, Generation and MDE filed with FERC a Joint Offer of Settlement that would resolve all outstanding issues between the parties, effective upon and subject to FERC’s approval and incorporation of the terms into the new license when issued. The financial impact of this settlement, along with other anticipated and prior license commitments, would be recognized over the term of the new 50-year license andgas purification sites is estimated to be on average, $11approximately $54 million which consists primarily of $48 million at ComEd.
As of December 31, 2021, the Registrants have established appropriate contingent liabilities for environmental remediation requirements. In addition, the Registrants may be required to $14 million per year, including capital and operatingmake significant additional expenditures not presently determinable for other environmental remediation costs. The actual timing and amount of a majority of these costs are not currently fixed and will vary from year to year throughout the life of the new license. Generation cannot currently predict when FERC will issue the new license. See Note 3 — Regulatory Matters and Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.information regarding the Registrants’ environmental matters, remediation efforts, and related impacts to the Registrants’ Consolidated Financial Statements. Pacific Gas & Electric Bankruptcy
Generation’s Antelope Valley,
Information about our Executive Officers as of February 25, 2022 Exelon | | | | | | | | | | | | | | | | | | | | | Name | | Age | | Position | | Period | Crane, Christopher M. | | 63 | | | Chief Executive Officer, Exelon; | | 2012 - Present | | | | | | | | | | | | | | | | | | | President, Exelon | | 2008 - Present | | | | | | | | | | | | | | | | | | | | | | Butler, Calvin G. | | 52 | | | Senior Executive Vice President, Exelon; Chief Operations Officer, Exelon | | 2021 - Present | | | | | Senior Executive Vice President, Exelon; Chief Executive Officer, Exelon Utilities | | 2019 - 2021 | | | | | Chief Executive Officer, BGE | | 2014 - 2019 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Glockner, David | | 61 | | | Executive Vice President, Compliance and Audit, Exelon | | 2020 - Present | | | | | Chief Compliance Officer, Citadel LLC | | 2017 - 2020 | | | | | Regional Director, U.S. Securities and Exchange Commission | | 2013 - 2017 | | | | | | | | Littleton, Gayle E. | | 49 | | | Executive Vice President, General Counsel, Exelon | | 2020- Present | | | | | Partner, Jenner & Block LLP | | 2015 -2020 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Quiniones, Gil | | 55 | | | Chief Executive Officer, ComEd | | 2021 - Present | | | | | President and Chief Executive Officer, New York Power Authority | | 2011 - 2021 | | | | | | | | Innocenzo, Michael A. | | 56 | | | President and Chief Executive Officer, PECO | | 2018 - Present | | | | | Senior Vice President and Chief Operations Officer, PECO | | 2012 - 2018 | | | | | | | | Khouzami, Carim V. | | 46 | | | Chief Executive Officer, BGE | | 2019 - Present | | | | | Senior Vice President, Chief Operating Officer, Exelon Utilities | | 2018 - 2019 | | | | | Senior Vice President, Chief Financial Officer, Exelon Utilities | | 2016 - 2018 | | | | | | | | Anthony, J. Tyler | | 57 | | | President and Chief Executive Officer, PHI | | 2021 - Present | | | | | Senior Vice President and Chief Operating Officer, PHI, Pepco, DPL, and ACE | | 2016 - 2021 | | | | | | | | Nigro, Joseph | | 57 | | | Senior Executive Vice President and Chief Financial Officer, Exelon | | 2018 - Present | | | | | Executive Vice President, Exelon; Chief Executive Officer, Constellation | | 2013 - 2018 | | | | | | | | Souza, Fabian E. | | 51 | | | Senior Vice President and Corporate Controller, Exelon | | 2018 - Present | | | | | Senior Vice President and Deputy Controller, Exelon | | 2017 - 2018 | | | | | Vice President, Controller and Chief Accounting Officer, The AES Corporation | | 2015 - 2017 |
ComEd | | | | | | | | | | | | | | | | | | | | | Name | | Age | | Position | | Period | Quiniones, Gil | | 55 | | | Chief Executive Officer, ComEd | | 2021 - Present | | | | | President and Chief Executive Officer, New York Power Authority | | 2011 - 2021 | | | | | | | | Donnelly, Terence R. | | 61 | | | President and Chief Operating Officer, ComEd | | 2018 - Present | | | | | Executive Vice President and Chief Operating Officer, ComEd | | 2012 - 2018 | | | | | | | | Trpik, Joseph | | 52 | | | Interim Senior Vice President, Chief Financial Officer and Treasurer, ComEd | | 2021 - Present | | | | | Senior Vice President, Chief Financial Officer, Exelon Utilities | | 2018 - Present | | | | | Senior Vice President, Chief Financial Officer and Treasurer, ComEd | | 2009 - 2018 | | | | | | | | Rippie, E. Glenn | | 61 | | | Senior Vice President and General Counsel, ComEd | | 2022 - Present | | | | | Partner, Jenner & Block LLP | | 2019 - 2021 | | | | | Partner and Chief Financial Officer, Rooney, Rippie & Ratnaswamy, LLP | | 2010 - 2019 | | | | | | | | Washington, Melissa | | 52 | | | Senior Vice President, Customer Operations and Chief Customer Officer, ComEd | | 2021 - Present | | | | | | | | | | | | Senior Vice President, Governmental and External Affairs, ComEd | | 2019 - 2021 | | | | | Vice President, Governmental and External Affairs, ComEd | | 2019 -2019 | | | | | Vice President, External Affairs and Large Customer Services, ComEd | | 2016 - 2019 | | | | | | | | Perez, David | | 52 | | | Senior Vice President, Distribution Operations, ComEd | | 2019 - Present | | | | | Vice President, Transmission and Substation, ComEd | | 2016 - 2019 | | | | | | | | Blaise, M. Michelle | | 60 | | | Senior Vice President, Technical Services, ComEd | | 2014 - Present | | | | | | | |
PECO | | | | | | | | | | | | | | | | | | | | | Name | | Age | | Position | | Period | Innocenzo, Michael A. | | 56 | | | President and Chief Executive Officer, PECO | | 2018 - Present | | | | | Senior Vice President and Chief Operations Officer, PECO | | 2012 - 2018 | | | | | | | | McDonald, John | | 64 | | | Senior Vice President and Chief Operations Officer, PECO | | 2018 - Present | | | | | Vice President, Integration, PHI | | 2016 - 2018 | Stefani, Robert J. | | 48 | | | Senior Vice President, Chief Financial Officer and Treasurer, PECO | | 2018 - Present | | | | | Vice President, Corporate Development, Exelon | | 2015 - 2018 | | | | | | | | Murphy, Elizabeth A. | | 62 | | | Senior Vice President, Governmental and External Affairs, PECO | | 2016 - Present | | | | | | | | | | | | | | | Webster Jr., Richard G. | | 60 | | | Vice President, Regulatory Policy and Strategy, PECO | | 2012 - Present | | | | | | | | | | | | | | | Williamson, Olufunmilayo | | 43 | | | Senior Vice President, Customer Operations, PECO | | 2020 - Present | | | | | Senior Vice President, Chief Commercial Risk Officer, Exelon | | 2017 - 2020 | | | | | Vice President, Commercial Risk Management, Exelon | | 2015 - 2017 | | | | | | | | Gay, Anthony | | 56 | | | Vice President and General Counsel, PECO | | 2019 - Present | | | | | | | | | | | | Vice President, Governmental and External Affairs, PECO | | 2016 - 2019 | | | | | | | |
BGE | | | | | | | | | | | | | | | | | | | | | Name | | Age | | Position | | Period | Khouzami, Carim V. | | 46 | | | Chief Executive Officer, BGE | | 2019 - Present | | | | | Senior Vice President, Chief Operating Officer, Exelon Utilities | | 2018 - 2019 | | | | | Senior Vice President, Chief Financial Officer, Exelon Utilities | | 2016 - 2018 | | | | | | | | Dickens, Derrick | | 56 | | | Senior Vice President and Chief Operating Officer, BGE | | 2021 - Present | | | | | Senior Vice President, Customer Operations, PHI | | 2020 - 2021 | | | | | Vice President, Technical Services, BGE | | 2016 - 2020 | | | | | | | | | | | | | | | Vahos, David M. | | 49 | | | Senior Vice President, Chief Financial Officer and Treasurer, BGE | | 2016 - Present | | | | | | | | | | | | | | | Núñez, Alexander G. | | 50 | | | Senior Vice President, Governmental, External and Regulatory Affairs, BGE | | 2021 - Present | | | | | Senior Vice President, Regulatory Affairs and Strategy, BGE | | 2020 - 2021 | | | | | Senior Vice President, Regulatory and External Affairs, BGE | | 2016 - 2020 | | | | | | | | Case, Mark D. | | 60 | | | Vice President, Strategy and Regulatory Affairs, BGE | | 2012 - Present | | | | | | | | | | | | | | | Galambos, Denise | | 59 | | | Senior Vice President, Customer Operations, BGE | | 2021 - Present | | | | | Vice President, Utility Oversight, Exelon Utilities | | 2020 - 2021 | | | | | VP, Human Resources, BGE | | 2018 - 2020 | | | | | Associate General Counsel, Exelon | | 2012 - 2017 | | | | | | | | Ralph, David | | 55 | | | Vice President and General Counsel, BGE | | 2021 - Present | | | | | Associate General Counsel, BGE | | 2019 - 2021 | | | | | Assistant General Counsel, Exelon | | 2017 - 2019 | | | | | City Attorney, City of Baltimore | | 2016 - 2017 |
PHI, Pepco, DPL, and ACE | | | | | | | | | | | | | | | | | | | | | Name | | Age | | Position | | Period | Anthony, J. Tyler | | 57 | | | President and Chief Executive Officer, PHI | | 2021 - Present | | | | | Senior Vice President and Chief Operating Officer, PHI, Pepco, DPL, and ACE | | 2016 - 2021 | | | | | | | | Olivier, Tamla | | 49 | | | Senior Vice President and Chief Operating Officer, PHI, Pepco, DPL, and ACE | | 2021 - Present | | | | | Senior Vice President, Customer Operations, BGE | | 2020 - 2021 | | | | | Senior Vice President, Constellation NewEnergy, Inc. | | 2016 - 2020 | | | | | | | | Barnett, Phillip S. | | 58 | | | Senior Vice President, Chief Financial Officer and Treasurer, PHI, Pepco, DPL, and ACE | | 2018 - Present | | | | | Senior Vice President and Chief Financial Officer, PECO | | 2007 - 2018 | | | | | Treasurer, PECO | | 2012 - 2018 | | | | | | | | Oddoye, Rodney | | 45 | | | Senior Vice President, Governmental & External Affairs, PHI, Pepco, DPL, and ACE | | 2021 - Present | | | | | Senior Vice President, Governmental and External Affairs, BGE | | 2020 - 2021 | | | | | Vice President, Customer Operations, BGE | | 2018 - 2020 | | | | | Director, Northeast Regional Electric Operations, BGE | | 2016 - 2018 | | | | | | | | Bancroft, Anne | | 55 | | | Vice President and General Counsel, PHI | | 2021 - Present | | | | | Associate General Counsel, Exelon | | 2017 - 2021 | | | | | Assistant General Counsel, Exelon | | 2010 - 2017 | | | | | | | | Bell-Izzard, Morlon | | 56 | | | Senior Vice President, Customer Operations & Chief Customer Officer, PHI | | 2021 - Present | | | | | Vice President, Customer Operations, PHI | | 2019 - 2021 | | | | | Director, Utility Performance Assessment, Exelon | | 2016 - 2019 | | | | | | | | O'Donnell, Morgan | | 46 | | | Vice President, Regulatory Policy and Strategy, DC/MD | | 2021 - Present | | | | | Director, Financial Planning and Analysis, PHI | | 2020 - 2021 | | | | | Director, Regulatory Strategy & Revenue Policy, PHI | | 2019 - 2020 | | | | | Manager, Regulatory Analysis, PHI | | 2016 - 2019 | | | | | | | | Humphrey, Marissa | | 42 | | Vice President, Regulatory Policy and Strategy, PHI, DPL, and ACE | | 2021 - Present | | | | | Vice President Finance, Exelon Utilities | | 2019 - 2020 | | | | | Vice President, Finance, PHI | | 2016 - 2019 | | | | | | | |
On February 21, 2021, Exelon’s Board of Directors approved a 242 MW solar facility in Lancaster, CA, sells all of its outputplan to PG&E through a PPA. On January 29, 2019, PG&E filed for protection under Chapter 11separate the Utility Registrants and Generation, creating two publicly traded companies. The separation was completed on February 1, 2022. See Note 26 — Separation of the U.S. Bankruptcy Code.Combined Notes to Consolidated Financial Statements for additional information. As such, the risk factors discussed below do not include those associated with Generation. Each of the Registrants operates in a complex market and regulatory environment that involves significant risks, many of which are beyond that Registrant’s direct control. Such risks, which could negatively affect one or more of the Registrants’ consolidated financial statements, fall primarily under the categories below:
Risks related to market and financial factors primarily include: •the demand for electricity, reliability of service, and affordability in the markets where the Utility Registrants conduct their business, •the ability of the Utility Registrants to operate their respective transmission and distribution assets, their ability to access capital markets, and the impacts on their results of operations due to the global outbreak (pandemic) of the 2019 novel coronavirus (COVID-19), and •emerging technologies and business models, including those related to climate change mitigation and transition to a low carbon economy. Risks related to legislative, regulatory, and legal factors primarily include changes to, and compliance with, the laws and regulations that govern: •utility regulatory business models, •environmental and climate policy, and •tax policy. Risks related to operational factors primarily include: •changes in the global climate could produce extreme weather events, which could put the Registrant’s facilities at risk, and such changes could also affect the levels and patterns of demand for energy and related services, •the ability of the Utility Registrants to maintain the reliability, resiliency, and safety of their energy delivery systems, which could affect their ability to deliver energy to their customers and affect their operating costs, and •physical and cyber security risks for the Utility Registrants as the owner-operators of transmission and distribution facilities. Risks related to the separation primarilyinclude: •challenges to achieving the benefits of separation and •performance by Exelon and Generation under the transaction agreements, including indemnification responsibilities. There may be further risks and uncertainties that are not presently known or that are not currently believed to be material that could negatively affect the Registrants' consolidated financial statements in the future. Risks Related to Market and Financial Factors The Registrants are potentially affected by emerging technologies that could over time affect or transform the energy industry (All Registrants). Advancements in power generation technology, including commercial and residential solar generation installations and commercial micro turbine installations, are improving the cost-effectiveness of customer self-supply of electricity. Improvements in energy storage technology, including batteries and fuel cells, could also better position customers to meet their around-the-clock electricity requirements. Improvements in energy efficiency of lighting, appliances, equipment and building materials will also affect energy consumption by customers. Changes in power generation, storage, and use technologies could have significant effects on customer behaviors and their energy consumption. These developments could affect levels of customer-owned generation, customer expectations, and current business models and make portions of the Utility Registrants' transmission and/or distribution facilities uneconomic prior to the end of their useful lives. These factors could affect the Registrants’ consolidated financial statements through, among other things, increased operating and maintenance expenses, increased capital
expenditures, and potential asset impairment charges or accelerated depreciation over shortened remaining asset useful lives. Market performance and other factors could decrease the value of employee benefit plan assets and could increase the related employee benefit plan obligations, which then could require significant additional funding (All Registrants). Disruptions in the capital markets and their actual or perceived effects on particular businesses and the greater economy could adversely affect the value of the investments held within Exelon’s employee benefit plan trusts. The asset values are subject to market fluctuations and will yield uncertain returns, which could fall below Exelon's projected return rates. A decline in the market value of the pension and OPEB plan assets would increase the funding requirements associated with Exelon’s pension and OPEB plan obligations. Additionally, Exelon’s pension and OPEB plan liabilities are sensitive to changes in interest rates. As interest rates decrease, the liabilities increase, potentially increasing benefit costs and funding requirements. Changes in demographics, including increased numbers of retirements or changes in life expectancy assumptions or changes to Social Security or Medicare eligibility requirements could also increase the costs and funding requirements of the obligations related to the pension and OPEB plans. See Note 15 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information. The Registrants could be negatively affected by unstable capital and credit markets (All Registrants). The Registrants rely on the capital markets, particularly for publicly offered debt, as well as the banking and commercial paper markets, to meet their financial commitments and short-term liquidity needs. Disruptions in the capital and credit markets in the United States or abroad could negatively affect the Registrants’ ability to access the capital markets or draw on their respective bank revolving credit facilities. The banks may not be able to meet their funding commitments to the Registrants if they experience shortages of capital and liquidity or if they experience excessive volumes of borrowing requests within a short period of time. The inability to access capital markets or credit facilities, and longer-term disruptions in the capital and credit markets as a result of uncertainty, changing or increased regulation, reduced alternatives, or failures of significant financial institutions could result in the deferral of discretionary capital expenditures, or require a reduction in dividend payments or other discretionary uses of cash. In addition, the Registrants have exposure to worldwide financial markets, including Europe, Canada, and Asia. Disruptions in these markets could reduce or restrict the Registrants’ ability to secure sufficient liquidity or secure liquidity at reasonable terms. As of December 31, 2019, Generation had2021, approximately $725 million20%, 17%, and $485 million of net long-lived assets and nonrecourse debt outstanding, respectively, related to Antelope Valley. PG&E’s bankruptcy created an event of default for Antelope Valley’s nonrecourse debt that provides the lender with a right to accelerate amounts outstanding under the loan such that they would become immediately due and payable. As a result16% of the ongoing event of defaultRegistrants’ available credit facilities (not including Generation's credit facilities) were with European, Canadian, and the absence of a waiver from the lender foregoing their acceleration rights, the debt was reclassified as current in Exelon’s and Generation’s Consolidated Balance Sheets in the first quarter of 2019 and continues to be classified as current as of December 31, 2019. In the first quarter of 2019, Generation assessed and determined that Antelope Valley’s long-lived assets were not impaired. Significant changes in assumptions such as the likelihood of the PPA being rejected as part of the bankruptcy proceedings could potentially result in future impairments of Antelope Valley's net long-lived assets, which could be material. Generation is monitoring the bankruptcy proceedings for any changes in circumstances that would indicate the carrying amount of the net long-lived assets of Antelope Valley may not be recoverable.
Asian banks, respectively. See Note 1117 — Asset Impairments and Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the PG&E bankruptcy.credit facilities. If any of the Registrants were to experience a downgrade in its credit ratings to below investment grade or otherwise fail to satisfy the credit standards in its agreements with its counterparties or regulatory financial requirements, it would be required to provide significant amounts of collateral that could affect its liquidity and could experience higher borrowing costs (All Registrants). Exelon’s StrategyThe Utility Registrants' operating agreements with PJM and OutlookPECO's, BGE's, and DPL's natural gas procurement contracts contain collateral provisions that are affected by their credit rating and market prices. If certain wholesale market conditions were to exist and the Utility Registrants were to lose their investment grade credit ratings (based on their senior unsecured debt ratings), they would be required to provide collateral in the forms of letters of credit or cash, which could have a material adverse effect upon their remaining sources of liquidity. PJM collateral posting requirements will generally increase as market prices rise and decrease as market prices fall. Collateral posting requirements for 2020PECO, BGE, and Beyond
Exelon’s value propositionDPL, with respect to their natural gas supply contracts, will generally increase as forward market prices fall and competitive advantage come from its scope and its core strengthsdecrease as forward market prices rise. If the Utility Registrants were downgraded, they could experience higher borrowing costs as a result of operational excellence and financial discipline. Exelon leverages its integrated business model to create value. Exelon’s regulated and competitive businesses feature a mixthe downgrade. In addition, changes in ratings methodologies by the agencies could also have an adverse negative impact on the ratings of attributes that, when combined, offer shareholders and customers a unique value proposition:the Utility Registrants.
The Utility Registrants provideconduct their respective businesses and operate under governance models and other arrangements and procedures intended to assure that the Utility Registrants are treated as separate,
independent companies, distinct from Exelon and other Exelon subsidiaries in order to isolate the Utility Registrants from Exelon and other Exelon subsidiaries in the event of financial difficulty at Exelon or another Exelon subsidiary. These measures (commonly referred to as “ring-fencing”) could help avoid or limit a foundationdowngrade in the credit ratings of the Utility Registrants in the event of a reduction in the credit rating of Exelon. Despite these ring-fencing measures, the credit ratings of the Utility Registrants could remain linked, to some degree, to the credit ratings of Exelon. Consequently, a reduction in the credit rating of Exelon could result in a reduction of the credit rating of some or all of the Utility Registrants. A reduction in the credit rating of a Utility Registrant could have a material adverse effect on the Utility Registrant. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Liquidity and Capital Resources — Credit Matters — Market Conditions and Security Ratings for steadily growing earnings,additional information regarding the potential impacts of credit downgrades on the Registrants’ cash flows. The impacts of significant economic downturns or increases in customer rates, could lead to decreased volumes delivered and increased expense for uncollectible customer balances (All Registrants). The impacts of significant economic downturns on the Utility Registrants' customers and the related regulatory limitations on residential service terminations for the Utility Registrants, could result in an increase in the number of uncollectible customer balances and related expense. Further, increases in customer rates, including those related to increases in purchased power and natural gas prices, could result in declines in customer usage and lower revenues for the Utility Registrants that do not have decoupling mechanisms. See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for additional information on the Registrants’ credit risk. The Registrants' results were negatively affected by the impacts of COVID-19 (All Registrants). COVID-19 has disrupted economic activity in the Registrants’ respective markets and negatively affected the Registrants’ results of operations. The estimated impact of COVID-19 to the Utility Registrants’ Net income was approximately $75 million for the year ended December 31, 2020 and was not material for the year ended December 31, 2021. The Registrants cannot predict the full extent of the impacts of COVID-19, which translateswill depend on, among other things, the rate, and public perceptions of the effectiveness, of vaccinations and rate of resumption of business activity. In addition, any future widespread pandemic or other local or global health issue could adversely affect customer demand and the Registrants’ ability to operate their transmission and distribution assets. See Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - Executive Overview for additional information. The Registrants could be negatively affected by the impacts of weather (All Registrants). Weather conditions directly influence the demand for electricity and natural gas and affect the price of energy commodities. Temperatures above normal levels in the summer tend to increase summer cooling electricity demand and revenues, and temperatures below normal levels in the winter tend to increase winter heating electricity and gas demand and revenues. Moderate temperatures adversely affect the usage of energy and resulting operating revenues at PECO and DPL Delaware. Due to revenue decoupling, operating revenues from electric distribution at ComEd, BGE, Pepco, DPL Maryland, and ACE are not affected by abnormal weather. Extreme weather conditions or damage resulting from storms could stress the Utility Registrants' transmission and distribution systems, communication systems, and technology, resulting in increased maintenance and capital costs and limiting each company’s ability to meet peak customer demand. First and third quarter financial results, in particular, are substantially dependent on weather conditions, and could make period comparisons less relevant. 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 the Utility Registrants have transmission and distribution assets. The frequency in which weather conditions emerge outside the current expected climate norms could contribute to weather-related impacts discussed above.
Long-lived assets, goodwill, and other assets could become impaired (All Registrants). Long-lived assets represent the single largest asset class on the Registrants’ statements of financial position. In addition, Exelon, ComEd, and PHI have material goodwill balances. The Registrants evaluate the recoverability of the carrying value of long-lived assets to be held and used whenever events or circumstances indicating a potential impairment exist. Factors such as, but not limited to, the business climate, including current and future energy and market conditions, environmental regulation, and the condition of assets are considered. ComEd and PHI perform an assessment for possible impairment of their goodwill at least annually or more frequently if an event occurs or circumstances change that would more likely than not reduce the fair value of the reporting units below their carrying amount. Regulatory actions or changes in significant assumptions, including discount and growth rates, utility sector market performance and transactions, projected operating and capital cash flows for ComEd’s, Pepco’s, DPL’s, and ACE’s business, and the fair value of debt, could potentially result in future impairments of Exelon’s, ComEd's, and PHI’s goodwill. An impairment would require the Registrants to reduce the carrying value of the long-lived asset or goodwill to fair value through a non-cash charge to expense by the amount of the impairment. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Critical Accounting Policies and Estimates, Note 8 — Property, Plant, and Equipment, Note 12 — Asset Impairments and Note 13 — Intangible Assets of the Combined Notes to the Consolidated Financial Statements for additional information on long-lived asset impairments and goodwill impairments. The Registrants could incur substantial costs in the event of non-performance by third-parties under indemnification agreements, or when the Registrants have guaranteed their performance (All Registrants). The Registrants have entered into various agreements with counterparties that require those counterparties to reimburse a Registrant and hold it harmless against specified obligations and claims. To the extent that any of these counterparties are affected by deterioration in their creditworthiness or the agreements are otherwise determined to be unenforceable, the affected Registrant could be held responsible for the obligations. Each of the Utility Registrants has transferred its former generation business to a stable currencythird party and in our stock.each case the transferee has agreed to assume certain obligations and to indemnify the applicable Utility Registrant for such obligations. In connection with the restructurings under which ComEd, PECO, and BGE transferred their generating assets to Generation, Generation assumed certain of ComEd’s, PECO’s, and BGE's rights and obligations with respect to their former generation businesses. Further, ComEd, PECO, and BGE have entered into agreements with third parties under which the third-party agreed to indemnify ComEd, PECO, or BGE for certain obligations related to their respective former generation businesses that have been assumed by Generation as part of the restructuring. If the third-party, Generation, or the transferee of Pepco's, DPL's, or ACE’s generation facilities experienced events that reduced its creditworthiness or the indemnity arrangement became unenforceable, the applicable Utility Registrant could be liable for any existing or future claims. In addition, the Utility Registrants have residual liability under certain laws in connection with their former generation facilities. Generation’s competitive businesses provide free cash flowThe Registrants have issued indemnities to invest primarilythird parties regarding environmental or other matters in connection with purchases and sales of assets, including several of the Utility Registrants in connection with Generation's absorption of their former generating assets. The Registrants could incur substantial costs to fulfill their obligations under these indemnities.
The Registrants have issued guarantees of the performance of third parties, which obligate the Registrants to perform in the utilitiesevent that the third parties do not perform. In the event of non-performance by those third parties, the Registrants could incur substantial cost to fulfill their obligations under these guarantees.
Risks Related to Legislative, Regulatory, and Legal Factors The Registrants' businesses are highly regulated and could be negatively affected by legislative and/or regulatory actions (All Registrants). Substantial aspects of the Registrants' businesses are subject to reduce debt.comprehensive Federal or state legislation and/or regulation. Exelon believes its strategy provides a platformThe Utility Registrants' consolidated financial statements are heavily dependent on the ability of the Utility Registrants to recover their costs for optimal successthe retail purchase and distribution of power and natural gas to their customers.
Fundamental changes in an energy industry experiencing fundamentalregulations or adverse legislative actions affecting the Registrants’ businesses would require changes in their business planning models and sweeping change.operations. The Registrants cannot predict when or whether legislative or regulatory proposals could become law or what their effect would be on the Registrants. Exelon’s utility strategy isChanges in the Utility Registrants' respective terms and conditions of service, including their respective rates, are subject to improve reliabilityregulatory approval proceedings and/or negotiated settlements that are at times contentious, lengthy, and operationssubject to appeal, which lead to uncertainty as to the ultimate result and enhance the customer experience, while ensuring ratemaking mechanisms provide the utilities fair financial returns. which could introduce time delays in effectuating rate changes (All Registrants).
The Utility Registrants only investare required to engage in regulatory approval proceedings as a part of the process of establishing the terms and rates for their respective services. These proceedings typically involve multiple parties, including governmental bodies and officials, consumer advocacy groups, and various consumers of energy, who have differing concerns but who have the common objective of limiting rate baseincreases or even reducing rates. Decisions are subject to appeal, potentially leading to additional uncertainty associated with the approval proceedings. The potential duration of such proceedings creates a risk that rates ultimately approved by the applicable regulatory body may not be sufficient for a Utility Registrant to recover its costs by the time the rates become effective. Established rates are also subject to subsequent prudency reviews by state regulators, whereby various portions of rates could be adjusted, subject to refund or disallowed, including recovery mechanisms for costs associated with the procurement of electricity or gas, credit losses, MGP remediation, smart grid infrastructure, and energy efficiency and demand response programs. In certain instances, the Utility Registrants could agree to negotiated settlements related to various rate matters, customer initiatives, or franchise agreements. These settlements are subject to regulatory approval. The ultimate outcome and timing of regulatory rate proceedings have a significant effect on the ability of the Utility Registrants to recover their costs or earn an adequate return. See Note 3 — Regulatory Matters of the Combined Notes to the Consolidated Financial Statements for additional information. The Registrants could be subject to higher costs and/or penalties related to mandatory reliability standards, including the likely exposure of the Utility Registrants to the results of PJM’s RTEP and NERC compliance requirements (All Registrants). The Utility Registrants as users, owners, and operators of the bulk power transmission system are subject to mandatory reliability standards promulgated by NERC and enforced by FERC. PECO, BGE, and DPL, as operators of natural gas distribution systems, are also subject to mandatory reliability standards of the U.S. Department of Transportation. The standards are based on the functions that need to be performed to ensure the bulk power system operates reliably and are guided by reliability and market interface principles. Compliance with or changes in the reliability standards could subject the Registrants to higher operating costs and/or increased capital expenditures. In addition, the ICC, PAPUC, MDPSC, DCPSC, DEPSC, and NJBPU impose certain distribution reliability standards on the Utility Registrants. If the Utility Registrants were found in non-compliance with the Federal and state mandatory reliability standards, they could be subject to remediation costs as well as sanctions, which could include substantial monetary penalties.
The Registrants could incur substantial costs to fulfill their obligations related to environmental and other matters (All Registrants). The Registrants are subject to extensive environmental regulation and legislation by local, state, and Federal authorities. These laws and regulations affect the manner in which the Registrants conduct their operations and make capital expenditures including how they handle air and water emissions, hazardous and solid waste, and activities affecting surface waters, groundwater, and aquatic and other species. Violations of these requirements could subject the Registrants to enforcement actions, capital expenditures to bring existing facilities into compliance, additional operating costs for remediation and clean-up costs, civil penalties and exposure to third parties’ claims for alleged health or property damages, or operating restrictions to achieve compliance. In addition, the Registrants are subject to liability under these laws for the remediation costs for environmental contamination of property now or formerly owned by the Registrants and of property contaminated by hazardous substances they generated or released. Remediation activities associated with MGP operations conducted by predecessor companies are one component of such costs. Also, the Registrants are currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and could be subject to additional proceedings in the future. See ITEM 1. BUSINESS — Environmental Matters and Regulation for additional information. The Registrants could be negatively affected by federal and state RPS and/or energy conservation legislation, along with energy conservation by customers (All Registrants). Changes to current state legislation or the development of Federal legislation that requires the use of clean, renewable, and alternate fuel sources could significantly impact the Utility Registrants, especially if timely cost recovery is not allowed. Federal and state legislation mandating the implementation of energy conservation programs that require the implementation of new technologies, such as smart meters and smart grid, could increase capital expenditures and could significantly impact the Utility Registrants consolidated financial statements if timely cost recovery is not allowed. These energy conservation programs, regulated energy consumption reduction targets, and new energy consumption technologies could cause declines in customer energy consumption and lead to a decline in the Registrants' revenues. See ITEM 1. BUSINESS — Environmental Matters and Regulation — Renewable and Clean Energy Standards and "The Registrants are potentially affected by emerging technologies that could over time affect or transform the energy industry" above for additional information. The Registrants could be negatively affected by challenges to tax positions taken, tax law changes, and the inherent difficulty in quantifying potential tax effects of business decisions. (All Registrants). The Registrants are required to make judgments in order to estimate their obligations to taxing authorities. These tax obligations include income, real estate, sales and use, and employment-related taxes and ongoing appeal issues related to these tax matters. These judgments include reserves established for potential adverse outcomes regarding tax positions that have been taken that could be subject to challenge by the tax authorities. See Note 1 — Significant Accounting Policies and Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information. Legal proceedings could result in a negative outcome, which the Registrants cannot predict (All Registrants). The Registrants are involved in legal proceedings, claims, and litigation arising out of their business operations. The material ones are summarized in Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements. Adverse outcomes in these proceedings could require significant expenditures, result in lost revenue, or restrict existing business activities. The Registrants could be subject to adverse publicity and reputational risks, which make them vulnerable to negative customer perception and could lead to increased regulatory oversight or other consequences (All Registrants).
The Registrants could be the subject of public criticism. Adverse publicity of this nature could render public service commissions and other regulatory and legislative authorities less likely to view energy companies in a favorable light, and could cause those companies, including the Registrants, to be susceptible to less favorable legislative and regulatory outcomes, as well as increased regulatory oversight and more stringent legislative or regulatory requirements. Exelon and ComEd have received requests for information related to an SEC investigation into their lobbying activities. The outcome of the investigations could have a material adverse effect on their reputation and consolidated financial statements (Exelon and ComEd). On October 22, 2019, the SEC notified Exelon and ComEd that it had opened an investigation into their lobbying activities in the state of Illinois. Exelon and ComEd have cooperated fully, including by providing all information requested by the SEC, and intend to continue to cooperate fully and expeditiously with the SEC. The outcome of the SEC’s investigation cannot be predicted and could subject Exelon and ComEd to civil penalties, sanctions, or other remedial measures. Any of the foregoing, as well as the appearance of non-compliance with anti-corruption and anti-bribery laws, could have an adverse impact on Exelon’s and ComEd’s reputations or relationships with regulatory and legislative authorities, customers, and other stakeholders, as well as their consolidated financial statements. See Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements. If ComEd violates its Deferred Prosecution Agreement announced on July 17, 2020, it could have an adverse effect on the reputation and consolidated financial statements of Exelon and ComEd (Exelon and ComEd). On July 17, 2020, ComEd entered into a Deferred Prosecution Agreement (DPA) with the U.S. Attorney’s Office for the Northern District of Illinois (USAO) to resolve the USAO’s investigation into Exelon’s and ComEd’s lobbying activities in the State of Illinois. Exelon was not made a party to the DPA and the investigation by the USAO into Exelon’s activities ended with no charges being brought against Exelon. 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 benefitthree-year period subject to certain obligations of ComEd, including, but not limited to, the following: (i) payment to the United States Treasury of $200 million; (ii) continued full cooperation with the government’s investigation; and (iii) ComEd’s adoption and maintenance of remedial measures involving compliance and reporting undertakings as specified in the DPA. If ComEd is found to have breached the terms of the DPA, the USAO may elect to prosecute, or bring a civil action against, ComEd for conduct alleged in the DPA or known to the government, which could result in fines or penalties and could have an adverse impact on Exelon’s and ComEd’s reputation or relationships with regulatory and legislative authorities, customers and other stakeholders, as well as their consolidated financial statements. See Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements. Risks Related to Operational Factors The Registrants are subject to risks associated with climate change (All Registrants). Climate adaptation risk refers to risks to the Registrants' facilities or operations that may result from changes in the physical climate, such as changes to temperature, weather patterns and sea level. The Registrants periodically perform analyses to better understand how climate change could affect their facilities and operations. The Registrants primarily operate in the Midwest and East Coast of the United States, areas that historically have been prone to various types of severe weather events, and as such the Registrants have well-developed response and recovery programs based on these historical events. However, the Registrants’ physical facilities could be placed at greater risk of damage should changes in the global climate impact temperature and weather patterns, and result in more intense, frequent and extreme weather events, unprecedented levels of precipitation, sea level rise, increased surface water temperatures, and/or other effects.
Over time, the Registrants may need to make additional investments to protect their facilities from physical climate-related risks. In addition, changes to the climate may impact levels and patterns of demand for energy and related services, which could affect Registrants’ operations. Over time, the Registrants may need to make additional investments to adapt to changes in operational requirements as a result of climate change. Climate mitigation and transition risks include changes to the energy systems as a result of new technologies, changing customer expectations and/or voluntary GHG goals, as well as local, state or federal regulatory requirements intended to reduce GHG emissions. The Registrants also periodically perform analyses of potential pathways to reduce power sector and economy-wide GHG emissions to mitigate climate change. To the extent additional GHG reduction legislation and/or regulation becomes effective at the Federal and/or state levels, the Registrants could incur costs to further limit the GHG emissions from their operations or otherwise comply with applicable requirements. See ITEM 1. BUSINESS — Environmental Matters and Regulation — Climate Change and "The Registrants are potentially affected by emerging technologies that could over time affect or transform the energy industry" above for additional information. The Utility Registrants' operating costs are affected by their ability to maintain the availability and reliability of their delivery and operational systems (All Registrants). Failures of the equipment or facilities used in the Utility Registrants' delivery systems could interrupt the electric transmission and electric and natural gas delivery, which could result in a loss of revenues and an increase in maintenance and capital expenditures. Equipment or facilities failures can be due to a number of factors, including natural causes such as weather or information systems failure. Specifically, if the implementation of AMI, smart grid, or other technologies in the Utility Registrants' service territory fail to perform as intended or are not successfully integrated with billing and other information systems, or if any of the financial, accounting, or other data processing systems fail or have other significant shortcomings, the Utility Registrants' financial results could be negatively impacted. In addition, dependence upon automated systems could further increase the risk that operational system flaws or internal and/or external tampering or manipulation of those systems will result in losses that are difficult to detect. Regulated utilities, which are required to provide service to all customers within their service territory, have generally been afforded liability protections against claims by customers relating to failure of service. Under Illinois law, however, ComEd could be required to pay damages to its customers in some circumstances involving extended outages affecting large numbers of its customers, which could be material. The Registrants are subject to physical security and cybersecurity risks (All Registrants). The Registrants face physical security and cybersecurity risks. Threat sources continue to seek to exploit potential vulnerabilities in the electric and natural gas utility 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 advanced digital technologies increases the potentially unfavorable impacts of such attacks. 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. The Registrants’ employees, contractors, customers, and the community by improving reliabilitygeneral public could be exposed to a risk of injury due to the nature of the energy industry (All Registrants). Employees and contractors throughout the organization work in, and customers and the general public could be exposed to, potentially dangerous environments near the Registrants’ operations. As a result, employees, contractors, customers, and the general public are at some risk for serious injury, including loss of life. These risks include gas explosions, pole strikes, and electric contact cases. Natural disasters, war, acts and threats of terrorism, pandemic, and other significant events could negatively impact the Registrants' results of operations, ability to raise capital and future growth (All Registrants). The Utility Registrants' distribution and transmission infrastructures could be affected by natural disasters and extreme weather events, which could result in increased costs, including supply chain costs. An extreme weather event within the Utility Registrants’ service experienceareas can also directly affect their capital assets, causing disruption in service to customers due to downed wires and poles or otherwise meetingdamage to other operating equipment. The impact that potential terrorist attacks could have on the industry and the Registrants is uncertain. The Registrants face a risk that their operations would be direct targets or indirect casualties of an act of terror. Any retaliatory military strikes or sustained military campaign could affect their operations in unpredictable ways, such as changes in insurance markets and disruptions of fuel supplies and markets, particularly oil. Furthermore, these catastrophic events could compromise the physical or cybersecurity of the Registrants' facilities, which could adversely affect the Registrants' ability to manage their businesses effectively. Instability in the financial markets as a result of terrorism, war, natural disasters, pandemic, credit crises, recession, or other factors also could result in a decline in energy consumption or interruption of fuel or the supply chain. In addition, the implementation of security guidelines and measures has resulted in and is expected to continue to result in increased costs. The Registrants could be significantly affected by the outbreak of a pandemic. Exelon has plans in place to respond to a pandemic. However, depending on the severity of a pandemic and the resulting impacts to workforce and other resource availability, the ability to operate Exelon's transmission and distribution assets could be adversely affected. See "The Registrants' results were negatively affected by the impacts of COVID-19" above for additional information. In addition, Exelon maintains a level of insurance coverage consistent with industry practices against property, casualty and cybersecurity losses subject to unforeseen occurrences or catastrophic events that could damage or destroy assets or interrupt operations. However, there can be no assurance that the amount of insurance will be adequate to address such property and casualty losses. The Registrants’ businesses are capital intensive, and their assets could require significant expenditures to maintain and are subject to operational failure, which could result in potential liability (All Registrants). The Utility Registrants’ businesses are capital intensive and require significant investments in transmission and distribution infrastructure projects. Equipment, even if maintained in accordance with good utility practices, is subject to operational failure, including events that are beyond the Utility Registrants’ control, and could require significant expenditures to operate efficiently. The Registrants consolidated financial statements could be negatively affected if they were unable to effectively manage their capital projects or raise the necessary capital.
See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Liquidity and Capital Resources for additional information regarding the Registrants’ potential future capital expenditures. The Utility Registrants' respective ability to deliver electricity, their operating costs, and their capital expenditures could be negatively impacted by transmission congestion and failures of neighboring transmission systems (All Registrants). Demand for electricity within the Utility Registrants' service areas could stress available transmission capacity requiring alternative routing or curtailment of electricity usage. Also, insufficient availability of electric supply to meet customer needs. demand could jeopardize the Utility Registrants' ability to comply with reliability standards and strain customer and regulatory agency relationships. As with all utilities, potential concerns over transmission capacity or generation facility retirements could result in PJM or FERC requiring the Utility Registrants to upgrade or expand their respective transmission systems through additional capital expenditures. PJM’s systems and operations are designed to ensure the reliable operation of the transmission grid and prevent the operations of one utility from having an adverse impact on the operations of the other utilities. However, service interruptions at other utilities may cause interruptions in the Utility Registrants’ service areas. The Registrants' performance could be negatively affected if they fail to attract and retain an appropriately qualified workforce (All Registrants). Certain events, such as the separation transaction, an employee strike, loss of employees, loss of contract resources due to a major event, and an aging workforce without appropriate replacements, could lead to operating challenges and increased costs for the Registrants. The challenges include lack of resources, loss of knowledge and a lengthy time period associated with skill development. In this case, costs, including costs for contractors to replace employees, productivity costs, and safety costs, could arise. The Registrants are particularly affected due to the specialized knowledge required of the technical and support employees for their transmission and distribution operations. The Registrants could make acquisitions or investments in new business initiatives and new markets, which may not be successful or achieve the intended financial results (All Registrants). The Utility Registrants make these investments atface risks associated with their regulatory-mandated initiatives, such as smart grids and utility of the lowest reasonablefuture. These risks include, but are not limited to, cost recovery, regulatory concerns, cybersecurity, and obsolescence of technology. Such initiatives may not be successful. Risks Related to customers.the Separation (Exelon) The separation may not achieve some or all of the benefits anticipated by Exelon seeksand, following the separation, Exelon's common stock price may underperform relative to leverage its scale and expertise across the utilities platform through enhanced standardization and sharing of resources and best practices to achieve improved operational and financial results. Additionally,Exelon's expectations. By separating the Utility Registrants anticipate makingand Generation, Exelon created two publicly traded companies with the resources necessary to best serve customers and sustain long-term investment and operating excellence. The separate companies are expected to create value by having the strategic flexibility to focus on their unique customer, market and community priorities. However, the separation may not provide such results on the scope or scale that Exelon anticipates, and Exelon may not realize the anticipated benefits of the separation. Failure to do so could have a material adverse effect on Exelon's financial statements and its common stock price. In connection with the separation into two public companies, Exelon and Generation will indemnify each other for certain liabilities. If Exelon is required to pay under these indemnities to Generation, Exelon's financial results could be negatively impacted. The Generation indemnities may not be sufficient to hold Exelon harmless from the full amount of liabilities for which Generation will be allocated responsibility, and Generation may not be able to satisfy its indemnification obligations in the future.
Pursuant to the separation agreement and certain other agreements between Exelon and Generation, each party will agree to indemnify the other for certain liabilities, in each case for uncapped amounts. Indemnities that Exelon may be required to provide Generation are not subject to any cap, may be significant future investmentsand could negatively impact its business. Third parties could also seek to hold Exelon responsible for any of the liabilities that Generation has agreed to retain. Any amounts Exelon is required to pay pursuant to these indemnification obligations and other liabilities could require Exelon to divert cash that would otherwise have been used in smart grid technology,furtherance of its operating business. Further, the indemnities from Generation for Exelon's benefit may not be sufficient to protect Exelon against the full amount of such liabilities, and Generation may not be able to fully satisfy its indemnification obligations. Moreover, even if Exelon ultimately succeeds in recovering from Generation any amounts for which Exelon is held liable, Exelon may be temporarily required to bear these losses. Each of these risks could negatively affect Exelon's business, results of operations and financial condition. | | | | | | ITEM 1B. | UNRESOLVED STAFF COMMENTS |
All Registrants None.
Generation The following table presents Generation’s interests in net electric generating capacity by station at December 31, 2021: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Station(a) | | Location | | No. of Units | | Percent Owned(b) | | Primary Fuel Type | | Primary Dispatch Type(c) | | Net Generation Capacity (MW)(d) | | Midwest | | | | | | | | | | | | | | Braidwood | | Braidwood, IL | | 2 | | | | | Uranium | | Base-load | | 2,386 | | | Byron | | Byron, IL | | 2 | | | | | Uranium | | Base-load | | 2,347 | | (e) | LaSalle | | Seneca, IL | | 2 | | | | | Uranium | | Base-load | | 2,320 | | | Dresden | | Morris, IL | | 2 | | | | | Uranium | | Base-load | | 1,845 | | (e) | Quad Cities | | Cordova, IL | | 2 | | | 75 | | | Uranium | | Base-load | | 1,403 | | (f) | Clinton | | Clinton, IL | | 1 | | | | | Uranium | | Base-load | | 1,080 | | | Michigan Wind 2 | | Sanilac Co., MI | | 50 | | | 51 | | (g) | Wind | | Intermittent | | 46 | | (f) | Beebe | | Gratiot Co., MI | | 34 | | | 51 | | (g) | Wind | | Intermittent | | 42 | | (f) | Michigan Wind 1 | | Huron Co., MI | | 46 | | | 51 | | (g) | Wind | | Intermittent | | 35 | | (f) | Harvest 2 | | Huron Co., MI | | 33 | | | 51 | | (g) | Wind | | Intermittent | | 30 | | (f) | Harvest | | Huron Co., MI | | 32 | | | 51 | | (g) | Wind | | Intermittent | | 27 | | (f) | Beebe 1B | | Gratiot Co., MI | | 21 | | | 51 | | (g) | Wind | | Intermittent | | 26 | | (f) | Blue Breezes | | Faribault Co., MN | | 2 | | | | | Wind | | Intermittent | | 3 | | | CP Windfarm | | Faribault Co., MN | | 2 | | | 51 | | (g) | Wind | | Intermittent | | 2 | | (f) | Southeast Chicago | | Chicago, IL | | 8 | | | | | Gas | | Peaking | | 296 | | (h) | Clinton Battery Storage | | Blanchester, OH | | 1 | | | | | Energy Storage | | Peaking | | 10 | | | Total Midwest | | | | | | | | | | | | 11,898 | | | | | | | | | | | | | | | | | Mid-Atlantic | | | | | | | | | | | | | | Limerick | | Sanatoga, PA | | 2 | | | | | Uranium | | Base-load | | 2,317 | | | Calvert Cliffs | | Lusby, MD | | 2 | | | | | Uranium | | Base-load | | 1,789 | | | Peach Bottom | | Delta, PA | | 2 | | | 50 | | | Uranium | | Base-load | | 1,324 | | (f) | Salem | | Lower Alloways Creek Township, NJ | | 2 | | | 42.59 | | | Uranium | | Base-load | | 995 | | (f) | Conowingo | | Darlington, MD | | 11 | | | | | Hydroelectric | | Base-load | | 572 | | | Criterion | | Oakland, MD | | 28 | | | 51 | | (g) | Wind | | Intermittent | | 36 | | (f) | Fair Wind | | Garrett County, MD | | 12 | | | | | Wind | | Intermittent | | 30 | | | Fourmile Ridge | | Garrett County, MD | | 16 | | | 51 | | (g) | Wind | | Intermittent | | 20 | | (f) | Solar Horizons | | Emmitsburg, MD | | 1 | | | 51 | | (g) | Solar | | Intermittent | | 16 | | (f) | Solar New Jersey 3 | | Middle Township, NJ | | 4 | | | 51 | | (g) | Solar | | Intermittent | | 2 | | (f) | Muddy Run | | Drumore, PA | | 8 | | | | | Hydroelectric | | Intermediate | | 1,070 | | | Eddystone 3, 4 | | Eddystone, PA | | 2 | | | | | Oil/Gas | | Peaking | | 760 | | | Perryman | | Aberdeen, MD | | 5 | | | | | Oil/Gas | | Peaking | | 404 | | | Croydon | | West Bristol, PA | | 8 | | | | | Oil | | Peaking | | 391 | | | Handsome Lake | | Kennerdell, PA | | 5 | | | | | Gas | | Peaking | | 268 | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Station(a) | | Location | | No. of Units | | Percent Owned(b) | | Primary Fuel Type | | Primary Dispatch Type(c) | | Net Generation Capacity (MW)(d) | | Richmond | | Philadelphia, PA | | 2 | | | | | Oil | | Peaking | | 98 | | | Philadelphia Road | | Baltimore, MD | | 4 | | | | | Oil | | Peaking | | 61 | | | Eddystone | | Eddystone, PA | | 4 | | | | | Oil | | Peaking | | 60 | | | Delaware | | Philadelphia, PA | | 4 | | | | | Oil | | Peaking | | 56 | | | Southwark | | Philadelphia, PA | | 4 | | | | | Oil | | Peaking | | 52 | | | Falls | | Morrisville, PA | | 3 | | | | | Oil | | Peaking | | 51 | | | Moser | | Lower Pottsgrove Twp., PA | | 3 | | | | | Oil | | Peaking | | 51 | | | Chester | | Chester, PA | | 3 | | | | | Oil | | Peaking | | 39 | | | Schuylkill | | Philadelphia, PA | | 2 | | | | | Oil | | Peaking | | 30 | | | Salem | | Lower Alloways Creek Township, NJ | | 1 | | | 42.59 | | | Oil | | Peaking | | 16 | | (f) | Total Mid-Atlantic | | | | | | | | | | | | 10,508 | | | | | | | | | | | | | | | | | ERCOT | | | | | | | | | | | | | | Whitetail | | Webb County, TX | | 57 | | | 51 | | (g) | Wind | | Intermittent | | 47 | | (f) | Sendero | | Jim Hogg and Zapata County, TX | | 39 | | | 51 | | (g) | Wind | | Intermittent | | 40 | | (f) | Colorado Bend II | | Wharton, TX | | 3 | | | | | Gas | | Intermediate | | 1,143 | | | Wolf Hollow II | | Granbury, TX | | 3 | | | | | Gas | | Intermediate | | 1,115 | | | Handley 3 | | Fort Worth, TX | | 1 | | | | | Gas | | Intermediate | | 395 | | | Handley 4, 5 | | Fort Worth, TX | | 2 | | | | | Gas | | Peaking | | 870 | | | Total ERCOT | | | | | | | | | | | | 3,610 | | | | | | | | | | | | | | | | | New York | | | | | | | | | | | | | | Nine Mile Point | | Scriba, NY | | 2 | | | | (i) | Uranium | | Base-load | | 1,675 | | (f) | FitzPatrick | | Scriba, NY | | 1 | | | | | Uranium | | Base-load | | 842 | | | Ginna | | Ontario, NY | | 1 | | | | | Uranium | | Base-load | | 576 | | | Total New York | | | | | | | | | | | | 3,093 | | | | | | | | | | | | | | | | | Other | | | | | | | | | | | | | | Antelope Valley | | Lancaster, CA | | 1 | | | | | Solar | | Intermittent | | 242 | | | Bluestem | | Beaver County, OK | | 60 | | | 51 | | (g)(j) | Wind | | Intermittent | | 101 | | (f) | Shooting Star | | Kiowa County, KS | | 65 | | | 51 | | (g) | Wind | | Intermittent | | 53 | | (f) | Sacramento PV Energy | | Sacramento, CA | | 4 | | | 51 | | (g) | Solar | | Intermittent | | 30 | | (f) | Bluegrass Ridge | | King City, MO | | 27 | | | 51 | | (g) | Wind | | Intermittent | | 29 | | (f) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Station(a) | | Location | | No. of Units | | Percent Owned(b) | | Primary Fuel Type | | Primary Dispatch Type(c) | | Net Generation Capacity (MW)(d) | | Conception | | Barnard, MO | | 24 | | | 51 | | (g) | Wind | | Intermittent | | 26 | | (f) | Cow Branch | | Rock Port, MO | | 24 | | | 51 | | (g) | Wind | | Intermittent | | 26 | | (f) | Mountain Home | | Glenns Ferry, ID | | 20 | | | 51 | | (g) | Wind | | Intermittent | | 21 | | (f) | High Mesa | | Elmore Co., ID | | 19 | | | 51 | | (g) | Wind | | Intermittent | | 20 | | (f) | Echo 1 | | Echo, OR | | 21 | | | 50.49 | | (g) | Wind | | Intermittent | | 17 | | (f) | Cassia | | Buhl, ID | | 14 | | | 51 | | (g) | Wind | | Intermittent | | 15 | | (f) | Wildcat | | Lovington, NM | | 13 | | | 51 | | (g) | Wind | | Intermittent | | 14 | | (f) | Echo 2 | | Echo, OR | | 10 | | | 51 | | (g) | Wind | | Intermittent | | 10 | | (f) | Tuana Springs | | Hagerman, ID | | 8 | | | 51 | | (g) | Wind | | Intermittent | | 9 | | (f) | Greensburg | | Greensburg, KS | | 10 | | | 51 | | (g) | Wind | | Intermittent | | 6 | | (f) | Echo 3 | | Echo, OR | | 6 | | | 50.49 | | (g) | Wind | | Intermittent | | 5 | | (f) | Three Mile Canyon | | Boardman, OR | | 6 | | | 51 | | (g) | Wind | | Intermittent | | 5 | | (f) | Loess Hills | | Rock Port, MO | | 4 | | | | | Wind | | Intermittent | | 5 | | | Denver Airport Solar | | Denver, CO | | 1 | | | 51 | | (g) | Solar | | Intermittent | | 4 | | (f) | Mystic 8, 9 | | Charlestown, MA | | 6 | | | | | Gas | | Intermediate | | 1,417 | | (e) | Hillabee | | Alexander City, AL | | 3 | | | | | Gas | | Intermediate | | 753 | | | Wyman 4 | | Yarmouth, ME | | 1 | | | 5.9 | | | Oil | | Intermediate | | 34 | | (f) | West Medway II | | West Medway, MA | | 2 | | | | | Oil/Gas | | Peaking | | 189 | | | West Medway | | West Medway, MA | | 3 | | | | | Oil | | Peaking | | 124 | | | Grand Prairie | | Alberta, Canada | | 1 | | | | | Gas | | Peaking | | 105 | | | Framingham | | Framingham, MA | | 3 | | | | | Oil | | Peaking | | 31 | | | Total Other | | | | | | | | | | | | 3,291 | | | Total | | | | | | | | | | | | 32,400 | | |
__________ (a)All nuclear stations are boiling water reactors except Braidwood, Byron, Calvert Cliffs, Ginna, and Salem, which are pressurized water reactors. (b)100%, unless otherwise indicated. (c)Base-load units are plants that normally operate to take all or part of the minimum continuous load of a system and, consequently, produce electricity at an essentially constant rate. Intermittent units are plants with output controlled by the natural variability of the energy resource rather than dispatched based on system requirements. Intermediate units are plants that normally operate to take load of a system during the daytime higher load hours and, consequently, produce electricity by cycling on and off daily. Peaking units consist of lower-efficiency, quick response steam units, gas turbines and diesels normally used during the maximum load periods. (d)For nuclear stations, capacity reflects the annual mean rating. Fossil stations and wind and solar facilities reflect a summer rating. (e)On August 9, 2020, Generation announced it would permanently cease generation operations at Byron and Dresden nuclear facilities in 2021 and Mystic Unit 8 and 9 in 2024. On September 15, 2021, Generation reversed its previous decision to retire Byron and Dresden. See Note 7 — Early Plant Retirements of the Combined Notes to the Consolidated Financial Statements for additional information. (f)Net generation capacity is stated at proportionate ownership share. (g)Reflects the prior sale of 49% of CRP to a third party. See Note 23 — Variable Interest Entities of the Combined Notes to Consolidated Financial Statements for additional information. (h)Generation has deactivated the site and is evaluating for potential return of service or retirement beyond 2023. (i)Generation wholly owns Nine Mile Point Unit 1 and has an 82% undivided ownership interest in Nine Mile Point Unit 2. (j)CRP owns 100% of the Class A membership interests and a tax equity investor owns 100% of the Class B membership interests of the entity that owns the Bluestem generating assets. The net generation capability available for operation at any time may be less due to regulatory restrictions, transmission projects, gas infrastructure, and electric system improvement projects, providing greater reliability and improvedcongestion, fuel restrictions, efficiency of cooling facilities, level of water supplies, or generating
units being temporarily out of service for our customersinspection, maintenance, refueling, repairs, or modifications required by regulatory authorities. Generation maintains property insurance against loss or damage to its principal plants and properties by fire or other perils, subject to certain exceptions. For additional information regarding nuclear insurance of generating facilities, see ITEM 1. BUSINESS — Generation. For its insured losses, Generation is self-insured to the extent that any losses are within the policy deductible or exceed the amount of insurance maintained. Any such losses could have a material adverse effect on Generation’s consolidated financial condition or results of operations.
The Utility Registrants The Utility Registrants' electric substations and a stable returnportion of their transmission rights are located on property that they own. A significant portion of their electric transmission and distribution facilities are located above or underneath highways, streets, other public places, or property that others own. The Utility Registrants believe that they have satisfactory rights to use those places or property in the form of permits, grants, easements, licenses, and franchise rights; however, they have not necessarily undertaken to examine the underlying title to the land upon which the rights rest. Transmission and Distribution The Utility Registrants’ high voltage electric transmission lines owned and in service at December 31, 2021 were as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Voltage | Circuit Miles | (Volts) | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE | 765,000 | 90 | | — | | — | | — | | — | | — | 500,000(a) | — | | 188 | | 216 | | 109 | | 16 | | — | 345,000 | 2,676 | | — | | — | | — | | — | | — | 230,000 | — | | 550 | | 358 | | 770 | | 472 | | 274 | 138,000 | 2,246 | | 135 | | 55 | | 61 | | 586 | | 214 | 115,000 | — | | — | | 700 | | 25 | | — | | — | 69,000 | — | | 177 | | — | | — | | 567 | | 667 |
___________ (a) In addition, PECO, DPL, and ACE have an ownership interest located in Delaware and New Jersey. See Note 9 - Jointly Owned Electric Utility Plant of the Combined Notes to the Consolidated Financial Statements for additional information. The Utility Registrants' electric distribution system includes the following number of circuit miles of overhead and underground lines: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Circuit Miles | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE | Overhead | 35,387 | | 12,981 | | 9,164 | | 4,127 | | 6,006 | | 7,364 | Underground | 32,498 | | 9,555 | | 17,796 | | 7,162 | | 6,427 | | 2,951 |
Gas The following table presents PECO’s, BGE’s, and DPL’s natural gas pipeline miles at December 31, 2021: | | | | | | | | | | | | | | | | | | | PECO | | BGE | | DPL | Transmission(a) | 9 | | 152 | | 8 | Distribution | 6,956 | | 7,482 | | 2,166 | Service piping | 6,479 | | 6,407 | | 1,473 | Total | 13,444 | | 14,041 | | 3,647 |
___________ (a) DPL has a 10% undivided interest in approximately 8 miles of natural gas transmission mains located in Delaware which are used by DPL for its natural gas operations and by 90% owner for distribution of natural gas to its electric generating facilities.
The following table presents PECO’s, BGE’s, and DPL’s natural gas facilities: | | | | | | | | | | | | | | | | | | | | | | | | Registrant | Facility | | Location | | Storage Capacity (mmcf) | | Send-out or Peaking Capacity (mmcf/day) | PECO | LNG Facility | | West Conshohocken, PA | | 1,200 | | 160 | PECO | Propane Air Plant | | Chester, PA | | 105 | | 25 | BGE | LNG Facility | | Baltimore, MD | | 1,056 | | 332 | BGE | Propane Air Plant | | Baltimore, MD | | 550 | | 85 | DPL | LNG Facility | | Wilmington, DE | | 250 | | 25 |
PECO, BGE, and DPL also own 30, 30, and 10 natural gas city gate stations and direct pipeline customer delivery points at various locations throughout their gas service territory, respectively. First Mortgage and Insurance The principal properties of ComEd, PECO, PEPCO, DPL, and ACE are subject to the lien of their respective Mortgages under which their respective First Mortgage Bonds are issued. See Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.
The Utility Registrants maintain property insurance against loss or damage to their properties by fire or other perils, subject to certain exceptions. For their insured losses, the Utility Registrants are self-insured to the extent that any losses are within the policy deductible or exceed the amount of insurance maintained. Any such losses could have a material adverse effect in the consolidated financial condition or results of operations of the Utility Registrants.
Exelon Security Measures The Registrants have initiated and work to maintain security measures. On a continuing basis, the Registrants evaluate enhanced security measures at certain critical locations, enhanced response and recovery plans, long-term design changes, and redundancy measures. Additionally, the energy industry has strategic relationships with governmental authorities to ensure that emergency plans are in place and critical infrastructure vulnerabilities are addressed in order to maintain the reliability of the country’s energy systems.
All Registrants 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 Note 3 — Regulatory Matters and Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements. Such descriptions are incorporated herein by these references.
| | | | | | ITEM 4. | MINE SAFETY DISCLOSURES | Not Applicable
PART II (Dollars in millions except per share data, unless otherwise noted) | | | | | | ITEM 5. | MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES |
Exelon Exelon’s common stock is listed on the Nasdaq (trading symbol: EXC). As of January 31, 2022, there were 980,136,968 shares of common stock outstanding and approximately 85,423 record holders of common stock. Stock Performance Graph The performance graph below illustrates a five-year comparison of cumulative total returns based on an initial investment of $100 in Exelon common stock, as compared with the S&P 500 Stock Index and the S&P Utility Index, for the company.period 2017 through 2021. Generation’s competitive businesses createThis performance chart assumes:
•$100 invested on December 31, 2016 in Exelon common stock, the S&P 500 Stock Index, and the S&P Utility Index; and •All dividends are reinvested.
| | | | | | | | | | | | | | | | | | | | | Value of Investment at December 31, | | 2016 | 2017 | 2018 | 2019 | 2020 | 2021 | Exelon Corporation | $100 | $115.05 | $136.13 | $141.96 | $136.44 | $192.94 | S&P 500 | $100 | $121.83 | $116.49 | $153.17 | $181.35 | $233.41 | S&P Utilities | $100 | $112.11 | $116.71 | $147.46 | $148.18 | $174.36 |
ComEd As of January 31, 2022, there were 127,021,391 outstanding shares of common stock, $12.50 par value, of ComEd, of which 127,002,904 shares were indirectly held by Exelon. At January 31, 2022, in addition to Exelon, there were 285 record holders of ComEd common stock. There is no established market for customers by providing innovative energy solutions and reliable, clean and affordable energy. Generation’s electricity generation strategy is to pursue opportunities that provide stable revenues and generation to load matching to reduce earnings volatility. Generation leverages its energy generation portfolio to deliver energy to both wholesale and retail customers. Generation’s customer-facing activities foster development and delivery of other innovative energy-related products and services for its customers. Generation operates in well-developed energy markets and employs an integrated hedging strategy to manage commodity price volatility. Its generation fleet, including its nuclear plants which consistently operate at high capacity factors, also provide geographic and supply source diversity. These factors help Generation mitigate the current challenging conditions in competitive energy markets. Exelon’s financial priorities are to maintain investment grade credit metrics at eachshares of the Registrants, to maintain optimal capital structure and to return value to Exelon’s shareholders with an attractive dividend throughout the energy commodity market cycle and through stable earnings growth.common stock of ComEd.
PECO
As partof January 31, 2022, there were 170,478,507 outstanding shares of common stock, without par value, of PECO, all of which were indirectly held by Exelon. BGE As of January 31, 2022, there were 1,000 outstanding shares of common stock, without par value, of BGE, all of which were indirectly held by Exelon. PHI As of January 31, 2022, Exelon indirectly held the entire membership interest in PHI. Pepco As of January 31, 2022, there were 100 outstanding shares of common stock, $0.01 par value, of Pepco, all of which were indirectly held by Exelon. DPL As of January 31, 2022, there were 1,000 outstanding shares of common stock, $2.25 par value, of DPL, all of which were indirectly held by Exelon. ACE As of January 31, 2022, there were 8,546,017 outstanding shares of common stock, $3.00 par value, of ACE, all of which were indirectly held by Exelon. All Registrants Dividends Under applicable Federal law, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE can pay dividends only from retained, undistributed or current earnings. A significant loss recorded at, ComEd, PECO, BGE, PHI, Pepco, DPL, or ACE may limit the dividends that these companies can distribute to Exelon. ComEd has agreed in connection with a financing arranged through ComEd Financing III that ComEd will not declare dividends on any shares of its strategic business planning process, Exelon routinely reviewscapital stock in the event that: (1) it exercises its hedging policy, dividend policy, operatingright to extend the interest payment periods on the subordinated debt securities issued to ComEd Financing III; (2) it defaults on its guarantee of the payment of distributions on the preferred trust securities of ComEd Financing III; or (3) an event of default occurs under the Indenture under which the subordinated debt securities are issued. No such event has occurred.
PECO has agreed in connection with financings arranged through PEC L.P. and capital costs, capital spending plans, strengthPECO Trust IV that PECO will not declare dividends on any shares of its balance sheetcapital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debentures which were issued to PEC L.P. or PECO Trust IV; (2) it defaults on its guarantee of the payment of distributions on the Series D Preferred Securities of PEC L.P. or the preferred trust securities of PECO Trust IV; or (3) an event of default occurs under the Indenture under which the subordinated debentures are issued. No such event has occurred. BGE is subject to restrictions established by the MDPSC that prohibit BGE from paying a dividend on its common shares if (a) after the dividend payment, BGE’s equity ratio would be below 48% as calculated pursuant to the MDPSC’s ratemaking precedents or (b) BGE’s senior unsecured credit rating is rated by two of the three major credit rating agencies below investment grade. No such event has occurred. Pepco is subject to certain dividend restrictions established by settlements approved in Maryland and the District of Columbia. Pepco is prohibited from paying a dividend on its common shares if (a) after the dividend payment, Pepco's equity ratio would be below 48% as equity levels are calculated under the ratemaking precedents of the MDPSC and DCPSC or (b) Pepco’s senior unsecured credit metrics,rating is rated by one of the three major credit rating agencies below investment grade. No such event has occurred. DPL is subject to certain dividend restrictions established by settlements approved in Delaware and sufficiencyMaryland. DPL is prohibited from paying a dividend on its common shares if (a) after the dividend payment, DPL's equity ratio would be below 48% as equity levels are calculated under the ratemaking precedents of the DEPSC and MDPSC or (b) DPL’s senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. No such event has occurred. ACE is subject to certain dividend restrictions established by settlements approved in New Jersey. ACE is prohibited from paying a dividend on its common shares if (a) after the dividend payment, ACE's equity ratio would be below 48% as equity levels are calculated under the ratemaking precedents of the NJBPU or (b) ACE's senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. ACE is also subject to a dividend restriction which requires ACE to obtain the prior approval of the NJBPU before dividends can be paid if its equity as a percent of its liquidity position, by performing various stress tests with differing variables,total capitalization, excluding securitization debt, falls below 30%. No such as commodity price movements, increases in margin-related transactions, changes in hedging practices, and the impacts of hypothetical credit downgrades.events have occurred. Exelon’s Board of Directors approved aan updated dividend policy providingfor 2022. The 2022 quarterly dividend will be $0.3375 per share. At December 31, 2021, Exelon had retained earnings of $16,942 million, ComEd’s retained earnings of $1,691 million consisting of retained earnings appropriated for future dividends of $3,330 million, partially offset by $1,639 million of unappropriated accumulated deficits, PECO’s retained earnings of $1,684 million, BGE’s retained earnings of $1,995 million, and PHI's undistributed losses of $210 million. The following table sets forth Exelon’s quarterly cash dividends per share paid during 2021 and 2020: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2021 | | 2020 | (per share) | Fourth Quarter | | Third Quarter | | Second Quarter | | First Quarter | | Fourth Quarter | | Third Quarter | | Second Quarter | | First Quarter | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exelon | $ | 0.3825 | | | $ | 0.3825 | | | $ | 0.3825 | | | $ | 0.3825 | | | $ | 0.3825 | | | $ | 0.3825 | | | $ | 0.3825 | | | $ | 0.3825 | |
The following table sets forth PHI's quarterly distributions and ComEd’s, PECO’s, BGE's, Pepco's, DPL's, and ACE's quarterly common dividend payments: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2021 | | 2020 | (in millions) | 4th Quarter | | 3rd Quarter | | 2nd Quarter | | 1st Quarter | | 4th Quarter | | 3rd Quarter | | 2nd Quarter | | 1st Quarter | | | | | | | | | | | | | | | | | ComEd | 127 | | | 127 | | | 126 | | | 127 | | | 126 | | | 124 | | | 124 | | | 125 | | PECO | 85 | | | 85 | | | 84 | | | 85 | | | 85 | | | 85 | | | 85 | | | 85 | | BGE | 73 | | | 73 | | | 72 | | | 74 | | | 60 | | | 62 | | | 62 | | | 62 | | PHI | 98 | | | 191 | | | 333 | | | 81 | | | 102 | | | 183 | | | 134 | | | 134 | | Pepco | 47 | | | 98 | | | 95 | | | 28 | | | 58 | | | 73 | | | 73 | | | 28 | | DPL | 41 | | | 43 | | | 23 | | | 40 | | | 42 | | | 33 | | | 14 | | | 52 | | ACE | 8 | | | 51 | | | 215 | | | 14 | | | 3 | | | 76 | | | 12 | | | 23 | |
First Quarter 2022 Dividend On February 8, 2022, Exelon's Board of Directors declared a raiseregular quarterly dividend of 5% each year$0.3375 per share on Exelon’s common stock for the period covering 2018 through 2020, beginning with thefirst quarter of 2022. The dividend is payable on Monday, March 2018 dividend.10, 2022, to shareholders of record of Exelon as of 5 p.m. Eastern time on Friday, February 25, 2022. Various market, financial, regulatory, legislative and operational factors could affect the Registrants' success
| | | | | | ITEM 6. | SELECTED FINANCIAL DATA |
Not Applicable
| | | | | | Item 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
(Dollars in pursuing their strategies.millions except per share data, unless otherwise noted) Exelon Executive Overview As of December 31, 2021, Exelon continues to assess infrastructure, operational, commercial, policy, and legal solutions to these issues. One key issue is ensuring the ability to properly value nuclear generation assetswas a utility services holding company engaged in the market, solutions to which Exelon is actively pursuing in a varietygeneration, delivery, and marketing of jurisdictionsenergy through Generation and venues. See ITEM 1A. RISK FACTORS for additional information regarding marketthe energy distribution and financial factors.transmission businesses through ComEd, PECO, BGE, Pepco, DPL, and ACE. Exelon continues to be committed to managing its costs. In November 2017, Exelon announced a commitment for $250 millionhas eleven reportable segments consisting of cost savings, primarily at Generation, to be achieved by 2020. In November 2018, Exelon announced the elimination of an approximately additional $200 million of annual ongoing costs, through initiatives primarily at GenerationGeneration’s five reportable segments (Mid-Atlantic, Midwest, New York, ERCOT, and BSC, by 2021. Approximately $150 million is expected to be related to Generation, with the remaining amount related to the Utility Registrants. In October 2019, Exelon announced additional annual cost savings of approximately $100 million, at Generation, to be achieved by 2022. These actions are in response to the continuing economic challenges confronting Generation's business, necessitating continued focus on cost management through enhanced efficiencyOther Power Regions), ComEd, PECO, BGE, Pepco, DPL, and productivity. Growth Opportunities
Management continually evaluates growth opportunities aligned with Exelon’s businesses, assets and markets, leveraging Exelon’s expertise in those areas and offering sustainable returns.
Regulated Energy Businesses. The Utility Registrants anticipate investing approximately $26 billion over the next four years in electric and natural gas infrastructure improvements and modernization projects, including smart grid technology, storm hardening, advanced reliability technologies, and transmission projects, which is projected to result in an increase to current rate base of approximately $13 billion by the end of 2023. The Utility Registrants invest in rate base where beneficial to customers and the community by increasing reliability and the service experience or otherwise meeting customer needs. These investments are made at the lowest reasonable cost to customers.
ACE. See Note 31 — Regulatory MattersSignificant Accounting Policies and Note 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for additional information onregarding Exelon's principal subsidiaries and reportable segments. Exelon’s consolidated financial information includes the Smart Meter and Smart Grid Investments and infrastructure development and enhancement programs. Competitive Energy Businesses. Generation continually assesses the optimal structure and compositionresults of its generation assetsseven separate operating subsidiary registrants, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE and its subsidiary Generation. The following combined Management’s Discussion and Analysis of Financial Condition and Results of Operations summarizes results for the year ended December 31, 2021 compared to the year ended December 31, 2020, and is separately filed by Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE. However, none of the Registrants makes any representation as well as explores wholesaleto information related solely to any of the other Registrants. For discussion of the year ended December 31, 2020 compared to the year ended December 31, 2019, refer to ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS in the 2020 Form 10-K, which was filed with the SEC on February 24, 2021.
COVID-19. The Registrants have taken steps to mitigate the potential risks posed by the global outbreak (pandemic) of COVID-19. The Registrants provide a critical service to our customers which means that it is paramount that we keep our employees who operate our businesses safe and retail opportunities withinminimize unnecessary risk of exposure to the powervirus by taking extra precautions for employees who work in the field and gas sectors. Generation’s long-term growth strategy isin our facilities. The Registrants have implemented work from home policies where appropriate, and imposed travel limitations on employees. The Registrants continue to implement strong physical and cyber-security measures to ensure appropriate valuation of its generation assets,that our systems remain functional in part through public policy efforts, identifyorder to both serve our operational needs with a remote workforce and capitalize on opportunities that provide generationkeep them running to load matchingensure uninterrupted service to our customers. There were no changes in internal control over financial reporting as a meansresult of COVID-19 that materially affected, or are reasonably likely to provide stable earnings, and identify emerging technologies where strategic investments providematerially affect, any of the optionRegistrants’ internal control over financial reporting. See ITEM 9A. CONTROLS AND PROCEDURES for significant future growth or influenceadditional information. Unfavorable economic conditions due to COVID-19 resulted in market development. Other Key Business Drivers and Management Strategies
Utility Rates and Rate Proceedingsan estimated reduction to Exelon’s Net income of approximately $245 million for the year ended December 31, 2020. The impact was not material for the year ended December 31, 2021. To offset the unfavorable impacts from COVID-19, Exelon identified approximately $250 million in cost savings in 2020. The cost savings achieved in 2020 were higher than originally anticipated.
The Utility Registrants file rate cases with their regulatory commissions seeking increasesassessed long-lived assets, goodwill, and investments for recoverability and there were no material impairment charges recorded in 2020 or decreases to their electric transmission and distribution, and gas distribution rates to recover their costs and earn2021 as a fair return on their investments. The outcomesresult of these regulatory proceedings impact the Utility Registrants’ current and future results of operations, cash flows and financial positions.COVID-19. See Note 312 — Regulatory MattersAsset Impairments of the Combined Notes to Consolidated Financial Statements for additional information on these regulatory proceedings.
Power Markets
Price of Fuelsrelated to other impairment assessments.
The useRegistrants will continue to monitor developments affecting their workforce, customers, and suppliers and will take additional precautions that they determine to be necessary in order to mitigate the impacts. The Registrants cannot predict the full extent of new technologiesthe impacts of COVID-19, which will depend on, among other things, the rate, and public perceptions of the effectiveness, of vaccinations and rate of resumption of business activity.
Financial Results of Operations GAAP Results of Operations. The following table sets forth Exelon's GAAP consolidated Net Income attributable to recover natural gascommon shareholders by Registrant or subsidiary for the year ended December 31, 2021 compared to the same period in 2020. For additional information regarding the financial results for the years ended December 31, 2021and2020 see the discussions of Results of Operations by Registrant or subsidiary. | | | | | | | | | | | | | | | | | | | 2021 | | 2020 | | (Unfavorable) Favorable Variance | Exelon | $ | 1,706 | | | $ | 1,963 | | | $ | (257) | | | | | | | | ComEd | 742 | | | 438 | | | 304 | | PECO | 504 | | | 447 | | | 57 | | BGE | 408 | | | 349 | | | 59 | | PHI | 561 | | | 495 | | | 66 | | Pepco | 296 | | | 266 | | | 30 | | DPL | 128 | | | 125 | | | 3 | | ACE | 146 | | | 112 | | | 34 | | Generation | (205) | | | 589 | | | (794) | | Other(a) | (304) | | | (355) | | | 51 | |
__________ (a)Primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities, and other financing and investing activities. Year Ended December 31, 2021 Compared to Year Ended December 31, 2020. Net income attributable to common shareholdersdecreased by $257 million and diluted earnings per average common share decreased to $1.74 in 2021 from shale deposits is increasing natural gas supply$2.01 in 2020 primarily due to: •Impacts of the February 2021 extreme cold weather event; •Accelerated depreciation and reserves,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 places downward pressurewas reversed on natural gas pricesSeptember 15, 2021, and therefore,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; •Higher net unrealized and realized losses on wholesaleequity investments; and retail power prices, which results in a reduction in Exelon’s revenues. Forward natural gas prices have declined significantly over the last several years; in part reflecting •The absence of prior year one-time tax settlements. The decreases were partially offset by;
•Higher electric distribution earnings from higher rate base and higher allowed ROE due to an increase in supplytreasury rates at ComEd; •The favorable impacts of the multi-year plan at BGE and Pepco and regulatory rate increases at DPL and ACE; •Favorable weather conditions at PECO and DPL's Delaware service territory; •Favorable volume at PECO and ACE; •Lower storm costs at PECO and DPL due to strong natural gas production (duethe absence of the June 2020 and August 2020 storms, respectively; •Lower operating and maintenance expense at ComEd due to shale gas development).the payments that ComEd made in 2020 under the Deferred Prosecution Agreement; FERC Inquiry•Higher mark-to-market gains;
•Higher net unrealized and realized gains on ResiliencyNDT funds; On August 23, 2017,
•Absence of one time charges recorded in the DOE staff releasedthird 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; •Favorable sales and hedges of excess emission credits; •Favorable commodity prices on fuel hedges; •Lower nuclear fuel costs due to accelerated amortization of nuclear fuel and lower prices; and •Higher New York ZEC revenues due to higher generation and an increase in ZEC prices. Adjusted (non-GAAP) Operating Earnings. In addition to net income, Exelon evaluates its reportoperating 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 table provides a reconciliation between Net income attributable to common shareholders as determined in accordance with GAAP and Adjusted (non-GAAP) operating earnings for the year ended December 31, 2021 as compared to 2020: | | | | | | | | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | | 2021 | | 2020 | (In millions, except per share data) | | | Earnings per Diluted Share | | | | Earnings per Diluted Share | Net Income Attributable to Common Shareholders | $ | 1,706 | | | $ | 1.74 | | | $ | 1,963 | | | $ | 2.01 | | Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $145 and $73, respectively) | (421) | | | (0.43) | | | (213) | | | (0.22) | | Unrealized Gains Related to NDT Fund Investments (net of taxes of $141 and $278, respectively)(a) | (139) | | | (0.14) | | | (256) | | | (0.26) | | | | | | | | | | Asset Impairments (net of taxes of $136 and $135, respectively)(b) | 405 | | | 0.41 | | | 396 | | | 0.41 | | Plant Retirements and Divestitures (net of taxes of $290 and $244, respectively)(c) | 865 | | | 0.88 | | | 718 | | | 0.74 | | Cost Management Program (net of taxes of $2 and $14, respectively)(d) | 9 | | | 0.01 | | | 45 | | | 0.05 | | | | | | | | | | Asset Retirement Obligation (net of taxes of $12 and $16, respectively)(e) | (35) | | | (0.04) | | | 48 | | | 0.05 | | Change in Environmental Liabilities (net of taxes of $3 and $6, respectively) | 9 | | | 0.01 | | | 18 | | | 0.02 | | COVID-19 Direct Costs (net of taxes of $13 and $19, respectively)(f) | 36 | | | 0.04 | | | 50 | | | 0.05 | | Deferred Prosecution Agreement Payments (net of taxes of $0)(g) | — | | | — | | | 200 | | | 0.20 | | Acquisition Related Costs (net of taxes of $5 and $1, respectively)(h) | 15 | | | 0.02 | | | 4 | | | — | | ERP System Implementation Costs (net of taxes of $4 and $1, respectively)(i) | 13 | | | 0.01 | | | 3 | | | — | | Separation Costs (net of taxes of $31)(j) | 90 | | | 0.09 | | | — | | | — | | Costs Related to Suspension of Contractual Offset (net of taxes of $45)(k) | 148 | | | 0.15 | | | — | | | — | | Income Tax-Related Adjustments (entire amount represents tax expense)(l) | 47 | | | 0.05 | | | 71 | | | 0.07 | | Noncontrolling Interests (net of taxes of $2 and $19, respectively)(m) | 16 | | | 0.02 | | | 103 | | | 0.11 | | Adjusted (non-GAAP) Operating Earnings | $ | 2,764 | | | $ | 2.82 | | | $ | 3,149 | | | $ | 3.22 | |
__________ Note: Amounts may not sum due to rounding. Unless otherwise noted, the income tax impact of each reconciling item between GAAP Net Income and Adjusted (non-GAAP) Operating Earnings is based on the reliabilitymarginal 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 funds, the marginal statutory income tax rates for 2021 and 2020 ranged from 25.0% 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 funds were 50.4% and 52.1% for the years ended December 31, 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 of the electric grid. One aspectNew England asset group, an impairment recorded as a result of the wide-ranging report isagreement to sell the DOE’s recognition thatAlbany Green Energy biomass facility, and an impairment of a wind project at Generation. In 2020, reflects an impairment at ComEd related to the electricity markets do not currently valueacquisition of transmission assets and an impairment of the resiliency provided by base-load generation, such as nuclear plants. On September 28, 2017, the DOE issued a Notice of Proposed Rulemaking (NOPR) that would entitle certain eligible resilient generating units (i.e., those located in organized markets, with a 90-day supply of fuel on site, not already subject to state cost of service regulation and satisfying certain other requirements) to recover fully allocated costs and earn a fair return on equity on their investment. On January 8, 2018, FERC issued an order terminating the rulemaking docket that it initiated to address the proposed ruleNew England asset group in the DOE NOPR, concludingthird quarter of 2020 at Generation. (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 proposed rule did not sufficiently demonstrate there isreversal of the previous decision to retire Byron and Dresden on September 15, 2021 and a resiliency issuegain on sale of Generation's solar business. Depreciation for Byron and that it proposed a remedy that did not appearDresden was adjusted beginning September 15, 2021 to be just, reasonablereflect the extended useful life estimates. In 2020, primarily reflects one-time charges and nondiscriminatory as requiredaccelerated 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)For Generation, reflects an adjustment to the nuclear asset obligation for the Non-Regulatory Agreement Units resulting from the annual update in the third quarter of 2021 and fourth quarter of 2020, respectively. (f)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. (g)Reflects the payments made by ComEd under the Federal Power Act. AtDeferred Prosecution Agreement, which ComEd entered in July 2020 with the same time, FERC initiated a new proceeding to consider resiliency challengesU.S. Attorney’s Office for the Northern District of Illinois. (h)Reflects costs related to the bulk power system and evaluate whether additional FERC action to address resiliency would be appropriate. FERC directed each RTO and ISO to respond within 60 days to 24 specific questions about how they assess and mitigate threats to resiliency. Thereafter, interested parties submitted reply comments on May 9, 2018, and a few parties submitted further replies. Exelon has been and will continue to be an active participantacquisition of EDF's interest in these proceedings but cannot predict the final outcome or its potential financial impact, if any, on Exelon or Generation. Section 232 Uranium Petition
On January 16, 2018, two Canadian-owned uranium mining companies with operationsCENG, which was completed in the U.S. jointly submittedthird quarter of 2021.
(i)Reflects costs related to a petitionmulti-year Enterprise Resource Program (ERP) system implementation. (j)Represents costs related to the U.S. Departmentseparation primarily comprised of Commerce (DOC) seeking relief under Section 232system-related costs, third-party costs paid to advisors, consultants, lawyers, and other experts assisting in the planned separation, and employee-related severance costs. (k)Decommissioning-related activities for 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 Trade Expansion ActARC, and accretion of 1962, as amended, (the Act) from importsthe decommissioning obligation, are generally offset within Exelon’s consolidated statements of uranium products, alleging that these imports threaten national security (the Petition). The relief requested would have required U.S. nuclear reactors to purchase at least 25%operations. These costs reflect the impact of their uranium needs from domestic minessuspension of contractual offset for the next 10 years or more. The Act was promulgated by Congress to protect essential national security industries whose survival is threatened by imports. As such,Byron units beginning in the Act authorizes the Secretarysecond quarter of Commerce (the Secretary) to conduct investigations to evaluate the effects of imports of any item on the national security2021 through September 15, 2021. With Generation's September 15, 2021 reversal of the U.S. The Petition allegesprevious decision to retire Byron, Generation resumed contractual offset for Byron as of that date. (l)In 2021, primarily reflects the lossrecognition of a viable U.S. uranium mining industry would havevaluation allowance against a significant detrimental impact ondeferred tax asset associated with Delaware net operating loss carryforwards due to a change in Delaware tax law. In 2021 and 2020, also reflects the national, energy, and economic securityadjustment to deferred income taxes due to changes in forecasted apportionment. (m)Represents elimination from Generation’s results of the U.S.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 abilitynoncontrolling interest portion of the country to sustain an independent nuclear fuel cycle.a wind project impairment. On July 18, 2018, the Secretary announced that the DOC had initiated an investigation in response to the petition. The Secretary submitted a report to President Trump on April 14, 2019 that has not been made public. On July 12, 2019, the President issued a memorandum indicating that he did not agree with the Secretary's finding that uranium imports threaten to impair the national security of the United States, choosing not to impose any trade restrictions at this time.The President found that a fuller analysis of national security considerations with respect to the entire nuclear fuel supply chain is necessary
Significant 2021 Transactions and directed that a United States Nuclear Fuel Working Group (Working Group) be established to develop recommendations for reviving and expanding domestic nuclear fuel production. The Working Group report has not yet been issued and is not expected to be made public. The Working Group is co-chaired by the Assistant to the President for National Security Affairs and the Assistant to the President for Economic Policy. Exelon will monitor and volunteer to provide information to support the Working Group's efforts. Exelon and Generation cannot currently predict the outcome of the Working Group report and subsequent actions.Developments Complaint at FERC Seeking to Alter Capacity Market Default Offer CapsSeparation
On February 21, 2019, PJM's Independent Market Monitor (IMM) filed2021, Exelon’s Board of Directors approved a complaint alleging that the number of performance assessment intervals usedplan to calculate the default offer cap for bids to supply capacity in PJM is too high, resulting in an overstated default offer cap that obviates the need for most sellers to seek unit-specific approval of their offers. The IMM claims that this allows for the exercise of market power. The IMM asks 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. It is too early to predict the final outcome of this proceeding or its potential financial impact, if any, on Exelon or Generation.
Energy Demand
Modest economic growth partially offset by energy efficiency initiatives is resulting in relatively flat load growth in electricity forseparate the Utility Registrants. ComEd, PECO, BGE, Pepco, DPLRegistrants and ACE are projecting load volumesGeneration, creating two publicly traded companies with the resources necessary to increase (decrease) by (0.3)%, (0.7)%, (1.2)%, (0.4)%, (0.5)%best serve customers and (0.4)%, respectively, in 2020 compared to 2019.
Retail Competition
Generation’s retail operations compete for customers in a competitive environment, which affect sustain long-term investment and operating excellence ("the margins that Generation can earn and the volumes that it is able to serve. Forward natural gas and power prices are expected to remain low and thus we expect retail competitors to stay aggressive in their pursuit of market share, and that wholesale generators (including Generation) will continue to use their retail operations to hedge generation output.
Hedging Strategy
Exelon’s policy to hedge commodity risk on a ratable basis over three-year periods is intended to reduceseparation"). The separation gives each company the financial impact of market price volatility. Generationand strategic independence to focus on its specific customer needs, while executing its core business strategy. Exelon completed the separation on February 1, 2022. The new publicly traded company 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 December 31, 2019, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York and ERCOT reportable segments is 91%-94% and 61%-64% for 2020 and 2021, respectively. 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 2020 through 2024 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 results of operations, cash flows and financial positions.
Constellation Energy Corporation. See Note 1526 — Derivative Financial InstrumentsSeparation of the Combined Notes to Consolidated Financial Statements and ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for additional information. In connection with the separation, Exelon incurred transaction costs of $122 million on a pre-tax basis for the year ended December 31, 2021, which are recorded in Operating and maintenance expense. Exelon expects to incur incremental transaction costs of approximately $90 million in 2022. These costs are excluded from Adjusted (non-GAAP) Operating Earnings. The Utility Registrants mitigate commodity price risk through regulatory mechanisms that allow themtransaction costs are primarily comprised of system-related costs, third-party costs paid to recover procurement costs from retail customers. Environmental Legislativeadvisors, consultants, lawyers, and Regulatory Developments
Exelon was actively involvedother experts assisting in the Obama Administration’s developmentseparation, and implementation of environmental regulations for the electric industry, in pursuit of its business strategy to provide reliable, clean, affordable and innovative energy products. These efforts have most frequently involved air, water and waste controls for fossil-fueled electric generating units, as set forth in the discussion below. These regulations have had a disproportionate adverse impact on coal-fired power plants, requiring significant expenditures of capital and variable operating and maintenance expense, and have resulted in the retirement of older, marginal facilities. Due to its low emission generation portfolio, Generation has not been significantly affected by these regulations, representing a competitive advantage relative to electric generators that are more reliant on fossil fuel plants.employee-related severance costs.
Through the issuance of a series of Executive Orders (EO), President Trump has initiated review of a number of EPA and other regulations issued during the Obama Administration, with the expectation that the Administration will seek repeal or significant revision of these rules. Under these EOs, each executive agency is required to evaluate existing regulations and make recommendations regarding repeal, replacement, or modification. The
Administration’s actions are intended to result in less stringent compliance requirements under air, water, and waste regulations. The exact nature, extent, and timing of the regulatory changes are unknown, as well as the ultimate impact on Exelon’s and its subsidiaries results of operations and cash flows.
In particular, the Administration has targeted existing EPA regulations for repeal, including notably the Clean Power Plan, as well as revoking many Executive Orders, reports, and guidance issued by the Obama Administration on the topic of climate change or the regulation of greenhouse gases. The Executive Order also disbanded the Interagency Working Group that developed the social cost of carbon used in rulemakings, and withdrew all technical support documents supporting the calculation. Other regulations that have been specifically identified for review are the Clean Water Act rule relating to jurisdictional waters of the U.S., the Steam Electric Effluent Guidelines relating to waste water discharges from coal-fired power plants, and the 2015 National Ambient Air Quality Standard (NAAQS) for ozone. The review of final rules could extend over several years as formal notice and comment rulemaking process proceeds.
Air Quality
Mercury and Air Toxics Standard Rule (MATS). On December 16, 2011, the EPA signed a final rule to reduce emissions of toxic air pollutants from power plants and signed revisions to the NSPS for electric generating units. The final rule, known as MATS, requires coal-fired electric generation plants to achieve high removal rates of mercury, acid gases and other metals, and to make capital investments in pollution control equipment and incur higher operating expenses. Numerous entities challenged MATS in the D.C. Circuit Court, and Exelon intervened in support of the rule. In April 2014, the D.C. Circuit Court issued an opinion upholding MATS in its entirety. On appeal, the U.S. Supreme Court decided in June 2015 that the EPA unreasonably refused to consider costs in determining whether it is appropriate and necessary to regulate hazardous air pollutants emitted by electric utilities, but did not vacate the rule. On April 27, 2017, the D.C. Circuit Court granted EPA’s motion to hold the litigation in abeyance, pending EPA’s review of the MATS rule pursuant to President Trump’s EO discussed above. Notwithstanding the Court’s order to hold the litigation in abeyance, the MATS rule remains in effect. Exelon will continue to participate in the remanded proceedings before the D.C. Circuit Court as an intervenor in support of the rule. On December 28, 2018, the EPA proposed to revoke the "appropriate and necessary" finding underpinning the MATS rule. While the proposal would leave in place the rule, it would leave it vulnerable to future legal challenge. On February 7, 2019, EPA published its Reconsideration of Supplemental Finding and Residual Risk and Technology Review. After considering public comment, EPA transmitted a final version to the Office of Management and Budget for review prior to publication.
Clean Power Plan. On April 28, 2017, the D.C. Circuit Court issued orders in separate litigation related to the EPA’s actions under the Clean Power Plan (CPP) to amend Clean Air Act Section 111(d) regulation of existing fossil-fired electric generating units and Section 111(b) regulation of new fossil-fired electric generating units. In both cases, the Court has determined to hold the litigation in abeyance pending a determination whether the rule should be remanded to the EPA. In June 2019, EPA issued a final rule that repealed the CPP, and finalized the Affordable Clean Energy rule to replace the CPP with less stringent emissions guidelines based on heat rate improvement measures that could be achieved within the fence line of existing power plants. The Affordable Clean Energy rule is currently being litigated.
2015 Ozone National Ambient Air Quality Standards (NAAQS). On April 11, 2017, the D.C. Circuit Court ordered that the consolidated 2015 ozone NAAQS litigation be held in abeyance pending EPA’s further review of the 2015 Rule. On August 23, 2019, the D.C. Circuit Court upheld the stringency of NAAQS, but remanded certain aspects of its secondary standard to EPA for revision.
Primary SO2 National Ambient Air Quality Standards (NAAQS). EPA took final action on April 17, 2019 to retain the current primary SO2 standard without revision, leaving the standard established in 2010 in effect.
Climate Change. Exelon supports comprehensive climate change legislation or regulation, including a cap-and-trade program for GHG emissions, which balances the need to protect consumers, business and the economy with the urgent need to reduce national GHG emissions. In the absence of Federal legislation, the EPA is moving forward with the regulation of GHG emissions under the Clean Air Act. In addition, there have been recent developments in the international regulation of GHG emissions pursuant to the United Nations Framework Convention on Climate Change (“UNFCCC” or “Convention”). See ITEM 1. BUSINESS, "Global Climate Change" for additional information.
Water QualityUtility Registrants
Section 316(b) requires that the cooling water intake structures at electric power plants reflect the best technology available to minimize adverse environmental impactsUtility Operations
Service Territories and is implemented through state-level NPDES permit programs. All of Generation’s power generation facilities with cooling water systems are subject to the regulations. Facilities without closed-cycle recirculating systems (e.g., cooling towers) are potentially most affected by recent changes to the regulations. For Generation, those facilities are Calvert Cliffs, Clinton, Dresden, Eddystone, Fairless Hills, FitzPatrick, Ginna, Gould Street, Handley, Mystic 7, Nine Mile Point Unit 1, Peach Bottom, Quad Cities, and Salem. See ITEM 1. BUSINESS, "Water Quality" for additional information. Clean Water Rule
In 2015, the EPA and the US Army Corps of Engineers, finalized the Clean Water Rule that significantly expanded the definition of the Waters of the United States under the Clean Water Act and resulted in increased environmental costs for some projects. On October 22, 2019, the EPA and the US Army Corps of Engineers repealed the 2015 Clean Water Rule and restored the definition of the Waters of the United States that existed prior to this rule. On January 23, 2020, a new final rule was issued by the EPA and the US Army Corps of Engineers to streamline and clarify the definition of Waters of the United States and will be effective sixty days after publication in the Federal Register. This rule represents final action by these government agencies to narrow the scope of Waters of the United States that are regulated under the federal Clean Water Act.
Solid and Hazardous Waste
In October 2015, the first federal regulation for the disposal of coal combustion residuals (CCR) from power plants became effective. The rule classifies CCR as non-hazardous waste under RCRA. Under the regulation, CCR will continue to be regulated by most states subject to coordination with the federal regulations. Generation has previously recorded accruals consistent with state regulation for its owned coal ash sites, and as such, the regulation is not expected to impact Exelon’s and Generation’s financial results. Generation does not have sufficient information to reasonably assess the potential likelihood or magnitude of any remediation requirements that may be asserted under the new federal regulations for coal ash disposal sites formerly owned by Generation. For these reasons, Generation is unable to predict whether and to what extent it may ultimately be held responsible for remediation and other costs relating to formerly owned coal ash disposal sites under the new regulations.
See Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information related to environmental matters.
Other Legislative and Regulatory Developments
Illinois Clean Energy Progress Act
On March 14, 2019, the Clean Energy Progress Act was introduced in the Illinois General Assembly to preserve Illinois’ clean energy choices arising from FEJA and empower the IPA to conduct capacity procurements outside of PJM’s base residual auction process, while utilizing the fixed resource requirement provisions in PJM's tariffs which are still subject to penalties and other obligations under the PJM tariffs. The most significant provisions of the proposed legislation are as follows: (1) it allows the IPA to procure capacity directly from clean energy resources that have previously sold ZECs or RECs, including certain of Generation’s nuclear plants in Illinois, or from new clean energy resources, (2) it establishes a goal of achieving 100% carbon-free power in the ComEd service territory by 2032, and (3) it implements reforms to enhance consumer protections in the state’s competitive retail electricity and natural gas markets, including Generation’s retail customers. Energy legislation has also been proposed by other stakeholders, including renewable resource developers, environmental advocates, and coal-fueled generators. Exelon and Generation will work with legislators and stakeholders and cannot predict the outcome or the potential financial impact, if any, on Exelon or Generation.
Nuclear Powers Act of 2019
On April 12, 2019, the Nuclear Powers America Act of 2019 was introduced to the United States Congress, which expands the current investment tax credit to existing nuclear power plants. The proposed legislation would provide a credit equal to 30% of continued capital investment in certain nuclear energy-related expenditures, including capital expenses and nuclear fuel, starting from tax years 2019 through 2023. Thereafter, the credit rate would be reduced to 26% in 2024, 22% in 2025, and 10% in 2026 and beyond. To qualify for the credit, the plant must be
currently operational and must have applied for an operating license renewal before 2026. Exelon and Generation are working with legislators and stakeholders and cannot predict the outcome or the potential financial impact, if any, on Exelon or Generation.
Critical Accounting Policies and Estimates
The preparation of financial statements in conformity with GAAP requires that management apply accounting policies and make estimates and assumptions that affect results of operations and the amounts of assets and liabilities reported in the financial statements. Management believes that the accounting policies described below require significant judgment in their application, or incorporate estimates and assumptions that are inherently uncertain and that may change in subsequent periods. Additional information of the application of these accounting policies can be found in the Combined Notes to Consolidated Financial Statements.
Nuclear Decommissioning Asset Retirement Obligations (Exelon and Generation)
Generation’s ARO associated with decommissioning its nuclear units was $10.5 billion at December 31, 2019. The authoritative guidance requires that Generation estimate its obligation for the future decommissioning of its nuclear generating plants. To estimate that liability, Generation uses an internally-developed, probability-weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple decommissioning outcome scenarios.
As a result of recent nuclear plant retirements in the industry, nuclear operators and third-party service providers are obtaining more information about costs associated with decommissioning activities. At the same time, regulators are gaining more information about decommissioning activities which could result in changes to existing decommissioning requirements. In addition, as more nuclear plants are retired, it is possible that technological advances will be identified that could create efficiencies and lead to a reduction in decommissioning costs. The availability of NDT funds could impact the timing of the decommissioning activities. Additionally, certain factors such as changes in regulatory requirements during plant operations or the profitability of a nuclear plant could impact the timing of plant retirements. These factors could result in material changes to Generation’s current estimates as more information becomes available and could change the timing of plant retirements and the probability assigned to the decommissioning outcome scenarios.
The nuclear decommissioning obligation is adjusted on a regular basis due to the passage of time and revisions to the key assumptions for the expected timing and/or estimated amounts of the future undiscounted cash flows required to decommission the nuclear plants, based upon the following methodologies and significant estimates and assumptions:
Decommissioning Cost Studies. Generation uses unit-by-unit decommissioning cost studies to provide a marketplace assessment of the expected costs (in current year dollars) and timing of decommissioning activities, which are validated by comparison to current decommissioning projects within the industry and other estimates. Decommissioning cost studies are updated, on a rotational basis, for each of Generation’s nuclear units at least every five years, unless circumstances warrant more frequent updates. As part of the annual cost study update process, Generation evaluates newly assumed costs or substantive changes in previously assumed costs to determine if the cost estimate impacts are sufficiently material to warrant application of the updated estimates to the AROs across the nuclear fleet outside of the normal five-year rotating cost study update cycle.
Cost Escalation Factors. Generation uses cost escalation factors to escalate the decommissioning costs from the decommissioning cost studies discussed above through the assumed decommissioning period for each of the units. Cost escalation studies, updated on an annual basis, are used to determine escalation factors, and are based on inflation indices for labor, equipment and materials, energy, LLRW disposal and other costs. All of the nuclear AROs are adjusted each year for the updated cost escalation factors.
Probabilistic Cash Flow Models. Generation’s probabilistic cash flow models include the assignment of probabilities to various scenarios for decommissioning cost levels, decommissioning approaches, and timing of plant shutdown on a unit-by-unit basis. Probabilities assigned to cost levels include an assessment of the likelihood of costs 20% higher (high-cost scenario) or 15% lower (low-cost scenario) than the base cost scenario. The assumed decommissioning scenarios include the following three alternatives: (1) DECON which assumes decommissioning activities begin shortly after the cessation of operation, (2) Shortened SAFSTOR generally has a 30-year delay prior to onset of decommissioning activities, and (3) SAFSTOR which assumes the nuclear facility is placed and
maintained in such condition that the nuclear facility can be safely stored and subsequently decontaminated generally within 60 years after cessation of operations. In each decommissioning scenario, spent fuel is transferred to dry cask storage as soon as possible until DOE acceptance for disposal.
The actual decommissioning approach selected once a nuclear facility is shutdown will be determined by Generation at the time of shutdown and may be influenced by multiple factors including the funding status of the nuclear decommissioning trust fund at the time of shutdown.
The assumed plant shutdown timing scenarios include the following four alternatives: (1) the probability of operating through the original 40-year nuclear license term, (2) the probability of operating through an extended 60-year nuclear license term (regardless of whether such 20-year license extension has been received for each unit), (3) the probability of a second, 20-year license renewal for some nuclear units, and (4) the probability of early plant retirement for certain sites due to changing market conditions and regulatory environments. The successful operation of nuclear plants in the U.S. beyond the initial 40-year license terms has prompted the NRC to consider regulatory and technical requirements for potential plant operations for an 80-year nuclear operating term. As power market and regulatory environment developments occur, Generation evaluates and incorporates, as necessary, the impacts of such developments into its nuclear ARO assumptions and estimates.
Generation’s probabilistic cash flow models also include an assessment of the timing of DOE acceptance of SNF for disposal. Generation currently assumes DOE will begin accepting SNF in 2030. The SNF acceptance date assumption is based on management’s estimates of the amount of time required for DOE to select a site location and develop the necessary infrastructure for long-term SNF storage. For additional information regarding the estimated date that DOE will begin accepting SNF, see Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements.
Discount Rates. The probability-weighted estimated future cash flows for the various assumed scenarios are discounted using credit-adjusted, risk-free rates (CARFR) applicable to the various businesses in which each of the nuclear units originally operated. Generation initially recognizes an ARO at fair value and subsequently adjusts it for changes to estimated costs, timing of future cash flows and modifications to decommissioning assumptions. The ARO is not required or permitted to be re-measured for changes in the CARFR that occur in isolation. Increases in the ARO as a result of upward revisions in estimated undiscounted cash flows are considered new obligations and are measured using a current CARFR as the increase creates a new cost layer within the ARO. Any decrease in the estimated undiscounted future cash flows relating to the ARO are treated as a modification of an existing ARO cost layer and, therefore, is measured using the average historical CARFR rates used in creating the initial ARO cost layers. If Generation’s future nominal cash flows associated with the ARO were to be discounted at current prevailing CARFR, the obligation would increase from approximately $10.5 billion to approximately $13.2 billion.Franchise Agreements
The following table illustratespresents the significant impactsize of service territories, populations of each service territory, and the number of customers within each service territory for the Utility Registrants as of December 31, 2021: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE | Service Territories (in square miles) | Electric | | 11,450 | | | 2,100 | | | 2,300 | | | 650 | | | 5,400 | | | 2,750 | | Natural Gas | | N/A | | 1,900 | | | 3,050 | | | N/A | | 250 | | | N/A | Total(a) | | 11,450 | | | 2,100 | | | 3,250 | | | 650 | | | 5,400 | | | 2,750 | | | | | | | | | | | | | | | Service Territory Population (in millions) | Electric | | 9.3 | | | 4.0 | | | 3.0 | | | 2.4 | | | 1.5 | | | 1.2 | | Natural Gas | | N/A | | 2.5 | | | 2.9 | | | N/A | | 0.6 | | | N/A | Total(b) | | 9.3 | | | 4.0 | | | 3.1 | | | 2.4 | | | 1.5 | | | 1.2 | | Main City | | Chicago | | Philadelphia | | Baltimore | | District of Columbia | | Wilmington | | Atlantic City | Main City Population | | 2.7 | | | 1.6 | | | 0.6 | | | 0.7 | | | 0.1 | | | 0.1 | | | | | | | | | | | | | | | Number of Customers (in millions) | Electric | | 4.1 | | | 1.7 | | | 1.3 | | | 0.9 | | | 0.5 | | | 0.6 | | Natural Gas | | N/A | | 0.5 | | | 0.7 | | | N/A | | 0.1 | | | N/A | Total(c) | | 4.1 | | | 1.7 | | | 1.3 | | | 0.9 | | | 0.5 | | | 0.6 | | ___________(a)The number of total service territory square miles counts once only a square mile that changesincludes both electric and natural gas services, and thus does not represent the combined total square mileage of electric and natural gas service territories. (b)The total service territory population counts once only an individual who lives in a region that includes both electric and natural gas services, and thus does not represent the combined total population of electric and natural gas service territories. (c)The number of total customers counts once only a customer who is both an electric and a natural gas customer, and thus does not represent the combined total of electric customers and natural gas customers. The Utility Registrants have the necessary authorizations to perform their current business of providing regulated electric and natural gas distribution services in the CARFR, when combinedvarious municipalities and territories in which they now supply such services. These authorizations include charters, franchises, permits, and certificates of public convenience issued by local and state governments and state utility commissions. ComEd's, BGE's (gas), Pepco DC's, and ACE's rights are generally non-exclusive while PECO's, BGE's (electric), Pepco MD's, and DPL's rights are generally exclusive. Certain authorizations are perpetual while others have varying expiration dates. The Utility Registrants anticipate working with changes in projected amountsthe appropriate governmental bodies to extend or replace the authorizations prior to their expirations.
Utility Regulations State utility commissions regulate the Utility Registrants' electric and expected timinggas distribution rates and service, issuances of cash flows, can have on the valuationcertain securities, and certain other aspects of the ARO (dollars in millions): | | | | | Change in the CARFR applied to the annual ARO update | Increase (Decrease) to ARO at December 31, 2019 | 2018 CARFR rather than the 2019 CARFR | $ | (820 | ) | 2019 CARFR increased by 50 basis points | (390 | ) | 2019 CARFR decreased by 50 basis points | 390 |
|
ARO Sensitivities. Changes in the assumptions underlying the ARO could materially affect the decommissioning obligation. The impact to the ARO of a change in any one of these assumptions is highly dependent on how the other assumptions may correspondingly change.
business. The following table illustratesoutlines the effects of changing certain ARO assumptions while holding all other assumptions constant (dollars in millions):state commissions responsible for utility oversight: | | | | | Change in ARO Assumption | Increase to ARO at December 31, 2019 | Cost escalation studies | | Uniform increase in escalation rates of 50 basis points | $ | 2,250 |
| Probabilistic cash flow models | | Increase the estimated costs to decommission the nuclear plants by 10 percent | 910 |
| Increase the likelihood of the DECON scenario by 10 percent and decrease the likelihood of the SAFSTOR scenario by 10 percent(a) | 550 |
| Shorten each unit's probability weighted operating life assumption by 10 percent(b) | 1,570 |
| Extend the estimated date for DOE acceptance of SNF to 2035 | 350 |
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__________
| | | | | | | | | (a)Registrant | Excludes any sites in which management has committed to a specific decommissioning approach. |
| Commission | (b)ComEd | Excludes any retired sites. | ICC | PECO | | PAPUC | BGE | | MDPSC | Pepco | | DCPSC/MDPSC | DPL | | DEPSC/MDPSC | ACE | | NJBPU |
The Utility Registrants are public utilities under the Federal Power Act subject to regulation by FERC related to transmission rates and certain other aspects of the utilities' business. The U.S. Department of Transportation also regulates pipeline safety and other areas of gas operations for PECO, BGE, and DPL. The U.S. Department of Homeland Security (Transportation Security Administration) provided new security directives in 2021 that regulate cyber risks for certain gas distribution operators. Additionally, the Utility Registrants are subject to NERC mandatory reliability standards, which protect the nation's bulk power system against potential disruptions from cyber and physical security breaches. Seasonality Impacts on Delivery Volumes The Utility Registrants' electric distribution volumes are generally higher during the summer and winter months when temperature extremes create demand for either summer cooling or winter heating. For PECO, BGE, and DPL, natural gas distribution volumes are generally higher during the winter months when cold temperatures create demand for winter heating. ComEd, BGE, Pepco, DPL Maryland, and ACE have electric distribution decoupling mechanisms and BGE has a natural gas decoupling mechanism that eliminate the favorable and unfavorable impacts of weather and customer usage patterns on electric distribution and natural gas delivery volumes. As a result, ComEd's, BGE's, Pepco's, DPL Maryland's, and ACE's electric distribution revenues and BGE's natural gas distribution revenues are not materially impacted by delivery volumes. PECO's and DPL Delaware's electric distribution revenues and natural gas distribution revenues are impacted by delivery volumes. Electric and Natural Gas Distribution Services The Utility Registrants are allowed to recover reasonable costs and fair and prudent capital expenditures associated with electric and natural gas distribution services and earn a return on those capital expenditures, subject to commission approval. ComEd recovers costs through a performance-based rate formula. ComEd is required to file an update to the performance-based rate formula on an annual basis. On September 15, 2021, Illinois passed the Clean Energy Law, which contains requirements for ComEd to transition away from the performance-based rate formula by the end of 2022 and would allow for the submission of either a general rate or multi-year rate plan. See Note 13 — Significant Accounting Policies, Note 6 — Early Plant Retirements and Note 9 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information regarding accounting for nuclear AROs. Goodwill (Exelon, ComEd and PHI)
As of December 31, 2019, Exelon’s $6.7 billion carrying amount of goodwill consists of $2.6 billion at ComEd, $4 billion at PHI and immaterial amounts at Generation and DPL. These entities are required to perform an assessment for possible impairment of their goodwill at least annually or more frequently if an event occurs or circumstances change that would more likely than not reduce the fair value of the reporting units below their carrying amount. A reporting unit is an operating segment or one level below an operating segment (known as a component) and is the level at which goodwill is tested for impairment. ComEd has a single operating segment and reporting unit. PHI’s operating segments and reporting units are Pepco, DPL and ACE. See Note 5 — Segment InformationRegulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. Exelon'sPECO's, BGE's, and ComEd’s goodwill hasDPL's electric and gas distribution costs and Pepco's and ACE's electric distribution costs have generally been assigned entirely torecovered through traditional rate case proceedings. However, the ComEd reporting unit. Exelon's and PHI’s goodwill has been assigned to the Pepco, DPL and ACE reporting units in the amounts of $2.1 billion, $1.4 billion and $0.5 billion, respectively. See Note 12 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information.
Entities assessing goodwill for impairment have the option of first performing a qualitative assessment to determine whether a quantitative assessment is necessary. As part of the qualitative assessments, Exelon, ComEd and PHI evaluate, among other things, management's best estimate of projected operating and capital cash flows for their businesses, outcomes of recent regulatory proceedings, changes in certain market conditions, including the discount rate and regulated utility peer EBITDA multiples,MDPSC and the passing margin fromDCPSC allow utilities to file multi-year rate plans. In certain instances, the Utility Registrants use specific recovery mechanisms as approved by their last quantitative assessments performed.respective regulatory agencies.
Application of the goodwill impairment test requires management judgment, including the identification of reporting units and determining the fair value of the reporting unit, which management estimates using a weighted combination of a discounted cash flow analysis and a market multiples analysis. Significant assumptions used in these fair value analyses include discount and growth rates, utility sector market performance and transactions, projected operating and capital cash flows for ComEd’s, Pepco's, DPL's and ACE's businesses and the fair value of debt. In applying the second step, if needed, management must estimate the fair value of specific assets and liabilities of the reporting unit.
While the annual assessments indicated no impairments, certain assumptions used in the assessment are highly sensitive to changes. Adverse regulatory actions or changes in significant assumptions could potentially result in future impairments of Exelon’s, ComEd's or PHI’s goodwill, which could be material. Based on the results of the
last annual quantitative goodwill tests performed as of November 1, 2016 and November 1, 2018 for ComEd and PHI, respectively, the estimated fair values of the ComEd, Pepco, DPL and ACE reporting units wouldcustomers have neededthe choice to decrease by more than 30%, 30%, 20%purchase electricity, and 30%, respectively,PECO and BGE customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers. DPL customers, with the exception of certain commercial and industrial customers, do not have the choice to purchase natural gas from competitive natural gas suppliers. The Utility Registrants remain the distribution service providers for ComEdall customers and PHIare obligated to fail the first step ofdeliver electricity and natural gas to customers in their respective impairment tests.service territories while charging a regulated rate for distribution service. In addition, the Utility Registrants also retain significant default service obligations to provide electricity to certain groups of customers in their respective service areas who do not choose a competitive electric generation supplier. PECO,
See Note 1 — Significant Accounting Policies
BGE, and Note 12 — Intangible AssetsDPL also retain significant default service obligations to provide natural gas to certain groups of customers in their respective service areas who do not choose a competitive natural gas supplier. For customers that choose to purchase electric generation or natural gas from competitive suppliers, the Combined Notes to Consolidated Financial Statements for additional information. Purchase Accounting (Exelon, Generation and PHI)
Assets acquired and liabilities assumed in an acquired business are recorded at their estimated fair values on the date of acquisition. The difference between the purchase price amount and the net fair value of assets acquired and liabilities assumed is recognized as goodwill on the balance sheet if the purchase price exceeds the estimated net fair value or as a bargain purchase gain on the income statement if the purchase price is less than the estimated net fair value. Determining the fair value of assets acquired and liabilities assumed requires management’s judgment, often utilizes independent valuation experts and involves the use of significant estimates and assumptions with respect to the timing and amounts of future cash inflows and outflows, discount rates, market prices and asset lives, among other items. The judgments made in the determination of the estimated fair value assigned to the assets acquired and liabilities assumed, as wellUtility Registrants act as the estimated useful life of each assetbilling agent and the duration of each liability, could significantly impact the financial statements in periods after acquisition, such as through depreciation and amortization expense. The allocation of the purchase price may be modified up to one year after the acquisition date as more information is obtained about the fair value of assets acquired and liabilities assumed. If the transaction is determined to be an asset acquisition the purchase price is allocated to the assets acquired and the liabilities assumed and no goodwilltherefore do not record Operating revenues or bargain purchase gain would be recorded. See Note 2 — Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information.
Unamortized Energy Contract Assets and Liabilities (Exelon, Generation and PHI)
Unamortized energy contract assets and liabilities represent the remaining unamortized balances of non-derivative energy contracts that Generation has acquired and the electricity contracts Exelon has acquired as part of the PHI merger. The initial amount recorded represents the fair value of the contracts at the time of acquisition. At Exelon and PHI, offsetting regulatory assets or liabilities were also recorded for those energy contract costs that are probable of recovery or refund through customer rates. The unamortized energy contract assets and liabilities and any corresponding regulatory assets or liabilities, respectively, are amortized over the life of the contract in relation to the expected realization of the underlying cash flows. Amortization of the unamortized energy contract assets and liabilities is recorded through purchasedPurchased power and fuel expense or operating revenues, depending on the nature of the underlying contract. See Note 3 — Regulatory Matters, Note 2 — Mergers, Acquisitions and Dispositions and Note 12 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information.
Impairment of Long-Lived Assets (All Registrants)
All Registrants regularly monitor and evaluate the carrying value of long-lived assets and asset groups for recoverability whenever events or changes in circumstances indicate that the carrying value of those assets may not be recoverable. Indicators of potential impairment may include a deteriorating business climate, including, but not limited to, declines in energy prices, condition of the asset, an asset remaining idle for more than a short period of time, specific regulatory disallowance, advances in technology, plans to dispose of a long-lived asset significantly before the end of its useful life, and financial distress of a third party for assets contracted with them on a long-term basis, among others.
The review of long-lived assets and asset groups for impairment utilizes significant assumptions about operating strategies and estimates of future cash flows, which require assessments of current and projected market conditions. For the generation business, forecasting future cash flows requires assumptions regarding forecasted commodity prices for the sale of power and purchases of fuel and the expected operations of assets. A variation in the assumptions used could lead to a different conclusion regarding the recoverability of an asset or asset group and, thus, could potentially result in material future impairments. An impairment evaluation is based on an undiscounted cash flow analysis at the lowest level at which cash flows of the long-lived assets or asset groups are largely independent of the cash flows of other assets and liabilities. For the generation business, the lowest level of independent cash flows is determined by the evaluation of several factors, including the geographic dispatch of the generation units and the hedging strategies related to those units as well as the associated intangible assets electricity and/or
liabilities recorded on the balance sheet. The cash flows from the generating units are generally evaluated at a regional portfolio level with cash flows generated from the customer supply and risk management activities, including cash flows from related intangible assets and liabilities on the balance sheet. In certain cases, generating assets may be evaluated on an individual basis where those assets are contracted on a long-term basis with a third party and operations are independent of other generating assets (typically contracted renewables). natural gas. For such assets the financial viability of the third party, including the impact of bankruptcy on the contract, may be a significant assumption in the assessment.
On a quarterly basis, Generation assesses its long-lived assets or asset groups for indicators of impairment. If indicators are present for a long-lived asset or asset group, a comparison of the undiscounted expected future cash flowscustomers that choose to the carrying value is performed. When the undiscounted cash flow analysis indicates the carrying value of 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 of the long-lived asset or asset group is dependent upon a market participant’s view of the exit price of the assets. This includes significant assumptions of the estimated future cash flows generated by the assets and market discount rates. Events and circumstances often do not occur as expected and there will usually be differences between prospective financial information and actual results, and those differences may be material. The determination of fair value is driven by both internal assumptions that include significant unobservable inputs (Level 3) such as revenue and generation forecasts, projected capital, and maintenance expenditures and discount rates, as well as information from various public, financial and industry sources.
See Note 11 — Asset Impairments of the Combined Notes to Consolidated Financial Statements for a discussion of asset impairment assessments.
Depreciable Lives of Property, Plant and Equipment (All Registrants)
The Registrants have significant investments inpurchase electric generation assets and electricor natural gas from a Utility Registrant, the Utility Registrants are permitted to recover the electricity and natural gas transmissionprocurement costs from customers without mark-up or with a slight mark-up and distribution assets. These assets are generally depreciated ontherefore record the amounts in Operating revenues and Purchased power and fuel expense. As a straight-line basis, using the group, compositeresult, fluctuations in electricity or unitary methods of depreciation. The group approach is typically for groups of similar assets that have approximately the same useful lives and the composite approach is used for heterogeneous assets that have different lives. Under both methods, a reporting entity depreciates the assets over the average life of the assets in the group. The estimation of asset useful lives requires management judgment, supported by formal depreciation studies of historical asset retirement experience. Depreciation studies are generally completed every five years, or more frequently if required by a rate regulator or if an event, regulatory action, or change in retirement patterns indicate an update is necessary.
For the Utility Registrants, depreciation studies generally serve as the basis for amounts allowed in customer rates for recovery of depreciation costs. Generally, the Utility Registrants adjust their depreciation rates for financial reporting purposes concurrent with adjustments to depreciation rates reflected in customer rates, unless the depreciation rates reflected in customer rates do not align with management’s judgment as to an appropriate estimated useful life or have not been updated on a timely basis. Depreciation expense and customer rates for ComEd, BGE, Pepco, DPL and ACE includes an estimate of the future costs of dismantling and removing plant from service upon retirement. See Note 3 — Regulatory Matters of the Combined Notes to the Consolidated Financial Statements for information regarding regulatory liabilities and assets recorded by ComEd, BGE, Pepco, DPL and ACE related to removal costs.
PECO’s removal costs are capitalized to accumulated depreciation when incurred, and recorded to depreciation expense over the life of the new asset constructed consistent with PECO’s regulatory recovery method. Estimates for such removal costs are also evaluated in the periodic depreciation studies.
At Generation, along with depreciation study results, management considers expected future energy market conditions and generation plant operating costs and capital investment requirements in determining the estimated service lives of its generating facilities. See Note 6 — Early Plant Retirements of the Combined Notes to the Consolidated Financial Statements for additional information.
Changes in estimated useful lives of electric generation assets and of electric and natural gas transmissionsales and distribution assets couldprocurement costs have ano significant impact on the Utility Registrants’ future results of operations. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for information regarding depreciation and estimated service lives of the property, plant and equipment of the Registrants.Net income.
Defined Benefit Pension and Other Postretirement Employee Benefits (All Registrants)
Exelon sponsors defined benefit pension plans and other postretirement employee benefit plans for substantially all current employees. The measurement of the plan obligations and costs of providing benefits involves various factors, including the development of valuation assumptions and inputs and accounting policy elections. When developing the required assumptions, Exelon considers historical information as well as future expectations. The measurement of benefit obligations and costs is affected by several assumptions including the discount rate applied to benefit obligations, the long-term expected rate of return on plan assets, the anticipated rate of increase of health care costs, Exelon’s expected level of contributions to the plans, the incidence of participant mortality, the expected remaining service period of plan participants, the level of compensation and rate of compensation increases, employee age, length of service, and the long-term expected investment rate credited to employees of certain plans, among others. The assumptions are updated annually and upon any interim remeasurement of the plan obligations. Exelon amortizes actuarial gains or losses in excess of a corridor of 10% of the greater of the projected benefit obligation or the market-related value (MRV) of plan assets over the expected average remaining service period of plan participants.
Pension and other postretirement benefit plan assets include equity securities, including U.S. and international securities, and fixed income securities, as well as certain alternative investment classes such as real estate, private equity and hedge funds.
Expected Rate of Return on Plan Assets. In determining the EROA, Exelon considers historical economic indicators (including inflation and GDP growth) that impact asset returns, as well as expectation regarding future long-term capital market performance, weighted by Exelon’s target asset class allocations. Exelon calculates the amount of expected return on pension and other postretirement benefit plan assets by multiplying the EROA by the MRV of plan assets at the beginning of the year, taking into consideration anticipated contributions and benefit payments to be made during the year. In determining MRV, the authoritative guidance for pensions and postretirement benefits allows the use of either fair value or a calculated value that recognizes changes in fair value in a systematic and rational manner over not more than five years. For the majority of pension plan assets, Exelon uses a calculated value that adjusts for 20% of the difference between fair value and expected MRV of plan assets. Use of this calculated value approach enables less volatile expected asset returns to be recognized as a component of pension cost from year to year. For other postretirement benefit plan assets and certain pension plan assets, Exelon uses fair value to calculate the MRV.
Discount Rate. At December 31, 2019 and 2018, the discount rates were determined by developing a spot rate curve based on the yield to maturity of a universe of high-quality non-callable (or callable with make whole provisions) bonds with similar maturities to the related pension and other postretirement benefit obligations. The spot rates are used to discount the estimated future benefit distribution amounts under the pension and other postretirement benefit plans. The discount rate is the single level rate that produces the same result as the spot rate curve. Exelon utilizes an analytical tool developed by its actuaries to determine the discount rates.
Mortality. The mortality assumption is composed of a base table that represents the current expectation of life expectancy of the population adjusted by an improvement scale that attempts to anticipate future improvements in life expectancy. Exelon’s mortality assumption is supported by an actuarial experience study of Exelon's plan participants and beginning in 2019, utilizes the Society of Actuaries' 2019 base table (Pri-2012) and MP-2019 improvement scale adjusted to a 0.75% long-term rate reached in 2035.
Sensitivity to Changes in Key Assumptions. The following tables illustrate the effects of changing certain of the actuarial assumptions discussed above, while holding all other assumptions constant (dollars in millions):
| | | | | | | | | | | | | | | | | | | | Actual Assumption | | | | | | | | | Actuarial Assumption | Pension | | OPEB | | Change in Assumption | | Pension | | OPEB | | Total | Change in 2019 cost: | | | | | | | | | | | | Discount rate (a) | 4.31% | | 4.30% | | 0.5% | | $ | (47 | ) | | $ | (14 | ) | | $ | (61 | ) | | 4.31% | | 4.30% | | (0.5)% | | 47 |
| | 13 |
| | 60 |
| EROA | 7.00% | | 6.67% | | 0.5% | | (88 | ) | | (11 | ) | | (99 | ) | | 7.00% | | 6.67% | | (0.5)% | | 88 |
| | 11 |
| | 99 |
| Change in benefit obligation at December 31, 2019: | | | | | | | | | | | | Discount rate (a) | 3.34% | | 3.31% | | 0.5% | | (1,244 | ) | | (247 | ) | | (1,491 | ) | | 3.34% | | 3.31% | | (0.5)% | | 1,316 |
| | 261 |
| | 1,577 |
|
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| | (a) | In general, the discount rate will have a larger impact on the pension and other postretirement benefit cost and obligation as the rate moves closer to 0%. Therefore, the discount rate sensitivities above cannot necessarily be extrapolated for larger increases or decreases in the discount rate. Additionally, Exelon utilizes a liability-driven investment strategy for its pension asset portfolio. The sensitivities shown above do not reflect the offsetting impact that changes in discount rates may have on pension asset returns. |
See Note 14 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information regarding the accounting for the defined benefit pension plans and other postretirement benefit plans. Regulatory Accounting (Exelon and Utility Registrants)
For their regulated electric and gas operations, Exelon and the Utility Registrants reflect the effects of cost-based rate regulation in their financial statements, which is required for entities with regulated operations that meet the following criteria: (1) rates are established or approved by a third-party regulator; (2) rates are designed to recover the entities’ cost of providing services or products; and (3) a reasonable expectation that rates designed to recover costs can be charged to and collected from customers. Regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent (1) revenue or gains that have been deferred because it is probable such amounts will be returned to customers through future regulated rates; or (2) billings in advance of expenditures for approved regulatory programs. If it is concluded in a future period that a separable portion of operations no longer meets the criteria discussed above, Exelon and the Utility Registrants would be required to eliminate any associated regulatory assets and liabilities and the impact would be recognized in the Consolidated StatementsITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, Results of Operations and Comprehensive Income and could be material.
The following table illustrates the gains (losses) that could result from the elimination of regulatory assets and liabilities and charges against OCI (dollars in millions before taxes) related to deferred costs associated with Exelon's pension and other postretirement benefit plans that are recorded as regulatory assets in Exelon's Consolidated Balance Sheets:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2019 | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Gain (loss) | $ | 887 |
| | $ | 4,981 |
| | $ | 6 |
| | $ | 591 |
| | $ | (696 | ) | | $ | (18 | ) | | $ | 337 |
| | $ | (43 | ) | Charge against OCI(a) | $ | 3,864 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
___________
| | (a) | Exelon's charge against OCI (before taxes) consists of up to $2.3 billion, $176 million, $176 million, $396 million, $191 million and $86 million related to ComEd's, BGE's, PHI's, Pepco's, DPL's and ACE's respective portions of the deferred costs associated with Exelon's pension and other postretirement benefit plans. Exelon also has a net regulatory liability of $(44) million (before taxes) related to PECO’s portion of the deferred costs associated with Exelon’s other postretirement benefit plans that would result in an increase in OCI if reversed. |
See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information regarding regulatory matters,electric and natural gas distribution services.
Procurement of Electricity and Natural Gas The Utility Registrants' electric supply for its customers is primarily procured through contracts as required by their respective state commissions. The Utility Registrants procure electricity supply from various approved bidders, including Generation. RTO spot market purchases and sales are utilized to balance the regulatory assetsutility electric load and liabilities tables of Exelon andsupply as required. Charges incurred for electric supply procured through contracts with Generation are included in Purchased power from affiliates on the Utility Registrants.Registrants' Statements of Operations and Comprehensive Income. For each regulatory jurisdictionPECO's, BGE’s, and DPL's natural gas supplies are purchased from a number of suppliers for terms of up to three years. PECO, BGE, and DPL have annual firm supply and transportation contracts of 137,000 mmcf, 268,000 mmcf and 61,000 mmcf, respectively. In addition, to supplement gas supply at times of heavy winter demands and in which they conduct business, Exelonthe event of temporary emergencies, PECO, BGE, and DPL have available storage capacity from the Utility Registrants assess whetherfollowing sources:
| | | | | | | | | | | | | | | | | | | Peak Natural Gas Sources (in mmcf) | | LNG Facility | | Propane-Air Plant | | Underground Storage Service Agreements (a) | PECO | 1,200 | | | 150 | | | 19,400 | | BGE | 1,056 | | | 550 | | | 22,000 | | DPL | 250 | | | N/A | | 3,900 | |
___________ (a)Natural gas from underground storage represents approximately 28%, 20%, and 33% of PECO's, BGE’s, and DPL's 2021-2022 heating season planned supplies, respectively. PECO, BGE, and DPL have long-term interstate pipeline contracts and also participate in the regulatory assets and liabilities continueinterstate markets by releasing pipeline capacity or bundling pipeline capacity with gas for off-system sales. Off-system gas sales are low-margin direct sales of gas to meet the criteria for probable future recovery or settlement at each balance sheet date and when regulatory events occur. This assessment includes considerationwholesale suppliers of recent rate orders, historical regulatory treatment for similar costs in each Registrant's jurisdictions, and factors such as changes in applicable regulatory and political environments. If the assessments and estimates made by Exelon and the Utility Registrants for regulatory assets and regulatory liabilities are ultimately different than actual regulatory outcomes, the impact in their consolidated financial statements could be material. Refer to the revenue recognition discussion below for additional information on the annual revenue reconciliations associated with ICC-approved electric distribution and energy efficiency formula rates for ComEd, and FERC transmission formula rate tariffs for the Utility Registrants.
Accounting for Derivative Instruments (All Registrants)
The Registrants use derivative instruments to manage commodity price risk, foreign currency exchange risk and interest rate risk related to ongoing business operations. The Registrants’ derivativenatural gas. Earnings from these activities are in accordance with Exelon’s Risk Management Policy (RMP). See Note 15 — Derivative Financial Instruments ofshared between the Combined Notes to Consolidated Financial Statements for additional information.
The Registrants account for derivative financial instruments under the applicable authoritative guidance. Determining whether a contract qualifies as a derivative requires that management exercise significant judgment, including assessing market liquidity as well as determining whether a contract has one or more underlyingsutilities and one or more notional quantities. Changes in management’s assessment of contractscustomers. PECO, BGE, and the liquidity of their markets, and changes in authoritative guidance, could result in previously excluded contracts becoming in scope to new authoritative guidance.
All derivatives are recognized on the balance sheet at their fair value, except for certain derivatives that qualify for, and are elected under, NPNS. Derivatives entered into for economic hedging and for proprietary trading purposes are recorded at fair value through earnings. For economic hedges that are not designated for hedge accounting for the Utility Registrants, changes in the fair value each period are generally recorded with a corresponding offsetting regulatory asset or liability given likelihood of recovering the associated costs through customer rates.
Normal Purchases and Normal Sales Exception. As part of Generation’s energy marketing business, Generation enters into contracts to buy and sell energy to meet the requirements of its customers. These contracts include short-term and long-term commitments to purchase and sell energy and energy-related products in the retail and wholesale markets with the intent and ability to deliver or take delivery. While some ofDPL make these contracts are considered derivative financial instruments under the authoritative guidance, certain of these qualifying transactions have been designated by Generation as NPNS transactions, which are thus not required to be recorded at fair value, but rather on an accrual basis of accounting. Determining whether a contract qualifies for the NPNS requires judgment on whether the contract will physically deliver and requires that management ensure compliance with all of the associated qualification and documentation requirements. Revenues and expenses on contracts that qualify as NPNS are recognized when the underlying physical transaction is completed. Contracts that qualify for the NPNS are those for which physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable period of time and the contract is not financially settled on a net basis. The contracts that ComEd has entered into with supplierssales as part of ComEd’s energy procurement process, PECO’s full requirement contracts under the PAPUC-approved DSPa program mostto balance its supply and cost of PECO’s natural gas. The off-system gas supply agreements, all of BGE’s full requirement contracts and natural gas supply agreements thatsales are derivatives and certain Pepco, DPL and ACE full requirement contracts qualify for and are accounted for under the NPNS.
Commodity Contracts. Identification of a commodity contract as an economic hedge requires Generation to determine that the contract is in accordance with the RMP. Generation reassesses its economic hedges on a regular basis to determine if they continue to be within the guidelines of the RMP.
As a part of the authoritative guidance, the Registrants make estimates and assumptions concerning future commodity prices, load requirements, interest rates, the timing of future transactions and their probable cash flows, the fair value of contracts and the expected changes in the fair value in deciding whether or not to enter into derivative
transactions, and in determining the initial accounting treatment for derivative transactions. Under the authoritative guidance for fair value measurements, the Registrants categorize these derivatives under a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value.
Derivative contracts are traded in both exchange-based and non-exchange-based markets. Exchange-based derivatives that are valued using unadjusted quoted prices in active markets are generally categorized in Level 1 in the fair value hierarchy.
Certain derivatives’ pricing is verified using indicative price quotations available through brokers or over-the-counter, on-line exchanges. The price quotations reflect the average of the bid-ask mid-point from markets that the Registrants believe provide the most liquid market for the commodity. The price quotations are reviewed and corroborated to ensure the prices are observable and representative of an orderly transaction between market participants. The Registrant’s derivatives are traded predominately at liquid trading points. The remaining derivative contracts are valued using models that consider inputs such as contract terms, including maturity, and market parameters, and assumptions of the future prices of energy, interest rates, volatility, credit worthiness and credit spread. For derivatives that trade in liquid markets, such as generic forwards, swaps and options, the model inputs are generally observable. Such instruments are categorized in Level 2.
For derivatives that trade in less liquid markets with limited pricing information, the model inputs generally would include both observable and unobservable inputs and are categorized in Level 3.
The Registrants consider nonperformance risk, including credit risk in the valuation of derivative contracts, including both historical and current market data in its assessment of nonperformance risk, including credit risk. The impacts of nonperformance and credit risk to date have generally not been material to the financial statements.PECO, BGE, and DPL.
See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK, and Note 17 — Fair Value of Financial Assets and Liabilities and Note 15 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial StatementsCommodity Price Risk (All Registrants), for additional information regarding the Registrants’ derivative instruments.Utility Registrants' contracts to procure electric supply and natural gas. Taxation (All Registrants)
Significant management judgment is required in determining the Registrants’ provisions for income taxes, primarily due to the uncertainty related to tax positions taken, as well as deferred tax assets and liabilities and valuation allowances. The Registrants account for uncertain income tax positions using a benefit recognition model with a two-step approach including a more-likely-than-not recognition threshold and a measurement approach based on the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. Management evaluates each position based solely on the technical merits and facts and circumstances of the position, assuming the position will be examined by a taxing authority having full knowledge of all relevant information. Significant judgment is required to determine whether the recognition threshold has been met and, if so, the appropriate amount of tax benefits to be recorded in the Registrants’ consolidated financial statements.Energy Efficiency Programs
The Registrants evaluate quarterly the probability of realizing deferred tax assets by reviewing a forecast of future taxable income and their intent and ability to implement tax planning strategies, if necessary, to realize deferred tax assets. The Registrants also assess negative evidence, such as the expiration of historical operating loss or tax credit carryforwards, that could indicate the Registrant's inability to realize its deferred tax assets. Based on the combined assessment, the Registrants record valuation allowances for deferred tax assets when it is more-likely-than-not such benefit will not be realized in future periods. Actual income taxes could vary from estimated amounts due to the future impacts of various items, including future changes in income tax laws, the Registrants’ forecasted financial condition and results of operations, failure to successfully implement tax planning strategies, as well as results of audits and examinations of filed tax returns by taxing authorities. See Note 13 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.
Accounting for Loss Contingencies (All Registrants)
In the preparation of their financial statements, the Registrants make judgments regarding the future outcome of contingent events and record liabilities for loss contingencies that are probable and can be reasonably estimated based upon available information. The amount recorded may differ from the actual expense incurred when the
uncertainty is resolved. Such difference could have a significant impact in the Registrants' consolidated financial statements.
Environmental Costs. Environmental investigation and remediation liabilities are based upon estimates with respect to the number of sites for which the Registrants will be responsible, the scope and cost of work to be performed at each site, the portion of costs that will be shared with other parties, the timing of the remediation work and changes in technology, regulations and the requirements of local governmental authorities. Annual studies and/or reviews are conducted at ComEd, PECO, BGE and DPL to determine future remediation requirements for MGP sites and estimates are adjusted accordingly. In addition, periodic reviews are performed at each of the Registrants to assess the adequacy of other environmental reserves. These matters, if resolved in a manner different from the estimate, could have a significant impact in the Registrants’ consolidated financial statements. See Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.
Other, Including Personal Injury Claims. TheUtility Registrants are self-insured for general liability, automotive liability, workers’ compensation, and personal injury claimsgenerally allowed to the extent that losses are within policy deductibles or exceed the amount of insurance maintained. The Registrants have reserves for both open claims asserted and an estimate of claims incurred but not reported (IBNR). The IBNR reserve is estimated based on actuarial assumptions and analysis and is updated annually. Future events, such as the number of new claims to be filed each year, the average cost of disposing of claims, as well as the numerous uncertainties surrounding litigation and possible state and national legislative measures could cause the actualrecover costs to be higher or lower than estimated. Accordingly, these claims, if resolved in a manner different fromassociated with the estimate, could have a material impact in the Registrants’ consolidated financial statements.
Revenue Recognition (All Registrants)
Sources of Revenue and Determination of Accounting Treatment. The Registrants earn revenues from various business activities including: the sale of power and energy-related products, such as natural gas, capacity, and other commodities in non-regulated markets (wholesale and retail); the sale and delivery of power and natural gas in regulated markets; and the provision of other energy-related non-regulated products and services.
The accounting treatment for revenue recognition is based on the nature of the underlying transaction and applicable authoritative guidance. The Registrants primarily apply the Revenue from Contracts with Customers, Derivative and Alternative Revenue Program (ARP) guidance to recognize revenue as discussed in more detail below.
Revenue from Contracts with Customers. The Registrants recognize revenues in the period in which the performance obligations within contracts with customers are satisfied, which generally occurs when power, natural gas, and other energy-related commodities are physically delivered to the customer. Transactions of the Registrants within the scope of Revenue from Contracts with Customers generally include non-derivative agreements, contracts that are designated as NPNS, sales to utility customers under regulated service tariffs, and spot-market energy commodity sales, including settlements with independent system operators.
The determination of Generation’s and the Utility Registrants' retail power and natural gas sales to individual customers is based on systematic readings of customer meters, generally on a monthly basis. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated, and corresponding unbilled revenue is recorded. The measurement of unbilled revenue is affected by the following factors: daily customer usage measured by generation or gas throughput volume, customer usage by class, losses of energy during delivery to customers and applicable customer rates. Increases or decreases in volumes delivered to the utilities’ customers and favorable or unfavorable rate mix due to changes in usage patterns in customer classes in the period could be significant to the calculation of unbilled revenue. In addition, revenues may fluctuate monthly as a result of customers electing to use an alternate supplier, since unbilled commodity revenues are not recorded for these customers. Changes in the timing of meter reading schedules and the number and type of customers scheduled for each meter reading date also impact the measurement of unbilled revenue; however, total operating revenues would remain materially unchanged. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional information.
Derivative Revenues. The Registrants record revenues and expenses using the mark-to-market method of accounting for transactions that are accounted for as derivatives. These derivative transactions primarily relate to commodity price risk management activities. Mark-to-market revenues and expenses include: inception gains or
losses on new transactions where the fair value is observable, unrealized gains and losses from changes in the fair value of open contracts, and realized gains and losses.
Alternative Revenue Program Accounting. Certain of the Utility Registrants’ ratemaking mechanisms qualify as ARPs if they (i) are established by a regulatory order and allow for automatic adjustment to future rates, (ii) provide for additional revenues (above those amounts currently reflected in the price of utility service) that are objectively determinable and probable of recovery, and (iii) allow for the collection of those additional revenues within 24 months following the end of the period in which they were recognized. For mechanisms that meet these criteria, which include the Utility Registrants’ formula rate and revenue decoupling mechanisms, the Utility Registrants adjust revenue and record an offsetting regulatory asset or liability once the condition or event allowing additional billing or refund has occurred. The ARP revenues presented in the Utility Registrants’ Consolidated Statements of Operations and Comprehensive Income include both: (i) the recognition of “originating” ARP revenues (when the regulator-specified condition or event allowing for additional billing or refund has occurred) and (ii) an equal and offsetting reversal of the “originating” ARP revenues as those amounts are reflected in the price of utility service and recognized as Revenue from Contracts with Customers.
ComEd records ARP revenue for its best estimate of the electric distribution, energy efficiency and transmission revenue impacts resulting from future changes in rates that demand response programs they offer. Each commission approved program seeks to meet mandated electric consumption reduction targets and implement demand response measures to reduce peak demand. The programs are designed to meet standards required by each respective regulatory agency.
ComEd believes are probable of approval by the ICC and FERC in accordance with its formula rate mechanisms. BGE, Pepco and DPL record ARP revenue for their best estimate of the electric and natural gas distribution revenue impacts resulting from future changes in rates that they believe are probable of approval by the MDPSC and/or DCPSC in accordance with their revenue decoupling mechanisms. PECO, BGE, Pepco, DPL and ACE record ARP revenue for their best estimate of the transmission revenue impacts resulting from future changes in rates that they believe are probable of approval by FERC in accordance with their formula rate mechanisms. Estimates of the current year revenue requirement are based on actual and/or forecasted costs and investments in rate base for the period and the rates ofis allowed to earn a return on common equity and associated regulatory capital structure allowed under the applicable tariff. The estimated reconciliation can be affected by, among other things, variances in costs incurred, investments made, allowed ROE, and actions by regulators or courts. its energy efficiency costs. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Capital Investment The Utility Registrants' businesses are capital intensive and require significant investments, primarily in electric transmission and distribution and natural gas transportation and distribution facilities, to ensure the adequate capacity, reliability, and efficiency of their systems. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, Liquidity and Capital Resources, for Uncollectible Accounts (Utility Registrants)additional information regarding projected 2022 capital expenditures. Transmission Services Under FERC’s open access transmission policy, the Utility Registrants, estimateas owners of transmission facilities, are required to provide open access to their transmission facilities under filed tariffs at cost-based rates approved by FERC. The Utility Registrants and their affiliates are required to comply with FERC’s Standards of Conduct regulation governing the allowancecommunication of non-public transmission information between the transmission owner’s employees and wholesale merchant employees. PJM is the regional grid operator and operates pursuant to FERC-approved tariffs. PJM is the transmission provider under, and the administrator of, the PJM Open Access Transmission Tariff (PJM Tariff). PJM operates the PJM energy, capacity, and other markets, and, through central dispatch, controls the day-to-day operations of the bulk power system for uncollectible accounts on customer receivables by applying loss rates developed specifically for each companythe region. The Utility Registrants are members of PJM and provide regional transmission service pursuant to the outstanding receivable balance by customer risk segment. Risk segments representPJM Tariff. The Utility Registrants and the other transmission owners in PJM have turned over control of certain of their transmission facilities to PJM, and their transmission systems are under the dispatch control of PJM. Under the PJM Tariff, transmission service is provided on a groupregion-wide, open-access basis using the transmission facilities of customers with similar credit quality indicators that are comprisedthe PJM transmission owners at rates based on various attributes, including delinquencythe costs of their balances and payment history. Losstransmission service. The Utility Registrants' transmission rates applied to the accounts receivable balances are established based on a historical averageFERC approved formula as shown below: | | | | | | | Approval Date | ComEd | January 2008 | PECO | December 2019 | BGE | April 2006 | Pepco | April 2006 | DPL | April 2006 | ACE | April 2006 |
Exelon’s Strategy and Outlook In 2021, the businesses remained focused on maintaining industry leading operational excellence, meeting or exceeding their financial commitments, ensuring timely recovery on investments to enable customer benefits, supporting enactment of charge-offs as a percentage of accounts receivable in each risk segment.clean energy policies, and continued commitment to corporate responsibility. Exelon’s strategy is to improve reliability and operations, enhance the customer experience, and advance clean and affordable energy choices, while ensuring ratemaking mechanisms provide the utilities fair financial returns. The Utility Registrants'Registrants only invest in rate base where it provides a benefit to customers and the community by improving reliability and the service experience or otherwise meeting customer accounts are generally considered delinquent ifneeds. The Utility Registrants make these investments at the amount billedlowest reasonable cost to customers. Exelon seeks to leverage its scale and expertise across the utilities platform through enhanced standardization and sharing of resources and best practices to achieve improved operational and financial results. Additionally, the Utility Registrants anticipate making significant future investments in smart grid technology, transmission projects, gas infrastructure, and electric system improvement projects, providing greater reliability, improved service for our customers, increased capacity to accommodate new technologies, and a stable return for the company. Management continually evaluates growth opportunities aligned with Exelon’s businesses, assets and markets leveraging Exelon’s expertise in those areas and offering sustainable returns. The Utility Registrants anticipate investing approximately $29 billion over the next four years in electric and natural gas infrastructure improvements and modernization projects, including smart grid technology, storm
hardening, advanced reliability technologies, and transmission projects, which is not receivedprojected to result in an increase to current rate base of approximately $17 billion by the timeend of 2025. The Utility Registrants invest in rate base where beneficial to customers and the next billcommunity by increasing reliability and the service experience or otherwise meeting customer needs. These investments are made at the lowest reasonable cost to customers. 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. See ITEM 1. BUSINESS — Environmental Matters and Regulation — Climate Change for additional information. Various market, financial, regulatory, legislative and operational factors could affect Exelon's success in pursuing its strategies. Exelon continues to assess infrastructure, operational, policy, and legal solutions to these issues. See ITEM 1A. RISK FACTORS for additional information. Employees The Registrants strive to create a workplace that is issued, which normally occursdiverse, innovative, and safe for their employees. In order to provide the services and products that their customers expect, the Registrants must create the best teams. These teams must reflect the diversity of the communities that the Registrants serve. Therefore, the Registrants strive to attract highly qualified and diverse talent and routinely review their hiring and promotion practices to ensure they maintain equitable and bias free processes to neutralize any unconscious bias. The Registrants provide growth opportunities, competitive compensation and benefits, and a variety of training and development programs. The Registrants are committed to helping employees grow their skills and careers largely through numerous training opportunities in technical, safety and business acumen areas, mentorship programs, and continuous feedback and development discussions and evaluations. Employees are encouraged to thrive outside the workplace as well. The Registrants provide a full suite of wellness benefits targeted at supporting work-life balance, physical, mental and financial health, and industry-leading paid leave policies. The Registrants generally conduct an employee engagement survey every other year to help identify their successes and areas where they can grow. The survey results are reviewed with senior management and the Exelon Board of Directors. Diversity Metrics The following tables show diversity metrics for all employees and management as of December 31, 2021. The Exelon numbers include all subsidiaries, including Generation. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Employees | | Exelon | | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Female(a) (b) | | 7,892 | | | | | 1,505 | | | 752 | | | 753 | | | 1,269 | | | 339 | | | 143 | | | 105 | | People of Color(b) | | 9,436 | | | | | 2,464 | | | 929 | | | 1,115 | | | 1,760 | | | 873 | | | 196 | | | 139 | | Aged <30 | | 3,236 | | | | | 653 | | | 315 | | | 280 | | | 413 | | | 169 | | | 87 | | | 58 | | Aged 30-50 | | 17,008 | | | | | 3,566 | | | 1,337 | | | 1,728 | | | 2,241 | | | 748 | | | 458 | | | 361 | | Aged >50 | | 11,274 | | | | | 2,037 | | | 1,157 | | | 1,120 | | | 1,532 | | | 472 | | | 365 | | | 214 | | Total Employees(c) | | 31,518 | | | | | 6,256 | | | 2,809 | | | 3,128 | | | 4,186 | | | 1,389 | | | 910 | | | 633 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Management(d) | | Exelon | | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Female(a) (b) | | 1,242 | | | | | 219 | | | 123 | | | 116 | | | 179 | | | 49 | | | 11 | | | 19 | | People of Color(b) | | 1,233 | | | | | 308 | | | 117 | | | 146 | | | 246 | | | 113 | | | 27 | | | 20 | | Aged <30 | | 73 | | | | | 6 | | | 7 | | | 1 | | | 8 | | | 3 | | | — | | | 2 | | Aged 30-50 | | 2,857 | | | | | 469 | | | 157 | | | 256 | | | 356 | | | 105 | | | 58 | | | 44 | | Aged >50 | | 2,107 | | | | | 365 | | | 194 | | | 161 | | | 266 | | | 67 | | | 59 | | | 40 | | Within 10 years of retirement eligibility | | 2,876 | | | | | 497 | | | 239 | | | 226 | | | 368 | | | 92 | | | 74 | | | 53 | | Total Employees in Management(c) | | 5,037 | | | | | 840 | | | 358 | | | 418 | | | 630 | | | 175 | | | 117 | | | 86 | |
__________ (a)The Registrants are devoted to creating an environment that allows women to stay in the workforce, grow with the company, and move up the ranks, all with parity of pay. Exelon employs an independent third-party vendor to run regression analysis on a monthly basis. Utility Registrants' customer accounts are written off consistent with approved regulatory requirements. Utility Registrants' allowances for uncollectible accounts will continue to be affected by changes in volume, pricesall management positions each year. The analysis consistently shows that the Registrants have no systemic pay equity issues. (b)This is based on self-disclosed information. (c)Total employees represents the sum of the aged categories. (d)Management is defined as executive/senior level officials and economic conditionsmanagers as well as changes in ICC, PAPUC, MDPSC, DCPSC, DPSCall employees who have direct reports and NJBPU regulations.supervisory responsibilities. Results of Operations by RegistrantAs turnover is inherent, management succession planning is performed and tracked for all executives and critical key manager positions. Management frequently reviews succession planning to ensure the Registrants are prepared when positions become available.
The Registrants' Resultstable below shows the average turnover rate for all employees for the last three years of Operations includes discussion2019 to 2021. The Exelon numbers include all subsidiaries, including Generation. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exelon | | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Retirement Age | | 4.27 | % | | | | 3.82 | % | | 3.47 | % | | 3.70 | % | | 4.02 | % | | 4.37 | % | | 4.10 | % | | 3.17 | % | Voluntary | | 2.98 | % | | | | 1.49 | % | | 1.76 | % | | 1.36 | % | | 2.06 | % | | 2.36 | % | | 1.11 | % | | 1.20 | % | Non-Voluntary | | 0.98 | % | | | | 0.56 | % | | 1.06 | % | | 0.94 | % | | 0.96 | % | | 1.87 | % | | 0.32 | % | | 0.68 | % |
Collective Bargaining Agreements Approximately 37% of RNF, which isExelon’s employees participate in CBAs. The following table presents employee information, including information about CBAs, as of December 31, 2021. The Exelon numbers include all subsidiaries, including Generation. | | | | | | | | | | | | | | | | | | | | | | | | | Total Employees Covered by CBAs | | Number of CBAs | | CBAs New and Renewed in 2021(a) | | Total Employees Under CBAs New and Renewed in 2021 | Exelon | 11,770 | | | 32 | | | 8 | | | 6,476 | | | | | | | | | | ComEd | 3,478 | | | 2 | | | 2 | | | 3,478 | | PECO | 1,351 | | | 2 | | | 2 | | | 1,351 | | BGE | 1,416 | | | 1 | | | — | | | — | | PHI | 2,161 | | | 5 | | | — | | | — | | Pepco | 929 | | | 1 | | | — | | | — | | DPL | 631 | | | 2 | | | — | | | — | | ACE | 387 | | | 2 | | | — | | | — | |
__________ (a)Does not include CBAs that were extended in 2021 while negotiations are ongoing for renewal.
Environmental Matters and Regulation On February 21, 2021, Exelon's Board of Directors approved a financial measure not defined under GAAP and may not be comparableplan to other companies' presentations or deemed more useful than the GAAP information provided elsewhere in this report. The CODMs for Exelon and Generation evaluate the performance of Generation's electric business activities and allocate resources based on RNF. Generation believes that RNF is a useful measure because it provides information that can be used to evaluate its operational performance. Forseparate the Utility Registrants their Operating revenues reflect the full and current recovery of commodity procurement costs given the rider mechanisms approved by their respective state regulators.Generation, creating two publicly traded companies. The commodity procurement costs, which are recorded in Purchased power and fuel expense, and the associated revenues can be volatile. Therefore, the Utility Registrants believe that RNF is a useful measure because it excludes the effectseparation was completed on Operating revenues caused by the volatility in these expenses.
Results of Operations—Generation
| | | | | | | | | | | | | | | | | | | | | | 2019 | | 2018 | | Favorable (unfavorable) 2019 vs. 2018 variance | | 2017 | | Favorable (unfavorable) 2018 vs. 2017 variance | Operating revenues | $ | 18,924 |
| | $ | 20,437 |
| | $ | (1,513 | ) | | $ | 18,500 |
| | $ | 1,937 |
| Purchased power and fuel expense | 10,856 |
| | 11,693 |
| | 837 |
| | 9,690 |
| | (2,003 | ) | Revenues net of purchased power and fuel expense | 8,068 |
|
| 8,744 |
| | (676 | ) | | 8,810 |
| | (66 | ) | Other operating expenses | | | | |
|
| | | |
| Operating and maintenance | 4,718 |
| | 5,464 |
| | 746 |
| | 6,299 |
| | 835 |
| Depreciation and amortization | 1,535 |
| | 1,797 |
| | 262 |
| | 1,457 |
| | (340 | ) | Taxes other than income taxes | 519 |
| | 556 |
| | 37 |
| | 555 |
| | (1 | ) | Total other operating expenses | 6,772 |
|
| 7,817 |
| | 1,045 |
| | 8,311 |
| | 494 |
| Gain (loss) on sales of assets and businesses | 27 |
| | 48 |
| | (21 | ) | | 2 |
| | 46 |
| Bargain purchase gain | — |
| | — |
| | — |
| | 233 |
| | (233 | ) | Gain on deconsolidation of business | — |
| | — |
| | — |
| | 213 |
| | (213 | ) | Operating income | 1,323 |
|
| 975 |
|
| 348 |
| | 947 |
| | 28 |
| Other income and (deductions) | | | | | | | | |
| Interest expense | (429 | ) | | (432 | ) | | 3 |
| | (440 | ) | | 8 |
| Other, net | 1,023 |
| | (178 | ) | | 1,201 |
| | 948 |
| | (1,126 | ) | Total other income and (deductions) | 594 |
|
| (610 | ) |
| 1,204 |
| | 508 |
| | (1,118 | ) | Income before income taxes | 1,917 |
|
| 365 |
|
| 1,552 |
| | 1,455 |
| | (1,090 | ) | Income taxes | 516 |
| | (108 | ) | | (624 | ) | | (1,376 | ) | | (1,268 | ) | Equity in losses of unconsolidated affiliates | (184 | ) | | (30 | ) | | (154 | ) | | (33 | ) | | 3 |
| Net income | 1,217 |
|
| 443 |
|
| 774 |
| | 2,798 |
| | (2,355 | ) | Net income attributable to noncontrolling interests | 92 |
| | 73 |
| | (19 | ) | | 88 |
| | (15 | ) | Net income attributable to membership interest | $ | 1,125 |
|
| $ | 370 |
|
| $ | 755 |
| | $ | 2,710 |
| | $ | (2,340 | ) |
Year Ended December 31, 2019 Compared to Year Ended December 31, 2018. Net income attributable to membership interest increased by $755 million primarily due to:
Higher net unrealized and realized gains on NDT funds;
| | • | Decreased accelerated depreciation and amortization due to the early retirement of the Oyster Creek nuclear facility in September 2018 and TMI in September 2019and the absence of a charge associated with the remeasurement of the Oyster Creek ARO;
|
Decreased operating and maintenance expense at Generation which includes the impacts of previous cost management programs and lower pension and OPEB costs, and increased NEIL insurance distributions;
| | • | A benefit associated with the remeasurement of the TMI ARO in the first quarter of 2019and the annual nuclear ARO update in the third quarter of 2019;
|
Decreased nuclear outage days;
Lower mark-to-market losses;
| | • | Research and development income tax credits.
|
The increases were partially offset by;
| | • | Lower realized energy prices;and
|
Lower capacity prices.
Revenues Net of Purchased Power and Fuel Expense. 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. During the first quarter of 2019, due to a change in economics in our New England region, Generation changed the way that information is reviewed by the CODM. The New England region will no longer be regularly reviewed as a separate region by the CODM nor will it be presented separately in any external information presented to third parties. Information for the New England region will be reviewed by the CODM as part of Other Power Regions.February 1, 2022. See Note 526 — Segment InformationSeparation of the Combined Notes to Consolidated Financial Statements for additional information on these reportable segments.information. As such, the disclosures below do not include disclosures associated with Generation.
The following business activitiesRegistrants are not allocatedsubject to comprehensive and complex environmental legislation and regulation at the federal, state, and local levels, including requirements relating to climate change, air and water quality, solid and hazardous waste, and impacts on species and habitats. The Exelon Board of Directors is responsible for overseeing the management of environmental matters. Exelon has a regionmanagement team to address environmental compliance and are reported under Other: natural gas,strategy, including the CEO; the Senior Vice President and Chief Strategy and Sustainability Officer; as well as other miscellaneous business activitiessenior management of the Utility Registrants. Performance of those individuals directly involved in environmental compliance and strategy is reviewed and affects compensation as part of the annual individual performance review process. The Exelon Board of Directors has delegated to the Corporate Governance Committee the authority to oversee Exelon’s compliance with health, environmental, and safety laws and regulations and its strategies and efforts to protect and improve the quality of the environment, including Exelon’s internal climate change and sustainability policies and programs, as discussed in further detail below. The respective Boards of the Utility Registrants oversee environmental, health, and safety issues related to these companies. Climate Change As detailed below, the Registrants face climate change mitigation and transition risks as well as adaptation risks. Mitigation and transition risks include changes to the energy systems as a result of new technologies, changing customer expectations and/or voluntary GHG goals, as well as local, state or federal regulatory requirements intended to reduce GHG emissions. Adaptation risk refers to risks to the Registrants' facilities or operations that may result from changes in the physical climate, such as changes to temperature, weather patterns and sea level. Climate Change Mitigation and Transition The Registrants support comprehensive federal climate legislation that addresses the urgent need to substantially reduce national GHG emissions while providing appropriate protections for consumers, businesses, and the economy. In the absence of comprehensive federal legislation, Exelon supports EPA moving forward with meaningful regulation of GHG emissions under the Clean Air Act. The Registrants currently are subject to, and may become subject to additional, federal and/or state legislation and/or regulations addressing GHG emissions. GHG emission sources associated with the Registrants include natural gas (methane) leakage on the natural gas systems, sulfur hexafluoride (SF6) leakage from electric transmission and distribution operations, refrigerant leakage from chilling and cooling equipment, and fossil fuel combustion in motor vehicles. In addition, PECO, BGE, and DPL distribute natural gas; and consumers' use of such natural gas produces GHG emissions. Since its inception, Exelon has positioned itself as a leader in climate change mitigation. In 2020, Exelon's Scope 1 and 2 GHG emissions, as revised following the separation, were just over 5.6 million metric tons carbon dioxide equivalent using the World Resources Institute Corporate Standard Market-based accounting. Of these emissions, 551,000 metric tons are considered to be operations-driven and in more direct control of our employees and processes. The remaining 5 million metric tons, approximately 90%, are the indirect emissions associated with electric distribution and transmission system uses and losses resulting from the Utility Registrant's delivery of electricity to their customers. These system uses and losses are driven primarily by customer use and generation assets on the grid that are not significantunder our ownership. In August 2021, the Utility Registrants announced a "path to overall operating revenuesclean" 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, while also supporting customers and communities to achieve their clean energy and emissions goals. 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. Over the next 10 years, Exelon anticipates investing approximately $4.8 billion towards its "path to clean" goal. Exelon believes it has line of sight into solutions available today to achieve 80% of its "path to clean" goal and that achieving full net-zero operations will require some technology advancement and continued policy support. Exelon is laying the groundwork by partnering with national labs, universities and research consortia to research, develop and pilot clean technologies. The Utility Registrants are also driving customer-driven emissions reductions in their communities through some of the nation's largest energy efficiency programs. During 2022 - 2025, estimated energy efficiency investments across the Utility Registrants total $3.4 billion. These programs enable customer savings through home energy audits, lighting discounts, appliance recycling, home improvement rebates, equipment upgrade incentives and innovative programs like smart thermostats and combined heat and power programs. The electric sector plays a key role in lowering GHG emissions across much of the economy. Electrification, where feasible for transportation, buildings, and industry coupled with simultaneous decarbonization of electric generation can be a key lever for emissions reductions. To support this transition, Exelon is advocating for public policy supportive of vehicle electrification, investing in enabling infrastructure and technology, and supporting customer education and adoption. In addition, the Utility Registrants will electrify 30% of their own vehicle fleet by 2025, increasing to 50% by 2030. Exelon also continues to explore other decarbonization opportunities, supporting pilots of emerging energy technologies and clean fuels to support both operational and customer-driven emissions reductions. International Climate Change Agreements. At the international level, the United States is a party to the United Nations Framework Convention on Climate Change (UNFCCC). The Parties to the UNFCCC adopted the Paris Agreement at the 21st session of the UNFCCC Conference of the Parties (COP 21) on December 12, 2015. Under the Agreement, which became effective on November 4, 2016, the parties committed to try to limit the global average temperature increase and to develop national GHG reduction commitments. On November 4, 2020, the United States formally withdrew from the Paris Agreement, retracting its commitment to reduce domestic GHG emissions by 26%-28% by 2025 compared with 2005 levels. However, on January 20, 2021, President Biden accepted the Paris Agreement, which resulted in the United States’ formal re-entry on February 19, 2021. The Biden administration has announced its intent to pursue ambitious GHG reductions in the United States and internationally, and the United States has now set an economy-wide target of reducing its net GHG emissions by 50-52% below 2005 levels by 2030. The 2021 UNFCCC Conference of the Parties (COP26) and resulting Glasgow Climate Pact indicated important global support for the Paris Agreement and continued progress toward decarbonization. Federal Climate Change Legislation and Regulation.It is uncertain whether federal legislation to significantly reduce GHG emissions will be enacted in the near-term. On November 15, 2021, President Biden signed the Infrastructure Investment and Jobs Act's (IIJA) into law, which does include provisions intended to address climate change. Exelon anticipates pursuing opportunities under IIJA. Regulation of GHGs from Power Plants under the Clean Air Act.TheEPA’s 2015 Clean Power Plan (CPP) established regulations addressing carbon dioxide emissions from existing fossil-fired power plants under Clean Air Act Section 111(d). The CPP’s carbon pollution limits could be met through changes to the electric generation system, including shifting generation from higher-emitting units to lower- or resultszero-emitting units, as well as the development of operations. Further,new or expanded zero-emissions generation. In July 2019, the following activities are not allocatedEPA published its final Affordable Clean Energy rule, which repealed the CPP and replaced it with less stringent emissions guidelines for existing fossil-fired power plants based on heat rate improvement measures that could be achieved within the fence line of individual plants. Exelon, together with a coalition of other electric utilities, filed a lawsuit in the U.S. Court of Appeals for the D.C. Circuit on September 6, 2019, challenging the Affordable Clean Energy rule as unlawful. This lawsuit was consolidated with separate challenges to the Affordable Clean Energy rule filed by various states, non-governmental organizations, and business coalitions. On January 19, 2021, the U.S. Court of Appeals for the D.C. Circuit held the Affordable Clean Energy Rule to be unlawful, vacated the rule, and remanded it to the EPA. On October 29, 2021, the Supreme Court granted certiorari to examine the extent of EPA's authority to regulate GHGs from power plants; a regiondecision is expected in 2022. The EPA has indicated it will promulgate new GHG limits for existing power plants. Increased regulation of GHG emissions from power plants could increase the cost of electricity delivered or sold by The Registrants. As of February 1, 2022, the Registrants no longer directly own electric generation plants.
State Climate Change Legislation and are reportedRegulation. A number of states in Other: accelerated nuclear fuel amortization associated with nuclear decommissioning;which the Registrants operate have state and regional programs to reduce GHG emissions and renewable and other miscellaneous revenues. Generation evaluatesportfolio standards, which impact the operating performance of electric business activities using the measure of RNF. 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 owned generation and fuel costs associated with tolling agreements.
For the years ended December 31, 2019 compared to 2018, RNF by region were as follows:
| | | | | | | | | | | | | | | | | | | | | 2019 vs. 2018 | | 2019 | | 2018 | | Variance | | % Change | Mid-Atlantic(a) | $ | 2,655 |
| | $ | 3,073 |
| | $ | (418 | ) | | (13.6 | )% | Midwest(b) | 2,962 |
| | 3,135 |
| | (173 | ) | | (5.5 | )% | New York | 1,094 |
| | 1,122 |
| | (28 | ) | | (2.5 | )% | ERCOT | 308 |
| | 258 |
| | 50 |
| | 19.4 | % | Other Power Regions | 620 |
| | 729 |
| | (109 | ) | | (15.0 | )% | Total electric revenues net of purchased power and fuel expense | 7,639 |
|
| 8,317 |
|
| (678 | ) | | (8.2 | )% | Mark-to-market losses | (215 | ) | | (319 | ) | | 104 |
| | (32.6 | )% | Other | 644 |
| | 746 |
| | (102 | ) | | (13.7 | )% | Total revenue net of purchased power and fuel expense | $ | 8,068 |
|
| $ | 8,744 |
|
| $ | (676 | ) | | (7.7 | )% |
_________
| | (a) | Includes results of transactions with PECO, BGE, Pepco, DPL and ACE. |
| | (b) | Includes results of transactions with ComEd. |
Generation’s supply sources by region are summarized below:
| | | | | | | | | | | | | | | | | | 2019 vs. 2018 | Supply Source (GWhs) | 2019 | | 2018 | | Variance | | % Change | Nuclear Generation(a) | | | | | | | | Mid-Atlantic | 58,347 |
| | 64,099 |
| | (5,752 | ) | | (9.0 | )% | Midwest | 94,890 |
| | 94,283 |
| | 607 |
| | 0.6 | % | New York | 28,088 |
| | 26,640 |
| | 1,448 |
| | 5.4 | % | Total Nuclear Generation | 181,325 |
| | 185,022 |
| | (3,697 | ) | | (2.0 | )% | Fossil and Renewables | | | | | | |
|
| Mid-Atlantic | 2,884 |
| | 3,670 |
| | (786 | ) | | (21.4 | )% | Midwest | 1,374 |
| | 1,373 |
| | 1 |
| | 0.1 | % | New York | 5 |
| | 3 |
| | 2 |
| | 66.7 | % | ERCOT | 13,572 |
| | 11,180 |
| | 2,392 |
| | 21.4 | % | Other Power Regions | 11,476 |
| | 13,256 |
| | (1,780 | ) | | (13.4 | )% | Total Fossil and Renewables | 29,311 |
|
| 29,482 |
| | (171 | ) | | (0.6 | )% | Purchased Power | | | | | | |
|
| Mid-Atlantic | 14,790 |
| | 6,506 |
| | 8,284 |
| | 127.3 | % | Midwest | 1,424 |
| | 996 |
| | 428 |
| | 43.0 | % | ERCOT | 4,821 |
| | 6,550 |
| | (1,729 | ) | | (26.4 | )% | Other Power Regions | 48,673 |
| | 44,998 |
| | 3,675 |
| | 8.2 | % | Total Purchased Power | 69,708 |
| | 59,050 |
|
| 10,658 |
| | 18.0 | % | Total Supply/Sales by Region | | | | | | |
|
| Mid-Atlantic(b) | 76,021 |
| | 74,275 |
| | 1,746 |
| | 2.4 | % | Midwest(b) | 97,688 |
| | 96,652 |
| | 1,036 |
| | 1.1 | % | New York | 28,093 |
| | 26,643 |
| | 1,450 |
| | 5.4 | % | ERCOT | 18,393 |
| | 17,730 |
| | 663 |
| | 3.7 | % | Other Power Regions | 60,149 |
| | 58,254 |
| | 1,895 |
| | 3.3 | % | Total Supply/Sales by Region | 280,344 |
|
| 273,554 |
|
| 6,790 |
| | 2.5 | % |
__________
| | (a) | Includes the proportionate share of output where Generation has an undivided ownership interest in jointly-owned generating plants and includes the total output of plants that are fully consolidated (e.g. 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. |
For the years ended December 31, 2019 compared to 2018 changes in RNF by region were as follows:
| | | | | | | 2019 vs. 2018 | | (Decrease)/Increase | Description | Mid-Atlantic | $ | (418 | ) | • decreased revenue due to the permanent cease of generation operations at Oyster Creek in the third quarter of 2018 and Three Mile Island in the third quarter of 2019 • lower realized energy prices • decreased capacity prices, partially offset by • increased ZEC revenues due to the approval of the NJ ZEC program in the second quarter of 2019 | Midwest | (173 | ) | • the absence of the revenue recognized in the first quarter of 2018 related to ZECs generated in Illinois from June through December 2017 • decreased capacity prices | New York | (28 | ) | • lower realized energy prices • decreased capacity prices, partially offset by • increased ZEC revenues due to higher ZEC prices and increased nuclear output • decreased nuclear outage days | ERCOT | 50 |
| • higher realized energy prices | Other Power Regions | (109 | ) | • decreased capacity prices • lower realized energy prices | Mark-to-market(a) | 104 |
| • losses on economic hedging activities of $215 million in 2019 compared to losses of $319 million in 2018 | Other | (102 | ) | • the absence of the gain on the settlement of a long-term gas supply agreement • congestion activity, partially offset by • decrease in accelerated nuclear fuel amortization associated with announced early plant retirements
| Total | $ | (676 | ) | |
_________(a)sector. See Note 15 — Derivative Financial Instrumentsdiscussion below for additional information on mark-to-market losses.renewable and other portfolio standards.
Nuclear Fleet Capacity Factor. The following table presents nuclear fleet operating data forEleven northeast and mid-Atlantic states (Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Rhode Island, Vermont, and Virginia) currently participate in the Generation-operated plants, which reflects ownership percentage of stations operated by Exelon, excluding Salem,RGGI, which is operated by PSEG. The nuclear fleet capacity factor presented in the tableprocess of strengthening its requirements. The program requires most fossil fuel-fired power plants in the region to hold allowances, purchased at auction, for each ton of CO2 emissions. Non-emitting resources do not have to purchase or hold these allowances. In October 2019, the Governor of Pennsylvania issued an Executive Order directing the PA DEP to begin a rulemaking process to allow Pennsylvania to join the RGGI, with the goal of reducing carbon emissions from the electricity sector. On November 7, 2020, the PA DEP proposed its rule, which is definedanticipated to support Pennsylvania's participation in RGGI beginning sometime in 2022.
Broader state programs impact other sectors as well, such as the ratioDistrict of Columbia's Clean Energy DC Omnibus Act and cross-sector GHG reduction plans, which resulted in recent requirements for Pepco to develop 5-year and 30-year decarbonization programs and strategies. Maryland has a statewide GHG reduction mandate to reduce GHG emissions by 40% no later than 2030, which it expects to meet and surpass. New Jersey accelerated its goals through Executive Order 274, which establishes an interim goal of 50% reductions below 2006 levels by 2030 and affirms its goal of achieving 80% reductions by 2050 and includes programs to drive greater amounts of electrified transportation. Finally, the actual output of a plant over a period of timeClean Energy Law establishes decarbonization requirements for Illinois as well as programs to its output ifsupport 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. | | | | | | | | 2019 | | 2018 | Nuclear fleet capacity factor | 95.7 | % | | 94.6 | % | Refueling outage days | 209 |
| | 274 |
| Non-refueling outage days | 51 |
| | 38 |
|
The changes in Operating and maintenance expense, consisted of the following:
| | | | | | (Decrease) Increase 2019 vs. 2018 | Labor, other benefits, contracting, materials(a) | $ | (174 | ) | Nuclear refueling outage costs, including the co-owned Salem plants | (87 | ) | Corporate allocations | (82 | ) | Insurance(b) | (47 | ) | Merger and integration costs | (4 | ) | Plant retirements and divestitures(c) | (175 | ) | Change in environmental liabilities | 7 |
| ARO update(d) | (70 | ) | Asset Impairments(e) | (32 | ) | Pension and non-pension postretirement benefits expense | (62 | ) | Allowance for uncollectible accounts | (14 | ) | Accretion expense | (77 | ) | Other(f) | 71 |
| Decrease in operating and maintenance expense | $ | (746 | ) |
__________
| | (a) | Primarily reflects decreased costs related to the permanent cease of generation operations at Oyster Creek, lower labor costs resulting from previous cost management programs, and lower pension and OPEB costs. |
| | (b) | Primarily reflects a supplemental NEIL insurance distribution received in the fourth quarter of 2019. |
| | (c) | Primarily due to the benefit recorded in the first quarter of 2019 for the remeasurement of the TMI ARO and the absence of a charge associated with the remeasurement of the Oyster Creek ARO in the third quarter of 2018. |
| | (d) | Primarily reflects a benefit related to Generation's annual nuclear ARO update for non-regulatory units. |
| | (e) | Primarily due to the impairment of certain wind projects recorded in the second quarter of 2018. |
| | (f) | Primarily due to the increased revenue as a result of a research and development tax refund. |
Depreciation and amortization expense for the year ended December 31, 2019 compared to the year ended December 31, 2018 decreased primarily due to the permanent cessation of generation operations at Oyster Creek in the third quarter of 2018 and TMI in the fourth quarter of 2019.
Gain (loss) on sales of assets and businesses for the year ended December 31, 2019 compared to the year ended December 31, 2018 decreased primarily due to Generation's sale of Oyster Creek.
Other, net for the year ended December 31, 2019 compared to the same period in 2018 increased for the twelve months ended December 31, 2019 compared to the same period in 2018 due to activity associated with NDT funds as described in the table below.
| | | | | | | | | | 2019 | | 2018 | Net unrealized gains (losses) on NDT funds(a) | $ | 411 |
| | $ | (483 | ) | Net realized gains on sale of NDT funds(a) | 253 |
| | 180 |
| Interest and dividend income on NDT funds(a) | 110 |
| | 122 |
| Contractual elimination of income tax expense(b) | 216 |
| | (38 | ) | Other | 33 |
| | 41 |
| Total other, net | $ | 1,023 |
| | $ | (178 | ) |
_________
| | (a) | Unrealized gains (losses), 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. |
Effective income tax rates were 26.9%and(29.5)% for the years ended December 31, 2019 and 2018, respectively. The change in 2019 is primarily related to researchretention and development claims, renewable tax credits and one-time adjustments.of emissions-free sources of electricity. See Note 13 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.
Equity in losses of unconsolidated affiliates for the twelve months ended December 31, 2019 compared to the same period in 2018 decreased primarily due to the impairment of equity method investments in certain distributed energy companies.
Net income attributable to noncontrolling interests for the twelve months ended December 31, 2019 compared to the same period in 2018 decreased primarily due to the offsetting noncontrolling interest impact of the impairment of equity method investments in certain distributed energy companies.
Results of Operations—ComEd
| | | | | | | | | | | | | | | | | | | | | | 2019 | | 2018 | | Favorable (unfavorable) 2019 vs. 2018 variance | | 2017 | | Favorable (unfavorable) 2018 vs. 2017 variance | Operating revenues | $ | 5,747 |
| | $ | 5,882 |
| | $ | (135 | ) | | $ | 5,536 |
| | $ | 346 |
| Purchased power expense | 1,941 |
| | 2,155 |
| | 214 |
| | 1,641 |
| | (514 | ) | Revenues net of purchased power expense | 3,806 |
| | 3,727 |
| | 79 |
| | 3,895 |
| | (168 | ) | Other operating expenses | | | | | | | | | | Operating and maintenance | 1,305 |
| | 1,335 |
| | 30 |
| | 1,427 |
| | 92 |
| Depreciation and amortization | 1,033 |
| | 940 |
| | (93 | ) | | 850 |
| | (90 | ) | Taxes other than income taxes | 301 |
| | 311 |
| | 10 |
| | 296 |
| | (15 | ) | Total other operating expenses | 2,639 |
| | 2,586 |
| | (53 | ) | | 2,573 |
| | (13 | ) | Gain on sales of assets | 4 |
| | 5 |
| | (1 | ) | | 1 |
| | 4 |
| Operating income | 1,171 |
| | 1,146 |
| | 25 |
| | 1,323 |
| | (177 | ) | Other income and (deductions) | | | | | | | | | | Interest expense, net | (359 | ) | | (347 | ) | | (12 | ) | | (361 | ) | | 14 |
| Other, net | 39 |
| | 33 |
| | 6 |
| | 22 |
| | 11 |
| Total other income and (deductions) | (320 | ) | | (314 | ) | | (6 | ) | | (339 | ) | | 25 |
| Income before income taxes | 851 |
| | 832 |
| | 19 |
| | 984 |
| | (152 | ) | Income taxes | 163 |
| | 168 |
| | 5 |
| | 417 |
| | 249 |
| Net income | $ | 688 |
| | $ | 664 |
| | $ | 24 |
| | $ | 567 |
| | $ | 97 |
|
Year Ended December 31, 2019 Compared to Year Ended December 31, 2018.Net income increased by $24 million primarily due to higher electric distribution, transmission and energy efficiency formula rate earnings (reflecting the impacts of higher rate base, partially offset by lower allowed electric distribution ROE due to a decrease in treasury rates).
Revenues Net of Purchased Power Expense. There are certain drivers of Operating revenues that are fully offset by their impact on Purchased power expense, such as commodity, REC and ZEC procurement costs and participation in customer choice programs. ComEd recovers electricity, REC and ZEC procurement costs from customers without mark-up. Therefore, fluctuations in these costs have no impact on RNF.
Customers have the choice to purchase electricity from a competitive electric generation supplier. Customer choice programs do not impact the volume of deliveries, but do impact Operating revenues related to supplied electricity.
The changes in RNF consisted of the following:
| | | | | | Increase (Decrease) 2019 vs. 2018 | Electric distribution revenue | $ | 47 |
| Transmission revenue | 32 |
| Energy efficiency revenue | 47 |
| Uncollectible accounts recovery, net | (7 | ) | Other | (40 | ) | Total increase | $ | 79 |
|
Revenue Decoupling. The demand for electricity is affected by weather and customer usage. Operating revenues are not impacted by abnormal weather, usage per customer or number of customers as a result of a change to the electric distribution formula rate 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. During the year ended December 31, 2019, as compared to the same period in 2018, electric distribution revenue increased primarily due to the impact of higher rate base and increased depreciation expenses, offset by lower allowed ROE due to a decrease in treasury rates. See Operating and Maintenance Expense below and Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
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 basedinformation on the prior calendar year. Generally, increases/decreases inClean Energy Law.
The Registrants cannot predict the highest daily peak load will result in higher/lower transmission revenue. During the year ended December 31, 2019, as compared to the same period in 2018, transmission revenue increased primarily due to thenature of future regulations or how such regulations might impact of increased peak load, higher rate base,future financial statements. Renewable and higher fully recoverable costs. See Operating and Maintenance Expense below and Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. Clean 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. Under FEJA, energy efficiency revenue varies from year to year based upon fluctuations in the underlying costs, investments being recovered, and allowed ROE. Energy efficiency revenue increased for the year ended December 31, 2019, as compared to the same period in 2018, primarily due to the impact of higher rate base and increased regulatory asset amortization. See Depreciation and amortization expense discussions below and Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. Uncollectible Accounts Recovery, Net represents recoveries under the uncollectible accounts tariff. See Operating and maintenance expense discussion below for additional information on this tariff.
Other revenue includes rental revenue, revenue related to late payment charges, mutual assistance revenues and recoveries of environmental costs associated with MGP sites. The decrease in Other revenue for the year ended December 31, 2019, as compared to the same period in 2018, primarily reflects absence of mutual assistance revenues associated with hurricane and winter storm restoration efforts that occurred in Q1 2018. An equal and offsetting amount was included in Operating and maintenance expense.
See Note 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ComEd's revenue disaggregation.
The changes in Operating and maintenance expense consisted of the following:
| | | | | | (Decrease) Increase 2019 vs. 2018 | Baseline | | Pension and non-pension postretirement benefits expense(a) | $ | (36 | ) | Labor, other benefits, contracting and materials(b) | (27 | ) | Uncollectible accounts expense(c) | (7 | ) | Storm costs | 31 |
| Other | 9 |
| Total decrease | $ | (30 | ) |
__________
| | (a) | Primarily reflects an increase in discount rates and the favorable impacts of the merger of two of Exelon’s pension plans |
effective in January 2019, partially offset by lower than expected asset returns in 2018.
| | (b) | Primarily reflects absence of mutual assistance expenses and decreased contracting costs. An equal and offsetting increase has been recognized in Operating revenues for the period presented. |
| | (c) | ComEd is allowed to recover from or refund to customers the difference between its annual uncollectible accounts expense and the amounts collected in rates annually through a rider mechanism. ComEd recorded a net decrease in uncollectible accounts for the year ended December 31, 2019, as compared to the same period in 2018, primarily due to the timing of regulatory cost recovery. An equal and offsetting amount has been recognized in Operating revenues for the periods presented. |
The changes in Depreciation and amortization expense consisted of the following:
| | | | | | Increase 2019 vs. 2018 | Depreciation expense(a) | $ | 58 |
| Regulatory asset amortization(b) | 35 |
| Total increase | $ | 93 |
|
__________
| | (a) | Reflects ongoing capital expenditures and higher depreciation rates effective January 2019. |
| | (b) | Includes amortization of ComEd's energy efficiency formula rate regulatory asset. |
Effective income tax rates for the years ended December 31, 2019 and 2018, were 19.2% and 20.2% , respectively. See Note 13 — 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
| | | | | | | | | | | | | | | | | | | | | | 2019 | | 2018 | | Favorable (unfavorable) 2019 vs. 2018 variance | | 2017 | | Favorable (unfavorable) 2018 vs. 2017 variance | Operating revenues | $ | 3,100 |
| | $ | 3,038 |
| | $ | 62 |
| | $ | 2,870 |
| | $ | 168 |
| Purchased power and fuel expense | 1,029 |
| | 1,090 |
| | 61 |
| | 969 |
| | (121 | ) | Revenues net of purchased power and fuel expense | 2,071 |
| | 1,948 |
| | 123 |
| | 1,901 |
| | 47 |
| Other operating expenses | | | | | | | | | | Operating and maintenance | 861 |
| | 898 |
| | 37 |
| | 806 |
| | (92 | ) | Depreciation and amortization | 333 |
| | 301 |
| | (32 | ) | | 286 |
| | (15 | ) | Taxes other than income taxes | 165 |
| | 163 |
| | (2 | ) | | 154 |
| | (9 | ) | Total other operating expenses | 1,359 |
| | 1,362 |
| | 3 |
| | 1,246 |
| | (116 | ) | Gain on sales of assets | 1 |
| | 1 |
| | — |
| | — |
| | 1 |
| Operating income | 713 |
| | 587 |
| | 126 |
| | 655 |
| | (68 | ) | Other income and (deductions) | | | | | | | | | | Interest expense, net | (136 | ) | | (129 | ) | | (7 | ) | | (126 | ) | | (3 | ) | Other, net | 16 |
| | 8 |
| | 8 |
| | 9 |
| | (1 | ) | Total other income and (deductions) | (120 | ) | | (121 | ) | | 1 |
| | (117 | ) | | (4 | ) | Income before income taxes | 593 |
| | 466 |
| | 127 |
| | 538 |
| | (72 | ) | Income taxes | 65 |
| | 6 |
| | (59 | ) | | 104 |
| | 98 |
| Net income | $ | 528 |
| | $ | 460 |
| | $ | 68 |
| | $ | 434 |
| | $ | 26 |
|
Year Ended December 31, 2019 Compared to Year Ended December 31, 2018.Net income increased by $68 million primarily due to higher electric distribution rates that became effective January 2019, higher natural gas distribution rates and lower storm costs, partially offset by unfavorable weather conditions and volume.
Revenues Net of Purchased Power and Fuel Expense. There are certain drivers of Operating revenues that are fully offset by their impact on Purchased power and fuel expenses such as commodity and REC procurement costs and participation in customer choice programs. PECO's recovers electricity, natural gas and REC procurement costs from customers without mark-up. Therefore, fluctuations in these costs have no impact on RNF.
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 or RNF, but impact Operating revenues related to supplied electricity and natural gas.
The changes in RNF consisted of the following:
| | | | | | | | | | | | | | 2019 vs. 2018 | | (Decrease) Increase | | Electric | | Gas | | Total | Weather | $ | (11 | ) | | $ | (8 | ) | | $ | (19 | ) | Volume | (22 | ) | | 6 |
| | (16 | ) | Pricing | 112 |
| | 10 |
| | 122 |
| Regulatory required programs | 42 |
| | 9 |
| | 51 |
| Transmission Revenue | (13 | ) | | — |
| | (13 | ) | Other | (2 | ) | | — |
| | (2 | ) | Total increase | $ | 106 |
| | $ | 17 |
| | $ | 123 |
|
Weather.Standards. The demandstates where Exelon operates have adopted some form of renewable or clean energy procurement requirement. These standards impose varying levels of mandates for procurement of renewable or clean electricity and natural gas is affected(the definition of which varies by weather conditions. With respectstate) and/or energy efficiency. These are generally expressed as a percentage of annual electric load, often increasing by year. The Utility Registrants comply with these various requirements through purchasing qualifying renewables, implementing efficiency programs, acquiring sufficient credits (e.g., RECs), paying an alternative compliance payment, and/or a combination of these compliance alternatives. The Utility Registrants are permitted to recover from retail customers the electric business, very warm weather in summer months and,costs of complying with respect totheir state RPS requirements, including 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 deliveriesprocurement of electricity and natural gas. Conversely, mild weather reduces demand. For the year ended December 31, 2019 compared to the same period in 2018 RNF was decreased by the impact of unfavorable weather conditions in PECO's service territory.
Heating and cooling degree days are quantitative indices that reflect the demand forRECs or other alternative 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 years ended December 31, 2019 and December 31, 2018 compared to the same periods in 2018 and 2017, respectively, and normal weather consisted of the following:
| | | | | | | | | | | | | | | | | For the Years Ended December 31, | | | | % Change | Heating and Cooling Degree-Days | 2019 | | 2018 | | Normal | | 2019 vs. 2018 | | 2019 vs. Normal | Heating Degree-Days | 4,307 |
| | 4,539 |
| | 4,458 |
| | (5.1 | )% | | (3.4 | )% | Cooling Degree-Days | 1,610 |
| | 1,584 |
| | 1,415 |
| | 1.6 | % | | 13.8 | % |
Volume. Electric volume, exclusive of the effects of weather, for the year ended December 31, 2019 compared to the same period in 2018, decreased due to lower customer usages for residential, commercial and industrial electric classes, partially offset by the impact of customer growth. Natural gas volume for the year ended December 31, 2019 compared to the same period in 2018, increased due to customer and economic growth.
| | | | | | | | | | | | | Electric Retail Deliveries to Customers (in GWhs) | 2019 | | 2018 | | % Change 2019 vs. 2018 | | Weather - Normal % Change(b) | Retail Deliveries (a) | | | | | | | | Residential | 13,650 |
| | 14,005 |
| | (2.5 | )% | | (1.4 | )% | Small commercial & industrial | 7,983 |
| | 8,177 |
| | (2.4 | )% | | (1.2 | )% | Large commercial & industrial | 14,958 |
| | 15,516 |
| | (3.6 | )% | | (3.4 | )% | Public authorities & electric railroads | 725 |
| | 761 |
| | (4.7 | )% | | (5.0 | )% | Total electric retail deliveries | 37,316 |
| | 38,459 |
| | (3.0 | )% | | (2.3 | )% |
__________
| | (a) | Reflects delivery volumes and revenue 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. |
| | | | | | | | As of December 31, | Number of Electric Customers | 2019 | | 2018 | Residential | 1,494,462 |
| | 1,480,925 |
| Small commercial & industrial | 154,000 |
| | 152,797 |
| Large commercial & industrial | 3,104 |
| | 3,118 |
| Public authorities & electric railroads | 10,039 |
| | 9,565 |
| Total | 1,661,605 |
| | 1,646,405 |
|
| | | | | | | | | | | | | Natural Gas Deliveries to customers (in mmcf) | 2019 | | 2018 | | % Change 2019 vs. 2018 | | Weather - Normal % Change(b) | Retail Deliveries (a) | | | | | | | | Residential | 40,196 |
| | 43,450 |
| | (7.5 | )% | | 0.9 | % | Small commercial & industrial | 23,828 |
| | 21,997 |
| | 8.3 | % | | 1.4 | % | Large commercial & industrial | 50 |
| | 65 |
| | (23.1 | )% | | 7.4 | % | Transportation | 25,822 |
| | 26,595 |
| | (2.9 | )% | | (1.3 | )% | Total natural gas deliveries | 89,896 |
| | 92,107 |
| | (2.4 | )% | | 0.4 | % |
__________
| | (a) | Reflects delivery volumes and revenue 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. |
| | | | | | | | As of December 31, | Number of Gas Customers | 2019 | | 2018 | Residential | 487,337 |
| | 482,255 |
| Small commercial & industrial | 44,374 |
| | 44,170 |
| Large commercial & industrial | 2 |
| | 1 |
| Transportation | 730 |
| | 754 |
| Total | 532,443 |
| | 527,180 |
|
Pricing for the year ended December 31, 2019 compared to the same period in 2018 increased primarily due to an increase in electric distribution rates charged to customers. The increase in electric distribution rates was effective January 1, 2019 in accordance with the 2018 PAPUC approved electric distribution rate case settlement. Additionally, the increase represents revenue from higher natural gas distribution rates.resources. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Regulatory Required Programs represent revenues collected under approved ridersClimate Change Adaptation
The Registrants' facilities and operations are subject to recover costs incurred for regulatory programsthe global impacts of climate change. Long-term shifts in climactic patterns, such as energy efficiency, PGCsustained higher temperatures 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 Operating and maintenance expense, Depreciation and amortization expense and Income taxes. 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 revenuesea level rise, may present challenges for the year ended December 31, 2019compared to the same period in 2018 decreased primarily due to lower operatingRegistrants and maintenance expenses and the terms of the settlement agreement approved by FERC in December 2019. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Other revenue includes rental revenue, revenue related to late payment charges and mutual assistance revenues.
See Note 5—Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of PECO's revenue disaggregation.
The changes in Operating and maintenance expense consisted of the following:
| | | | | | (Decrease) Increase 2019 vs. 2018 | Baseline | | Storm-related costs (a) | $ | (30 | ) | Pension and non-pension postretirement benefits expense | (5 | ) | Uncollectible accounts expense | (2 | ) | BSC costs | 2 |
| Labor, other benefits, contracting and materials | 1 |
| Other | (7 | ) | | (41 | ) | Regulatory required programs | | Energy efficiency | 4 |
| Decrease in operating and maintenance expense | $ | (37 | ) |
__________
(a) Reflects decreased storm costs due to the March 2018 winter storms.
The changes in Depreciation and amortization expense consisted of the following:
| | | | | | Increase 2019 vs. 2018 | Depreciation expense (a) | $ | 28 |
| Regulatory asset amortization | 4 |
| Increase in depreciation and amortization expense | $ | 32 |
|
__________(a) Depreciation expense increased due to ongoing capital expenditures.
Effective income tax rates were 11.0% and 1.3% for the years ended December 31, 2019 and 2018, respectively. See Note 13 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information of the change in effective income tax rates.
Results of Operations—BGE
| | | | | | | | | | | | | | | | | | | | | | 2019 | | 2018 | | Favorable (unfavorable) 2019 vs. 2018 variance | | 2017 | | Favorable (unfavorable) 2018 vs. 2017 variance | Operating revenues | $ | 3,106 |
| | $ | 3,169 |
| | $ | (63 | ) | | $ | 3,176 |
| | $ | (7 | ) | Purchased power and fuel expense | 1,052 |
| | 1,182 |
| | 130 |
| | 1,133 |
| | (49 | ) | Revenues net of purchased power and fuel expense | 2,054 |
| | 1,987 |
| | 67 |
| | 2,043 |
| | (56 | ) | Other operating expenses | | | | | | | | | | Operating and maintenance | 760 |
| | 777 |
| | 17 |
| | 716 |
| | (61 | ) | Depreciation and amortization | 502 |
| | 483 |
| | (19 | ) | | 473 |
| | (10 | ) | Taxes other than income taxes | 260 |
| | 254 |
| | (6 | ) | | 240 |
| | (14 | ) | Total other operating expenses | 1,522 |
| | 1,514 |
| | (8 | ) | | 1,429 |
| | (85 | ) | Gain on sales of assets | — |
| | 1 |
| | (1 | ) | | — |
| | 1 |
| Operating income | 532 |
| | 474 |
| | 58 |
| | 614 |
| | (140 | ) | Other income and (deductions) | | | | | | | | | | Interest expense, net | (121 | ) | | (106 | ) | | (15 | ) | | (105 | ) | | (1 | ) | Other, net | 28 |
| | 19 |
| | 9 |
| | 16 |
| | 3 |
| Total other income and (deductions) | (93 | ) | | (87 | ) | | (6 | ) | | (89 | ) | | 2 |
| Income before income taxes | 439 |
| | 387 |
| | 52 |
| | 525 |
| | (138 | ) | Income taxes | 79 |
| | 74 |
| | (5 | ) | | 218 |
| | 144 |
| Net income | 360 |
| | 313 |
| | 47 |
| | 307 |
| | 6 |
| Net income attributable to common shareholder | $ | 360 |
| | $ | 313 |
| | $ | 47 |
| | $ | 307 |
| | $ | 6 |
|
Year Ended December 31, 2019 Compared to Year Ended December 31, 2018.Net income attributable to common shareholder increased by $47 million primarily due to higher natural gas distribution rates that became effective January 2019 and December 2019, higher electric distribution rates that became effective December 2019, and lower storm costs, partially offset by an increase in various expenses, including interest.
Revenues Net of Purchased Power and Fuel Expense. There are certain drivers to Operating revenues that are fully offset by their impact on Purchased power and fuel expense, such as commodity procurement costs and participation in customer choice programs. BGE recovers electricity, natural gas and other procurement costs from customers without mark-up. Therefore, fluctuations in these costs have no impact on RNF.
Customers have the choice to purchase electricity and natural gas from electric generation and natural gas competitive suppliers. Customer choice programs do not impact the volume of deliveries or RNF but impact Operating revenues related to supplied electricity and natural gas.
The changes in RNF consisted of the following:
| | | | | | | | | | | | | | 2019 vs. 2018 | | Increase (Decrease) | | Electric | | Gas | | Total | Distribution revenue | $ | 11 |
| | $ | 68 |
| | $ | 79 |
| Regulatory required programs | (6 | ) | | (4 | ) | | (10 | ) | Transmission revenue | 10 |
| | — |
| | 10 |
| Other, net | (7 | ) | | (5 | ) | | (12 | ) | Total increase | $ | 8 |
| | $ | 59 |
|
| $ | 67 |
|
Revenue Decoupling. The demand for electricity and natural gas isservice territories. Exelon believes its operations could be significantly affected by weather and customer usage. However, Operating revenuesthe physical risks of climate change. See ITEM 1A. RISK FACTORS, The Registrants 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 December 31, | Number of Electric Customers | 2019 | | 2018 | Residential | 1,177,333 |
| | 1,168,372 |
| Small commercial & industrial | 114,504 |
| | 113,915 |
| Large commercial & industrial | 12,322 |
| | 12,253 |
| Public authorities & electric railroads | 268 |
| | 262 |
| Total | 1,304,427 |
| | 1,294,802 |
|
| | | | | | | | As of December 31, | Number of Gas Customers | 2019 | | 2018 | Residential | 639,426 |
| | 633,757 |
| Small commercial & industrial | 38,345 |
| | 38,332 |
| Large commercial & industrial | 6,037 |
| | 5,954 |
| Total | 683,808 |
| | 678,043 |
|
Distribution Revenues increased during the year ended December 31, 2019, comparedsubject to the same period in 2018, primarily due to the impact of higher natural gas distribution rates that became effective in both January 2019 and December 2019 and higher electric distribution rates that became effective in December 2019. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
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 Operating and maintenance expense, Depreciation and amortization expense and Taxes other than income taxes.
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 during the year ended December 31, 2019 compared to the same period in 2018, primarily due to increases in capital investment and operating and maintenance expense recoveries. See Operating and maintenance expense below and Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Other revenue includes revenue related to late payment charges, mutual assistance revenues, off-system sales and service application fees.
See Note 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of BGE's revenue disaggregation.
The changes in Operating and maintenance expense consisted of the following:
| | | | | | (Decrease) Increase 2019 vs. 2018 | Baseline | | Storm-related costs(a) | $ | (24 | ) | Uncollectible accounts expense | (2 | ) | BSC costs | (1 | ) | Labor, other benefits, contracting and materials | 8 |
| Pension and non-pension postretirement benefits expense | 1 |
| Other | 2 |
| | (16 | ) | | | Regulatory Required Programs
| (1 | ) | Total (decrease) increase | $ | (17 | ) |
__________
| | (a) | Reflects decreased storm restoration costs due to the March 2018 winter storms. |
The changes in Depreciation and amortization expense consisted of the following:
| | | | | | Increase (Decrease) 2019 vs. 2018 | Depreciation expense(a) | $ | 24 |
| Regulatory asset amortization | 4 |
| Regulatory required programs | (9 | ) | Increase in depreciation and amortization expense | $ | 19 |
|
__________
| | (a) | Depreciation expense increased due to ongoing capital expenditures. |
Interest expense, netincreased during the year ended December 31, 2019 compared to the same period in 2018, primarily due to the issuances of debt in September 2018 and September 2019.
Other, net increased during the year ended December 31, 2019 compared to the same period in 2018, primarily due to higher AFUDC equity.
Effective income tax rates were 18% and 19.1% for the years ended December 31, 2019 and 2018, respectively. See Note 13 — 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. See the results of operations for Pepco, DPL, and ACErisks associated with climate change, for additional information.
| | | | | | | | | | | | | | | | | | | | | | | | 2019 | | 2018(a) | | Favorable (unfavorable) 2019 vs. 2018 variance | | 2017(a) | | Favorable (unfavorable) 2018 vs. 2017 variance | | | PHI | $ | 477 |
| | $ | 393 |
| | $ | 84 |
| | $ | 355 |
| | $ | 38 |
| | Pepco | 243 |
| | 205 |
| | 38 |
| | 198 |
| | 7 |
| | DPL | 147 |
| | 120 |
| | 27 |
| | 121 |
| | (1 | ) | | ACE | 99 |
| | 75 |
| | 24 |
| | 77 |
| | (2 | ) | | Other(b) | (12 | ) | | (7 | ) | | (5 | ) | | (41 | ) | | 34 |
|
_________ | | (a) | PHI's and Pepco's amounts have been revised to reflect the correction of an error related to Pepco's decoupling mechanism. See Note 1 - Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional information. |
| | (b) | Primarily includes eliminating and consolidating adjustments, PHI's corporate operations, shared service entities and other financing activities. |
Year Ended December 31, 2019 ComparedThe Registrants' assets undergo seasonal readiness efforts to Year Ended December 31, 2018. Net income increased by $84 million primarily due to higher electric and natural gas distribution rates (not reflectingensure they are ready for the impact of TCJA), higher transmission revenues due to an increase in transmission rates and the highest daily peak load, lower contracting costs, the absenceweather projections of the charge associated with a remeasurement of the Buzzard Point ARO, lower uncollectible accounts expense,summer and lower write-offs of construction work in progress, partially offset by an increase in environmental liabilitieswinter months. The Registrants consider and various expenses.
Results of Operations—Pepco
| | | | | | | | | | | | | | | | | | | | | | 2019 | | 2018(a) | | Favorable (unfavorable) 2019 vs. 2018 variance | | 2017(a) | | Favorable (unfavorable) 2018 vs. 2017 variance | Operating revenues | $ | 2,260 |
| | $ | 2,232 |
| | $ | 28 |
| | $ | 2,151 |
| | $ | 81 |
| Purchased power expense | 665 |
| | 654 |
| | (11 | ) | | 614 |
| | (40 | ) | Revenues net of purchased power expense | 1,595 |
| | 1,578 |
| | 17 |
| | 1,537 |
| | 41 |
| Other operating expenses | | | | | | | | | | Operating and maintenance | 482 |
| | 501 |
| | 19 |
| | 454 |
| | (47 | ) | Depreciation and amortization | 374 |
| | 385 |
| | 11 |
| | 321 |
| | (64 | ) | Taxes other than income taxes | 378 |
| | 379 |
| | 1 |
| | 371 |
| | (8 | ) | Total other operating expenses | 1,234 |
| | 1,265 |
| | 31 |
| | 1,146 |
| | (119 | ) | Gain on sales of assets | — |
| | — |
| | — |
| | 1 |
| | (1 | ) | Operating income | 361 |
| | 313 |
| | 48 |
| | 392 |
| | (79 | ) | Other income and (deductions) | | | | | | | | | | Interest expense, net | (133 | ) | | (128 | ) | | (5 | ) | | (121 | ) | | (7 | ) | Other, net | 31 |
| | 31 |
| | — |
| | 32 |
| | (1 | ) | Total other income and (deductions) | (102 | ) | | (97 | ) | | (5 | ) | | (89 | ) | | (8 | ) | Income before income taxes | 259 |
| | 216 |
| | 43 |
| | 303 |
| | (87 | ) | Income taxes | 16 |
| | 11 |
| | (5 | ) | | 105 |
| | 94 |
| Net income | $ | 243 |
| | $ | 205 |
| | $ | 38 |
| | $ | 198 |
| | $ | 7 |
|
__________
| | (a) | Amounts have been revised to reflect the correction of an error related to Pepco’s decoupling mechanism. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional information. |
Year Ended December 31, 2019 Comparedreview national climate assessments to Year Ended December 31, 2018.Net income increased by $38 million primarily due to higher electric distribution rates in Maryland that became effective August 2019 and June 2018 (not reflecting the impact of TCJA), higher electric distribution rates in the District of Columbia that became effective August 2018 (not reflecting the impact of TCJA), higher transmission revenues due to an increase in transmission rates and the highest daily peak load, the absence of the charge associated with a remeasurement of the Buzzard Point ARO, and lower contracting costs, partially offset by an increase in environmental liabilities.
Revenues Net of Purchased Power Expense. There are certain drivers of Operating revenues that are fully offset byinform their impact on Purchased power expense, such as commodity and REC procurement costs and participation in customer choice programs. Pepco recovers electricity and REC procurement costs from customers with a slight mark-up. Therefore, fluctuations in these costs have minimal impact on RNF.
Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries or RNF, but impact Operating revenues related to supplied electricity.
The changes in RNF consisted of the following:
| | | | | | Increase (Decrease) 2019 vs. 2018 | Volume | $ | 12 |
| Distribution revenue | 20 |
| Regulatory required programs | (35 | ) | Transmission revenues | 18 |
| Other | 2 |
| Total increase | $ | 17 |
|
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.
Volume, exclusive of the effects of weather, increased for the year ended December 31, 2019 compared to the same period in 2018 primarily due to the impact of residential customer growth.
| | | | | | | | As of December 31, | Number of Electric Customers | 2019 | | 2018 | Residential | 817,770 |
| | 807,442 |
| Small commercial & industrial | 54,265 |
| | 54,306 |
| Large commercial & industrial | 22,271 |
| | 22,022 |
| Public authorities & electric railroads | 160 |
| | 150 |
| Total | 894,466 |
| | 883,920 |
|
Distribution Revenues increased for the year ended December 31, 2019 compared to the same period in 2018 primarily due to higher electric distribution rates in Maryland that became effective in August 2019 and June 2018 (not reflecting the impact of TCJA), higher electric distribution rates (not reflecting the impact of TCJA) in the District of Columbia that became effective in August 2018, partially offset by the accelerated amortization of certain deferred income tax regulatory liabilities established upon the enactment of TCJA as the result of regulatory settlements. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
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 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 Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Revenues from regulatory programs decreased for the year ended December 31, 2019 compared to the same period in 2018 due to lower surcharge rates effective January 2019 for energy efficiency programs that were implemented to reflect the impacts of the enactment of TCJA.
Transmission Revenues. 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 year ended December 31, 2019 compared to the same period in 2018 due to rate increases and an increase in the highest daily peak load.
Other revenue includes revenue related to late payment charges, mutual assistance revenues, off-system sales and service application fees.
See Note 5 - Segment Information for the Combined Notes to Consolidated Financial Statements for the presentation of Pepco's revenue disaggregation.
The changes in Operating and maintenance expense consisted of the following:
| | | | | | (Decrease) Increase 2019 vs. 2018 | Baseline | | BSC and PHISCO costs | $ | (16 | ) | Labor, other benefits, contracting and materials | (11 | ) | Uncollectible accounts expense | (3 | ) | Pension and Non-Pension Postretirement Benefits
| 6 |
| Other | 8 |
| | (16 | ) | | | Regulatory required programs | (3 | ) | Total decrease | $ | (19 | ) |
| | | | | | Increase (Decrease) 2019 vs. 2018 | Depreciation expense(a) | $ | 21 |
| Regulatory asset amortization | 4 |
| Regulatory required programs | (36 | ) | Total decrease | $ | (11 | ) |
__________
| | (a) | Depreciation and amortization increased primarily due to ongoing capital expenditures. |
Interest expense, net for the year ended December 31, 2019 compared to the same period in 2018 increased primarily due to higher outstanding debt.
Effective income tax rates for the years ended December 31, 2019 and 2018 were 6.2% and 5.1%, respectively. See Note 13 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective income tax rates.
Results of Operations—DPL
| | | | | | | | | | | | | | | | | | | | | | 2019 | | 2018 | | Favorable (unfavorable) 2019 vs. 2018 variance | | 2017 | | Favorable (unfavorable) 2018 vs. 2017 variance | Operating revenues | $ | 1,306 |
| | $ | 1,332 |
| | $ | (26 | ) | | $ | 1,300 |
| | $ | 32 |
| Purchased power and fuel expense | 526 |
| | 561 |
| | 35 |
| | 532 |
| | (29 | ) | Revenues net of purchased power and fuel expense | 780 |
| | 771 |
| | 9 |
| | 768 |
| | 3 |
| Other operating expenses | | | | | | | | |
|
| Operating and maintenance | 323 |
| | 344 |
| | 21 |
| | 315 |
| | (29 | ) | Depreciation and amortization | 184 |
| | 182 |
| | (2 | ) | | 167 |
| | (15 | ) | Taxes other than income taxes | 56 |
| | 56 |
| | — |
| | 57 |
| | 1 |
| Total other operating expenses | 563 |
| | 582 |
| | 19 |
| | 539 |
| | (43 | ) | Gain on sales of assets | — |
| | 1 |
| | (1 | ) | | — |
| | 1 |
| Operating income | 217 |
| | 190 |
| | 27 |
| | 229 |
| | (39 | ) | Other income and (deductions) | | | | | | | | |
|
| Interest expense, net | (61 | ) | | (58 | ) | | (3 | ) | | (51 | ) | | (7 | ) | Other, net | 13 |
| | 10 |
| | 3 |
| | 14 |
| | (4 | ) | Total other income and (deductions) | (48 | ) | | (48 | ) | | — |
| | (37 | ) | | (11 | ) | Income before income taxes | 169 |
| | 142 |
| | 27 |
| | 192 |
| | (50 | ) | Income taxes | 22 |
| | 22 |
| | — |
| | 71 |
| | 49 |
| Net income | $ | 147 |
| | $ | 120 |
| | $ | 27 |
| | $ | 121 |
| | $ | (1 | ) |
Year Ended December 31, 2019 Compared to Year Ended December 31, 2018.Net income increased by $27 million primarily due to higher transmission revenues due to an increase in the transmission rates and the highest daily peak load, higher electric distribution rates in Maryland and Delaware that became effective throughout 2018 (not reflecting the impact of TCJA), higher natural gas distribution rates in Delaware that became effective throughout 2018 (not reflecting the impact of TCJA), and lower write-offs of construction work in progress.
Revenues Net of Purchased Power and Fuel Expense. There are certain drivers to Operating revenues that are fully offset by their impact on Purchased power and fuel expense, such as commodity and REC procurement costs and participation in customer choice programs. DPL recovers electricity and REC procurement costs from customers with a slight mark-up and natural gas costs from customers without mark-up. Therefore, fluctuations in these costs have minimal impact on RNF.
Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries or RNF, but impact Operating revenues related to supplied electricity.
The changes in RNF consisted of the following:
| | | | | | | | | | | | | | 2019 vs. 2018 | | Increase (Decrease) | | Electric | | Gas | | Total | Weather | $ | (3 | ) | | $ | (4 | ) | | $ | (7 | ) | Volume | 1 |
| | 2 |
| | 3 |
| Distribution revenue | 2 |
| | 1 |
| | 3 |
| Regulatory required programs | (7 | ) | | 2 |
| | (5 | ) | Transmission revenues | 19 |
| | — |
| | 19 |
| Other | (4 | ) | | — |
| | (4 | ) | Total increase | $ | 8 |
|
| $ | 1 |
|
| $ | 9 |
|
Revenue Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from electric distribution customers in Maryland are not affected by unseasonably warmer or colder weather because 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 year ended December 31, 2019 compared to the same period in 2018, RNF related to weather decreased primarily due to unfavorable weather conditions in DPL's Delaware 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 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 year ended December 31, 2019 compared to same period in 2018 and normal weather consisted of the following:
| | | | | | | | | | | | | | | | Delaware Electric Service Territory | For the Years Ended December 31, | | | | % Change | Heating and Cooling Degree-Days | 2019 | | 2018 | | Normal | | 2019 vs. 2018 | | 2019 vs. Normal | Heating Degree-Days | 4,475 |
| | 4,713 |
| | 4,656 |
| | (5.0 | )% | | (3.9 | )% | Cooling Degree-Days | 1,476 |
| | 1,456 |
| | 1,224 |
| | 1.4 | % | | 20.6 | % |
| | | | | | | | | | | | | | | | Delaware Natural Gas Service Territory | For the Years Ended December 31, | | | | % Change | Heating Degree-Days | 2019 | | 2018 | | Normal | | 2019 vs. 2018 | | 2019 vs. Normal | Heating Degree-Days | 4,475 |
| | 4,713 |
| | 4,698 |
| | (5.0 | )% | | (4.7 | )% |
Volume, exclusive of the effects of weather, remained relatively consistent for the year ended December 31, 2019 compared to the same period in 2018.
| | | | | | | | | | | | | Electric Retail Deliveries to Delaware Customers (in GWhs) | 2019 | | 2018 | | % Change 2019 vs. 2018 | | Weather - Normal % Change (b) | Retail Deliveries | | | | | | | | Residential | 3,149 |
| | 3,204 |
| | (1.7 | )% | | (0.2 | )% | Small commercial & industrial | 1,320 |
| | 1,344 |
| | (1.8 | )% | | (1.4 | )% | Large commercial & industrial | 3,424 |
| | 3,636 |
| | (5.8 | )% | | (5.7 | )% | Public authorities & electric railroads | 34 |
| | 33 |
| | 3.0 | % | | 0.9 | % | Total electric retail deliveries(a) | 7,927 |
| | 8,217 |
| | (3.5 | )% | | (2.9 | )% |
| | | | | | | | As of December 31, | Number of Total Electric Customers (Maryland and Delaware) | 2019 | | 2018 | Residential | 468,162 |
| | 463,670 |
| Small commercial & industrial | 61,721 |
| | 61,381 |
| Large commercial & industrial | 1,411 |
| | 1,406 |
| Public authorities & electric railroads | 613 |
| | 621 |
| Total | 531,907 |
| | 527,078 |
|
__________
| | (a) | Reflects delivery volumes and revenues 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) | 2019 | | 2018 | | % Change 2019 vs. 2018 | | Weather - Normal % Change(b) | Retail Deliveries | | | | | | | | Residential | 8,613 |
| | 8,633 |
| | (0.2 | )% | | 4.2 | % | Small commercial & industrial | 4,287 |
| | 4,134 |
| | 3.7 | % | | 7.8 | % | Large commercial & industrial | 1,811 |
| | 1,952 |
| | (7.2 | )% | | (7.1 | )% | Transportation | 6,733 |
| | 6,831 |
| | (1.4 | )% | | (0.2 | )% | Total natural gas deliveries(a) | 21,444 |
| | 21,550 |
| | (0.5 | )% | | 2.5 | % |
| | | | | | | | As of December 31, | Number of Delaware Gas Customers | 2019 | | 2018 | Residential | 125,873 |
| | 124,183 |
| Small commercial & industrial | 9,999 |
| | 9,986 |
| Large commercial & industrial | 17 |
| | 18 |
| Transportation | 159 |
| | 156 |
| Total | 136,048 |
| | 134,343 |
|
_________
| | (a) | Reflects delivery volumes and revenues 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 year ended December 31, 2019 compared to the same period in 2018 primarily due to higher electric distribution rates (not reflecting the impact of TCJA) in Maryland and Delaware that became effective throughout 2018 and higher natural gas distribution rates (not reflecting the impact of TCJA) in Delaware that became effective throughout 2018, partially offset by the accelerated amortization of certain deferred income tax regulatory liabilities established upon the enactment of TCJA as the result of regulatory settlements. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
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 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 Operating and maintenance expense, Depreciation and amortization expense and Taxes other than income taxes.
Transmission Revenues. 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 years. Generally, increases/decreases in the highest daily peak load will result in higher/lower transmission revenue. Transmission revenue increased for the year ended December 31, 2019 compared to the same period in 2018 due to rate increases and an increase in the highest daily peak load.
Other revenue includes revenue related to late payment charges, mutual assistance revenues, off-system sales and service application fees.
See Note 5 - Segment Information for the Combined Notes to Consolidated Financial Statements for the presentation of DPL's revenue disaggregation.
The changes in Operating and maintenance expense consisted of the following:
| | | | | | (Decrease) Increase 2019 vs. 2018 | Baseline | | BSC and PHISCO costs | $ | (10 | ) | Write-off of construction work in progress | (7 | ) | Uncollectible accounts expense | (2 | ) | Pension and non-pension postretirement benefits expense | 4 |
| Labor, other benefits, contracting and materials | 2 |
| Storm-related costs | (1 | ) | Other | (6 | ) | | (20 | ) | | | Regulatory required programs | (1 | ) | Total decrease | $ | (21 | ) |
The changes in Depreciation and amortization expense consisted of the following:
| | | | | | Increase (Decrease) 2019 vs. 2018 | Depreciation expense(a) | $ | 14 |
| Regulatory asset amortization | (1 | ) | Regulatory required programs | (11 | ) | Total increase | $ | 2 |
|
_________
| | (a) | Depreciation and amortization increased primarily due to ongoing capital expenditures. |
Interest expense, net for the year ended December 31, 2019 compared to the same period in 2018 increased primarily due to higher outstanding debt.
Effective income tax rates for the years ended December 31, 2019 and 2018 were 13.0% and 15.5%, respectively. See Note 13 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective income tax rates
Results of Operations—ACE
| | | | | | | | | | | | | | | | | | | | | | 2019 | | 2018 | | Favorable (unfavorable) 2019 vs. 2018 variance | | 2017 | | Favorable (unfavorable) 2018 vs. 2017 variance | Operating revenues | $ | 1,240 |
| | $ | 1,236 |
| | $ | 4 |
| | $ | 1,186 |
| | $ | 50 |
| Purchased power expense | 608 |
| | 616 |
| | 8 |
| | 570 |
| | (46 | ) | Revenues net of purchased power expense | 632 |
| | 620 |
| | 12 |
| | 616 |
| | 4 |
| Other operating expenses | | | | |
| | | |
| Operating and maintenance | 320 |
| | 330 |
| | 10 |
| | 307 |
| | (23 | ) | Depreciation and amortization | 157 |
| | 136 |
| | (21 | ) | | 146 |
| | 10 |
| Taxes other than income taxes | 4 |
| | 5 |
| | 1 |
| | 6 |
| | 1 |
| Total other operating expenses | 481 |
| | 471 |
| | (10 | ) | | 459 |
| | (12 | ) | Gain on sales of assets | — |
| | — |
| | — |
| | — |
| | — |
| Operating income | 151 |
| | 149 |
| | 2 |
| | 157 |
| | (8 | ) | Other income and (deductions) | | | | |
| | | |
| Interest expense, net | (58 | ) | | (64 | ) | | 6 |
| | (61 | ) | | (3 | ) | Other, net | 6 |
| | 2 |
| | 4 |
| | 7 |
| | (5 | ) | Total other income and (deductions) | (52 | ) | | (62 | ) | | 10 |
| | (54 | ) | | (8 | ) | Income (loss) before income taxes | 99 |
| | 87 |
| | 12 |
| | 103 |
| | (16 | ) | Income taxes | — |
| | 12 |
| | 12 |
| | 26 |
| | 14 |
| Net income | $ | 99 |
| | $ | 75 |
| | $ | 24 |
| | $ | 77 |
| | $ | (2 | ) |
Year Ended December 31, 2019 Compared to Year Ended December 31, 2018. Net income increased $24 million primarily due to higher electric distribution rates that became effective April 2019 and higher transmission revenues due to an increase in the transmission rates and the highest daily peak load, partially offset by lower average residential usage.
Revenues Net of Purchased Power Expense. There are certain drivers of Operating revenues that are fully offset by their impact on Purchased power expense, such as commodity and REC procurement costs and participation in customer choice programs. ACE recovers electricity and REC procurement costs from customers without mark-up. Therefore, fluctuations in these costs have no impact on RNF.
Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs of supplier do not impact the volume of deliveries or RNF, but impact revenues related to supplied electricity.
The changes in RNF, consisted of the following:
| | | | | | (Decrease) Increase 2019 vs. 2018 | Weather | $ | (6 | ) | Volume | (11 | ) | Distribution revenue | 36 |
| Regulatory required programs | (23 | ) | Transmission revenues | 20 |
| Other | (4 | ) | Total increase | $ | 12 |
|
Weather. The demand for electricity is 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 year ended December 31, 2019 compared to the same period in 2018, RNF related to weather was lower due to the impact of unfavorable weather conditions in ACE'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 20-year period in ACE’s service territory. The changes in heating and cooling degree days in ACE’s service territory for the year ended December 31, 2019 compared to same period in 2018, and normal weather consisted of the following:
| | | | | | | | | | | | | | | | | For the Years Ended December 31, | | Normal | | % Change | Heating and Cooling Degree-Days | 2019 | | 2018 | | | 2019 vs. 2018 | | 2019 vs. Normal | Heating Degree-Days | 4,467 |
| | 4,523 |
| | 4,676 |
| | (1.2 | )% | | (4.5 | )% | Cooling Degree-Days | 1,374 |
| | 1,535 |
| | 1,158 |
| | (10.5 | )% | | 18.7 | % |
Volume,exclusive of the effects of weather, decreased for the year ended December 31, 2019 compared to the same period in 2018, primarily due to lower average residential and commercial usage.
| | | | | | | | | | | | | Electric Retail Deliveries to Customers (in GWhs) | 2019 | | 2018 | | % Change 2019 vs. 2018 | | Weather - Normal % Change(b) | Retail Deliveries | | | | | | | | Residential | 3,966 |
| | 4,185 |
| | (5.2 | )% | | (3.5 | )% | Small commercial & industrial | 1,346 |
| | 1,361 |
| | (1.1 | )% | | 0.1 | % | Large commercial & industrial | 3,429 |
| | 3,565 |
| | (3.8 | )% | | (3.4 | )% | Public authorities & electric railroads | 47 |
| | 49 |
| | (4.1 | )% | | (2.9 | )% | Total retail deliveries(a) | 8,788 |
| | 9,160 |
| | (4.1 | )% | | (2.9 | )% |
| | | | | | | | As of December 31, | Number of Electric Customers | 2019 | | 2018 | Residential | 494,596 |
| | 490,975 |
| Small commercial & industrial | 61,497 |
| | 61,386 |
| Large commercial & industrial | 3,392 |
| | 3,515 |
| Public authorities & electric railroads | 679 |
| | 656 |
| Total | 560,164 |
| | 556,532 |
|
__________
| | (a) | Reflects delivery volumes and revenues 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 year ended December 31, 2019 compared to the same period in 2018 primarily due to higher electric distribution base rates that became effective in April 2019, partially offset by the accelerated amortization of certain deferred income tax regulatory liabilities established upon the enactment of TCJA as the result of regulatory settlements. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
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 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 Operating and maintenance expense, Depreciation and
amortization expense and Taxes other than income taxes. Revenues from regulatory programs decreased for the year ended December 31, 2019 compared to the same period in 2018 due to rate decreases effective October 2018 for the ACE Transition Bonds.
Transmission Revenues. 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 year ended December 31, 2019 compared to the same period in 2018 primarily due to rate increases and an increase in the highest daily peak load.
Other revenue includes revenue related to late payment charges, mutual assistance revenues, off-system sales and service application fees.
See Note 5 - Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ACE's revenue disaggregation.
The changes in Operating and maintenance expense consisted of the following:
| | | | | | (Decrease) Increase 2019 vs. 2018 | Baseline | | BSC and PHISCO costs | $ | (8 | ) | Uncollectible accounts expense(a) | (6 | ) | Labor, other benefits, contracting and materials | (5 | ) | Storm-related costs | 2 |
| Pension and non-pension postretirement benefits expense | 1 |
| Other | 6 |
| Total decrease
| $ | (10 | ) |
__________
| | (a) | ACE is allowed to recover from or refund to customers the difference between its annual uncollectible accounts expense and the amounts collected in rates annually through a rider mechanism. An equal and offsetting amount has been recognized in Operating revenues for the periods presented. |
The changes in Depreciation and amortizationexpense consisted of the following:
| | | | | | Increase (Decrease) 2019 vs. 2018 | Depreciation expense(a) | $ | 29 |
| Regulatory asset amortization | 6 |
| Regulatory required programs | (14 | ) | Total increase | $ | 21 |
|
__________
| | (a) | Depreciation and amortization increased primarily due to ongoing capital expenditures. |
Interest expense, net for the year ended December 31, 2019 compared to the same period in 2018 decreased primarily due to lower outstanding debt.
Other, net for the year ended December 31, 2019 compared to the same period in 2018 increased primarily due to higher AFUDC equity.
Effective income tax rates were 0.0% and 13.8% for the years ended December 31, 2019 and 2018, respectively. See Note 13 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective income tax rates.
Liquidity and Capital Resources
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 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.planning. Each of the Utility 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, retire debt, pay dividends, fund pension and OPEB obligations and invest in new and existing ventures. A broad spectrum 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.). 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 $10.6 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” 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 other postretirement benefit 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, ComEd, PECO, BGE, Pepco, DPL and ACE operate in rate-regulated environments in which the amount of new investmentalso has well establish system recovery may be delayed or limited and where such recovery takes place over an extended period of time. See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of the Registrants’ debt and credit agreements.
NRC Minimum Funding Requirements
NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that sufficient funds will be available in certain minimum amounts to decommission the facility. These NRC minimum funding levels are based upon 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 9 - Asset Retirement Obligations 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 fund investments could appreciate in value. A shortfall could require that Generation address the shortfall by, among other things, obtaining a parental guarantee for Generation’s share of the funding assurance. However, the amount of any guarantees or other assurance will ultimately depend on the decommissioning approach, the associated level of costs, and the NDT fund investment performance going forward.
Upon issuance of any required financial guarantees, 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, the NRC must approve an exemption in order for the plant’s owner(s) to utilize the NDT fund to pay for non-radiological decommissioning costs (i.e., spent fuel management and site restoration costs). If a unit does not receive this exemption, the costs would be borne by the owner(s) without reimbursement from or access to the NDT funds. The ultimate costs for spent fuel management may vary greatly and could be reduced by alternate decommissioning scenarios and/or reimbursement of certain costs under the DOE reimbursement agreements.
As of December 31, 2019, Exelon would not be required to post a parental guarantee for TMI Unit 1 under the SAFSTOR scenario which is the planned decommissioning option as described 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 would be required to allow the funds to be spent on site restoration costs, which are not expected to be incurred in the near term.
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 finance has credit facilities. See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on nonrecourse debt.
Cash Flows from Operating Activities
General
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.
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, competitive suppliers, and their ability to achieve operating cost reductions.
See Note 3 — Regulatory Matters and Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information of regulatory and legal proceedings and proposed legislation.
The following table provides a summary of the change in cash provided by (used in) operating activities for the years ended December 31, 2019, 2018 and 2017:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2019 vs. 2018 Variance | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Net income | $ | 949 |
| | $ | 774 |
| | $ | 24 |
| | $ | 68 |
| | $ | 47 |
| | $ | 84 |
| | $ | 38 |
| | $ | 27 |
| | $ | 24 |
| Add (subtract): | | | | | | | | | | | | | | | | | | Non-cash operating activities | (778 | ) | | (835 | ) | | (34 | ) | | 43 |
| | 100 |
| | (12 | ) | | (1 | ) | | (26 | ) | | (3 | ) | Pension and non-pension postretirement benefit contributions | (25 | ) | | (36 | ) | | (35 | ) | | — |
| | 6 |
| | 49 |
| | 3 |
| | (1 | ) | | 5 |
| Income taxes | (404 | ) | | 495 |
| | 33 |
| | (49 | ) | | (47 | ) | | (18 | ) | | 22 |
| | 10 |
| | 4 |
| Changes in working capital and other noncurrent assets and liabilities | (1,221 | ) | | (855 | ) | | (71 | ) | | (50 | ) | | (139 | ) | | (118 | ) | | (24 | ) | | (68 | ) | | 3 |
| Option premiums received (paid), net | 14 |
| | 14 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Collateral posted (received), net | (520 | ) | | (545 | ) | | 37 |
| | — |
| | (8 | ) | | — |
| | — |
| | — |
| | — |
| Net cash flows provided by (used in) operations | $ | (1,985 | ) | | $ | (988 | ) | | $ | (46 | ) | | $ | 12 |
| | $ | (41 | ) | | $ | (15 | ) | | $ | 38 |
| | $ | (58 | ) | | $ | 33 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2018 vs. 2017 Variance | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Net income | $ | (1,790 | ) | | $ | (2,355 | ) | | $ | 97 |
| | $ | 26 |
| | $ | 6 |
| | $ | 38 |
| | $ | 7 |
| | $ | (1 | ) | | $ | (2 | ) | Add (subtract): | | | | | | | | | | | | | | | | | | Non-cash operating activities | 2,133 |
| | 3,116 |
| | (232 | ) | | (12 | ) | | (73 | ) | | (124 | ) | | (17 | ) | | (41 | ) | | (17 | ) | Pension and non-pension postretirement benefit contributions | 22 |
| | 9 |
| | (1 | ) | | (4 | ) | | (1 | ) | | 25 |
| | 55 |
| | 2 |
| | 14 |
| Income taxes | 41 |
| | (689 | ) | | 370 |
| | (19 | ) | | (80 | ) | | (45 | ) | | (94 | ) | | (24 | ) | | 9 |
| Changes in working capital and other noncurrent assets and liabilities | 589 |
| | 359 |
| | (49 | ) | | (7 | ) | | 112 |
| | 288 |
| | 116 |
| | 95 |
| | 18 |
| Option premiums received (paid), net | (71 | ) | | (71 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Collateral posted (received), net | 240 |
| | 193 |
| | 37 |
| | — |
| | 4 |
| | — |
| | — |
| | — |
| | — |
| Net cash flows provided by (used in) operations | $ | 1,164 |
| | $ | 562 |
| | $ | 222 |
| | $ | (16 | ) | | $ | (32 | ) | | $ | 182 |
| | $ | 67 |
| | $ | 31 |
| | $ | 22 |
|
Changes in Registrants' cash flows from operations for 2019, 2018 and 2017 were generally consistent with changes in each Registrant’s respective results of operations, as adjusted for non-cash operating activities, and changes in working capital in the normal course of business. In addition, significant operating cash flow impacts for the Registrants for 2019, 2018 and 2017 were as follows:
| | • | See Note 23 —Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements and the Registrants’ Consolidated Statement of Cash Flows for additional information on non-cash operating activity.
|
| | • | See Note 13 —Income Taxes of the Combined Notes to Consolidated Financial Statements and the Registrants' Consolidated Statement of Cash Flows for additional information on income taxes.
|
| | • | Depending upon whether Generation is in a net mark-to-market liability or asset position, collateral may be required 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 OTC markets.
|
Pension and Other Postretirement Benefits
Management 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 pension obligation and regulatory implications. The Act requires the attainment of certain funding levels to avoid benefit restrictions (such as an inability to pay lump sums or to accrue benefits prospectively), and at-risk status (which triggers higher minimum contribution requirements and participant notification). The projected contributions below reflect a funding strategy to make levelized annual contributions with the objective of achieving 100% funded status on an Accumulated Benefit Obligation (ABO) basis over time. This level funding strategy helps minimize volatility of future period required pension contributions. Based on this funding strategy and current market conditions, which are subject to change, Exelon’s estimated annual qualified pension contributions will be approximately $500 million beginning in 2020. 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 other postretirement plans are also not subject to statutory minimum contribution requirements, Exelon does fund certain of its plans. For Exelon's funded OPEB plans, contributions generally equal accounting costs, however, Exelon’s management has historically considered several factors in determining the level of contributions to its OPEB plans, including liabilities management, levels of benefit claims paid and regulatory implications (amounts deemed prudent to meet regulatory expectations and best assure continued rate recovery). The amounts below include benefit payments related to unfunded plans.
The following table provides all registrants' planned contributions to the qualified pension plans, planned benefit payments to non-qualified pension plans and planned contributionsis investing in its systems to other postretirement plans in 2020:install advanced equipment and reinforce the local electric system, making it more weather resistant and less vulnerable to anticipated storm damage.
Other Environmental Regulation | | | | | | | | | | | | | | Qualified Pension Plans | | Non-Qualified Pension Plans | | OPEB | Exelon | $ | 505 |
| | $ | 36 |
| | $ | 42 |
| Generation | 227 |
| | 14 |
| | 16 |
| ComEd | 141 |
| | 2 |
| | 3 |
| PECO | 17 |
| | 1 |
| | — |
| BGE | 56 |
| | 2 |
| | 16 |
| PHI | 22 |
| | 9 |
| | 7 |
| Pepco | — |
| | 2 |
| | 7 |
| DPL | — |
| | 1 |
| | — |
| ACE | 2 |
| | — |
| | — |
|
To the extent interest rates decline significantly or the pension and OPEB plans earn less than the expected asset returns, annual pension contribution requirements in future years could increase. Conversely, to the extent interest rates increase significantly or the pension and OPEB plans earn greater than the expected asset returns, annual pension and OPEB contribution requirements in future years could decrease. Additionally, expected contributions could change if Exelon changes its pension or OPEB funding strategy.
Cash Flows from Investing Activities
The following table provides a summary of the change in cash provided by (used in) investing activities for the years ended December 31, 2019, 2018 and 2017:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2019 vs. 2018 Variance | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Capital expenditures | $ | 346 |
| | $ | 397 |
| | $ | 211 |
| | $ | (90 | ) | | $ | (186 | ) | | $ | 20 |
| | $ | 30 |
| | $ | 16 |
| | $ | (40 | ) | Proceeds from NDT fund sales, net | 199 |
| | 199 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Acquisitions of assets and businesses, net | 113 |
| | 113 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Proceeds from sales of assets and businesses | (38 | ) | | (38 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Changes in intercompany money pool | — |
| | — |
| | — |
| | (68 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| Other investing activities | (46 | ) | | (7 | ) | | — |
| | (10 | ) | | (1 | ) | | (7 | ) | | 1 |
| | (1 | ) | | (2 | ) | Net cash flows provided by (used in) investing activities | $ | 574 |
| | $ | 664 |
| | $ | 211 |
| | $ | (168 | ) | | $ | (187 | ) | | $ | 13 |
| | $ | 31 |
| | $ | 15 |
| | $ | (42 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2018 vs. 2017 Variance | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Capital expenditures | $ | (10 | ) | | $ | 17 |
| | $ | 124 |
| | $ | (117 | ) | | $ | (77 | ) | | $ | 21 |
| | $ | (28 | ) | | $ | 64 |
| | $ | (23 | ) | Proceeds from NDT fund sales, net | 33 |
| | 33 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Acquisitions of assets and businesses, net | 54 |
| | 54 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Proceeds from sales of assets and businesses | (128 | ) | | (128 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Changes in intercompany money pool | — |
| | — |
| | — |
| | (131 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| Other investing activities | 188 |
| | 155 |
| | 9 |
| | 5 |
| | 2 |
| | 5 |
| | 2 |
| | 3 |
| | 2 |
| Net cash flows provided by (used in) investing activities | $ | 137 |
| | $ | 131 |
| | $ | 133 |
| | $ | (243 | ) | | $ | (75 | ) | | $ | 26 |
| | $ | (26 | ) | | $ | 67 |
| | $ | (21 | ) |
Significant investing cash flow impacts for the Registrants for 2019, 2018 and 2017 were as follows:
| | • | Variances in capital expenditures are primarily due to the timing of cash expenditures for capital projects. Refer below for additional information on projected capital expenditure spending.
|
| | • | During 2018, Exelon and Generation had expenditures of $81 million and $57 related to the acquisitions of the Everett Marine Terminal and the Handley generating station.
|
| | • | During 2017, Exelon and Generation had expenditures of $23 million and $178 million related to the acquisitions of ConEdison Solutions and the FitzPatrick nuclear generating station.
|
| | • | During 2018, Exelon and Generation had proceeds of $85 million relating to the sale of Generation’s interest in an electrical contracting business that primarily installs, maintains and repairs underground and high-voltage cable transmission and distribution services.
|
| | • | During 2017, Exelon and Generation had proceeds of $218 million from sales of long-lived assets, primarily related to the sale back of turbine equipment.
|
| | • | Changes in intercompany money pool are driven by short-term borrowing needs. Refer to more information regarding the intercompany money pool below.
|
Capital Expenditure Spending
The Registrants most recent estimates of capital expenditures for plant additions and improvements for 2020 are as follows:
| | | | | | | | | | | (in millions) | Transmission | Distribution | Gas | Total | Exelon | N/A |
| N/A |
| N/A |
| $ | 8,175 |
| Generation | N/A |
| N/A |
| N/A |
| 1,725 |
| ComEd | 475 |
| 1,875 |
| N/A |
| 2,350 |
| PECO | 125 |
| 700 |
| 275 |
| 1,100 |
| BGE | 275 |
| 575 |
| 475 |
| 1,325 |
| Pepco | 175 |
| 675 |
| N/A |
| 850 |
| DPL | 125 |
| 225 |
| 100 |
| 450 |
| ACE | 150 |
| 225 |
| N/A |
| 375 |
|
Projected capital expenditures and other investments are subject to periodic review and revision to reflect changes in economic conditions and other factors.
Generation
Approximately 45% of projected 2020 capital expenditures at Generation are for the acquisition of nuclear fuel, with the remaining amounts reflecting additions and upgrades to existing generation facilities (including material condition improvements during nuclear refueling outages), and additional investment in new generation facilities. Generation anticipates that it will fund capital expenditures with internally generated funds and borrowings.
Utility Registrants Projected 2020 capital expenditures atUtility Operations
Service Territories and Franchise Agreements The following table presents the size of service territories, populations of each service territory, and the number of customers within each service territory for the Utility Registrants as of December 31, 2021: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE | Service Territories (in square miles) | Electric | | 11,450 | | | 2,100 | | | 2,300 | | | 650 | | | 5,400 | | | 2,750 | | Natural Gas | | N/A | | 1,900 | | | 3,050 | | | N/A | | 250 | | | N/A | Total(a) | | 11,450 | | | 2,100 | | | 3,250 | | | 650 | | | 5,400 | | | 2,750 | | | | | | | | | | | | | | | Service Territory Population (in millions) | Electric | | 9.3 | | | 4.0 | | | 3.0 | | | 2.4 | | | 1.5 | | | 1.2 | | Natural Gas | | N/A | | 2.5 | | | 2.9 | | | N/A | | 0.6 | | | N/A | Total(b) | | 9.3 | | | 4.0 | | | 3.1 | | | 2.4 | | | 1.5 | | | 1.2 | | Main City | | Chicago | | Philadelphia | | Baltimore | | District of Columbia | | Wilmington | | Atlantic City | Main City Population | | 2.7 | | | 1.6 | | | 0.6 | | | 0.7 | | | 0.1 | | | 0.1 | | | | | | | | | | | | | | | Number of Customers (in millions) | Electric | | 4.1 | | | 1.7 | | | 1.3 | | | 0.9 | | | 0.5 | | | 0.6 | | Natural Gas | | N/A | | 0.5 | | | 0.7 | | | N/A | | 0.1 | | | N/A | Total(c) | | 4.1 | | | 1.7 | | | 1.3 | | | 0.9 | | | 0.5 | | | 0.6 | | ___________(a)The number of total service territory square miles counts once only a square mile that includes both electric and natural gas services, and thus does not represent the combined total square mileage of electric and natural gas service territories. (b)The total service territory population counts once only an individual who lives in a region that includes both electric and natural gas services, and thus does not represent the combined total population of electric and natural gas service territories. (c)The number of total customers counts once only a customer who is both an electric and a natural gas customer, and thus does not represent the combined total of electric customers and natural gas customers. The Utility Registrants have the necessary authorizations to perform their current business of providing regulated electric and natural gas distribution services in the various municipalities and territories in which they now supply such services. These authorizations include charters, franchises, permits, and certificates of public convenience issued by local and state governments and state utility commissions. ComEd's, BGE's (gas), Pepco DC's, and ACE's rights are generally non-exclusive while PECO's, BGE's (electric), Pepco MD's, and DPL's rights are generally exclusive. Certain authorizations are perpetual while others have varying expiration dates. The Utility Registrants anticipate working with the appropriate governmental bodies to extend or replace the authorizations prior to their expirations.
Utility Regulations State utility commissions regulate the Utility Registrants' electric and gas distribution rates and service, issuances of certain securities, and certain other aspects of the business. The following table outlines the state commissions responsible for utility oversight: | | | | | | | | | Registrant | | Commission | ComEd | | ICC | PECO | | PAPUC | BGE | | MDPSC | Pepco | | DCPSC/MDPSC | DPL | | DEPSC/MDPSC | ACE | | NJBPU |
The Utility Registrants are public utilities under the Federal Power Act subject to regulation by FERC related to transmission rates and certain other aspects of the utilities' business. The U.S. Department of Transportation also regulates pipeline safety and other areas of gas operations for PECO, BGE, and DPL. The U.S. Department of Homeland Security (Transportation Security Administration) provided new security directives in 2021 that regulate cyber risks for certain gas distribution operators. Additionally, the Utility Registrants are subject to NERC mandatory reliability standards, which protect the nation's bulk power system against potential disruptions from cyber and physical security breaches. Seasonality Impacts on Delivery Volumes The Utility Registrants' electric distribution volumes are generally higher during the summer and winter months when temperature extremes create demand for continuingeither summer cooling or winter heating. For PECO, BGE, and DPL, natural gas distribution volumes are generally higher during the winter months when cold temperatures create demand for winter heating. ComEd, BGE, Pepco, DPL Maryland, and ACE have electric distribution decoupling mechanisms and BGE has a natural gas decoupling mechanism that eliminate the favorable and unfavorable impacts of weather and customer usage patterns on electric distribution and natural gas delivery volumes. As a result, ComEd's, BGE's, Pepco's, DPL Maryland's, and ACE's electric distribution revenues and BGE's natural gas distribution revenues are not materially impacted by delivery volumes. PECO's and DPL Delaware's electric distribution revenues and natural gas distribution revenues are impacted by delivery volumes. Electric and Natural Gas Distribution Services The Utility Registrants are allowed to recover reasonable costs and fair and prudent capital expenditures associated with electric and natural gas distribution services and earn a return on those capital expenditures, subject to commission approval. ComEd recovers costs through a performance-based rate formula. ComEd is required to file an update to the performance-based rate formula on an annual basis. On September 15, 2021, Illinois passed the Clean Energy Law, which contains requirements for ComEd to transition away from the performance-based rate formula by the end of 2022 and would allow for the submission of either a general rate or multi-year rate plan. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. PECO's, BGE's, and DPL's electric and gas distribution costs and Pepco's and ACE's electric distribution costs have generally been recovered through traditional rate case proceedings. However, the MDPSC and the DCPSC allow utilities to file multi-year rate plans. In certain instances, the Utility Registrants use specific recovery mechanisms as approved by their respective regulatory agencies. ComEd, Pepco, DPL and ACE customers have the choice to purchase electricity, and PECO and BGE customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers. DPL customers, with the exception of certain commercial and industrial customers, do not have the choice to purchase natural gas from competitive natural gas suppliers. The Utility Registrants remain the distribution service providers for all customers and are obligated to deliver electricity and natural gas to customers in their respective service territories while charging a regulated rate for distribution service. In addition, the Utility Registrants also retain significant default service obligations to provide electricity to certain groups of customers in their respective service areas who do not choose a competitive electric generation supplier. PECO,
BGE, and DPL also retain significant default service obligations to provide natural gas to certain groups of customers in their respective service areas who do not choose a competitive natural gas supplier. For customers that choose to purchase electric generation or natural gas from competitive suppliers, the Utility Registrants act as the billing agent and therefore do 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 a Utility Registrant, the Utility Registrants are permitted to recover the electricity and natural gas procurement costs from customers without mark-up or with a slight mark-up and therefore record the amounts in Operating revenues and Purchased power and fuel expense. As a result, fluctuations in electricity or natural gas sales and procurement costs have no significant impact on the Utility Registrants’ Net income. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, Results of Operations and Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information regarding electric and natural gas distribution services. Procurement of Electricity and Natural Gas The Utility Registrants' electric supply for its customers is primarily procured through contracts as required by their respective state commissions. The Utility Registrants procure electricity supply from various approved bidders, including Generation. RTO spot market purchases and sales are utilized to balance the utility electric load and supply as required. Charges incurred for electric supply procured through contracts with Generation are included in Purchased power from affiliates on the Utility Registrants' Statements of Operations and Comprehensive Income. PECO's, BGE’s, and DPL's natural gas supplies are purchased from a number of suppliers for terms of up to three years. PECO, BGE, and DPL have annual firm supply and transportation contracts of 137,000 mmcf, 268,000 mmcf and 61,000 mmcf, respectively. In addition, to supplement gas supply at times of heavy winter demands and in the event of temporary emergencies, PECO, BGE, and DPL have available storage capacity from the following sources: | | | | | | | | | | | | | | | | | | | Peak Natural Gas Sources (in mmcf) | | LNG Facility | | Propane-Air Plant | | Underground Storage Service Agreements (a) | PECO | 1,200 | | | 150 | | | 19,400 | | BGE | 1,056 | | | 550 | | | 22,000 | | DPL | 250 | | | N/A | | 3,900 | |
___________ (a)Natural gas from underground storage represents approximately 28%, 20%, and 33% of PECO's, BGE’s, and DPL's 2021-2022 heating season planned supplies, respectively. PECO, BGE, and DPL have long-term interstate pipeline contracts and also participate in the interstate markets by releasing pipeline capacity or bundling pipeline capacity with gas for off-system sales. Off-system gas sales are low-margin direct sales of gas to wholesale suppliers of natural gas. Earnings from these activities are shared between the utilities and customers. PECO, BGE, and DPL make these sales as part of a program to balance its supply and cost of natural gas. The off-system gas sales are not material to PECO, BGE, and DPL. See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK, Commodity Price Risk (All Registrants), for additional information regarding Utility Registrants' contracts to procure electric supply and natural gas. Energy Efficiency Programs The Utility Registrants are generally allowed to recover costs associated with the energy efficiency and demand response programs they offer. Each commission approved program seeks to meet mandated electric consumption reduction targets and implement demand response measures to reduce peak demand. The programs are designed to meet standards required by each respective regulatory agency. ComEd is allowed to earn a return on its energy efficiency costs. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Capital Investment The Utility Registrants' businesses are capital intensive and require significant investments, primarily in electric transmission and distribution and natural gas transportation and distribution facilities, to ensure the adequate capacity, reliability, and efficiency of their systems. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, Liquidity and Capital Resources, for additional information regarding projected 2022 capital expenditures. Transmission Services Under FERC’s open access transmission policy, the Utility Registrants, as owners of transmission facilities, are required to provide open access to their transmission facilities under filed tariffs at cost-based rates approved by FERC. The Utility Registrants and their affiliates are required to comply with FERC’s Standards of Conduct regulation governing the communication of non-public transmission information between the transmission owner’s employees and wholesale merchant employees. PJM is the regional grid operator and operates pursuant to FERC-approved tariffs. PJM is the transmission provider under, and the administrator of, the PJM Open Access Transmission Tariff (PJM Tariff). PJM operates the PJM energy, capacity, and other markets, and, through central dispatch, controls the day-to-day operations of the bulk power system for the region. The Utility Registrants are members of PJM and provide regional transmission service pursuant to the PJM Tariff. The Utility Registrants and the other transmission owners in PJM have turned over control of certain of their transmission facilities to PJM, and their transmission systems are under the dispatch control of PJM. Under the PJM Tariff, transmission service is provided on a region-wide, open-access basis using the transmission facilities of the PJM transmission owners at rates based on the costs of transmission service. The Utility Registrants' transmission rates are established based on a FERC approved formula as shown below: | | | | | | | Approval Date | ComEd | January 2008 | PECO | December 2019 | BGE | April 2006 | Pepco | April 2006 | DPL | April 2006 | ACE | April 2006 |
Exelon’s Strategy and Outlook In 2021, the businesses remained focused on maintaining industry leading operational excellence, meeting or exceeding their financial commitments, ensuring timely recovery on investments to enable customer benefits, supporting enactment of clean energy policies, and continued commitment to corporate responsibility. Exelon’s strategy is to improve reliability and operations, enhance the customer experience, and advance clean and affordable energy choices, while ensuring ratemaking mechanisms provide the utilities fair financial returns. The Utility Registrants only invest in rate base where it provides a benefit to customers and the community by improving reliability and the service experience or otherwise meeting customer needs. The Utility Registrants make these investments at the lowest reasonable cost to customers. Exelon seeks to leverage its scale and expertise across the utilities platform through enhanced standardization and sharing of resources and best practices to achieve improved operational and financial results. Additionally, the Utility Registrants anticipate making significant future investments in smart grid technology, transmission projects, gas infrastructure, and electric system improvement projects, providing greater reliability, improved service for our customers, increased capacity to accommodate new technologies, and a stable return for the company. Management continually evaluates growth opportunities aligned with Exelon’s businesses, assets and markets leveraging Exelon’s expertise in those areas and offering sustainable returns. The Utility Registrants anticipate investing approximately $29 billion over the next four years in electric and natural gas infrastructure improvements and modernization projects, including smart grid technology, storm
hardening, advanced reliability technologies, and transmission projects, which is projected to result in an increase to current rate base of approximately $17 billion by the end of 2025. The Utility Registrants invest in rate base where beneficial to customers and the community by increasing reliability and the service experience or otherwise meeting customer needs. These investments are made at the lowest reasonable cost to customers. 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. See ITEM 1. BUSINESS — Environmental Matters and Regulation — Climate Change for additional information. Various market, financial, regulatory, legislative and operational factors could affect Exelon's success in pursuing its strategies. Exelon continues to assess infrastructure, operational, policy, and legal solutions to these issues. See ITEM 1A. RISK FACTORS for additional information. Employees The Registrants strive to create a workplace that is diverse, innovative, and safe for their employees. In order to provide the services and products that their customers expect, the Registrants must create the best teams. These teams must reflect the diversity of the communities that the Registrants serve. Therefore, the Registrants strive to attract highly qualified and diverse talent and routinely review their hiring and promotion practices to ensure they maintain equitable and bias free processes to neutralize any unconscious bias. The Registrants provide growth opportunities, competitive compensation and benefits, and a variety of training and development programs. The Registrants are committed to helping employees grow their skills and careers largely through numerous training opportunities in technical, safety and business acumen areas, mentorship programs, and continuous feedback and development discussions and evaluations. Employees are encouraged to thrive outside the workplace as well. The Registrants provide a full suite of wellness benefits targeted at supporting work-life balance, physical, mental and financial health, and industry-leading paid leave policies. The Registrants generally conduct an employee engagement survey every other year to help identify their successes and areas where they can grow. The survey results are reviewed with senior management and the Exelon Board of Directors. Diversity Metrics The following tables show diversity metrics for all employees and management as of December 31, 2021. The Exelon numbers include all subsidiaries, including Generation. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Employees | | Exelon | | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Female(a) (b) | | 7,892 | | | | | 1,505 | | | 752 | | | 753 | | | 1,269 | | | 339 | | | 143 | | | 105 | | People of Color(b) | | 9,436 | | | | | 2,464 | | | 929 | | | 1,115 | | | 1,760 | | | 873 | | | 196 | | | 139 | | Aged <30 | | 3,236 | | | | | 653 | | | 315 | | | 280 | | | 413 | | | 169 | | | 87 | | | 58 | | Aged 30-50 | | 17,008 | | | | | 3,566 | | | 1,337 | | | 1,728 | | | 2,241 | | | 748 | | | 458 | | | 361 | | Aged >50 | | 11,274 | | | | | 2,037 | | | 1,157 | | | 1,120 | | | 1,532 | | | 472 | | | 365 | | | 214 | | Total Employees(c) | | 31,518 | | | | | 6,256 | | | 2,809 | | | 3,128 | | | 4,186 | | | 1,389 | | | 910 | | | 633 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Management(d) | | Exelon | | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Female(a) (b) | | 1,242 | | | | | 219 | | | 123 | | | 116 | | | 179 | | | 49 | | | 11 | | | 19 | | People of Color(b) | | 1,233 | | | | | 308 | | | 117 | | | 146 | | | 246 | | | 113 | | | 27 | | | 20 | | Aged <30 | | 73 | | | | | 6 | | | 7 | | | 1 | | | 8 | | | 3 | | | — | | | 2 | | Aged 30-50 | | 2,857 | | | | | 469 | | | 157 | | | 256 | | | 356 | | | 105 | | | 58 | | | 44 | | Aged >50 | | 2,107 | | | | | 365 | | | 194 | | | 161 | | | 266 | | | 67 | | | 59 | | | 40 | | Within 10 years of retirement eligibility | | 2,876 | | | | | 497 | | | 239 | | | 226 | | | 368 | | | 92 | | | 74 | | | 53 | | Total Employees in Management(c) | | 5,037 | | | | | 840 | | | 358 | | | 418 | | | 630 | | | 175 | | | 117 | | | 86 | |
__________ (a)The Registrants are devoted to creating an environment that allows women to stay in the workforce, grow with the company, and move up the ranks, all with parity of pay. Exelon employs an independent third-party vendor to run regression analysis on all management positions each year. The analysis consistently shows that the Registrants have no systemic pay equity issues. (b)This is based on self-disclosed information. (c)Total employees represents the sum of the aged categories. (d)Management is defined as executive/senior level officials and managers as well as all employees who have direct reports and supervisory responsibilities. Turnover Rates As turnover is inherent, management succession planning is performed and tracked for all executives and critical key manager positions. Management frequently reviews succession planning to ensure the Registrants are prepared when positions become available. The table below shows the average turnover rate for all employees for the last three years of 2019 to 2021. The Exelon numbers include all subsidiaries, including Generation. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exelon | | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Retirement Age | | 4.27 | % | | | | 3.82 | % | | 3.47 | % | | 3.70 | % | | 4.02 | % | | 4.37 | % | | 4.10 | % | | 3.17 | % | Voluntary | | 2.98 | % | | | | 1.49 | % | | 1.76 | % | | 1.36 | % | | 2.06 | % | | 2.36 | % | | 1.11 | % | | 1.20 | % | Non-Voluntary | | 0.98 | % | | | | 0.56 | % | | 1.06 | % | | 0.94 | % | | 0.96 | % | | 1.87 | % | | 0.32 | % | | 0.68 | % |
Collective Bargaining Agreements Approximately 37% of Exelon’s employees participate in CBAs. The following table presents employee information, including information about CBAs, as of December 31, 2021. The Exelon numbers include all subsidiaries, including Generation. | | | | | | | | | | | | | | | | | | | | | | | | | Total Employees Covered by CBAs | | Number of CBAs | | CBAs New and Renewed in 2021(a) | | Total Employees Under CBAs New and Renewed in 2021 | Exelon | 11,770 | | | 32 | | | 8 | | | 6,476 | | | | | | | | | | ComEd | 3,478 | | | 2 | | | 2 | | | 3,478 | | PECO | 1,351 | | | 2 | | | 2 | | | 1,351 | | BGE | 1,416 | | | 1 | | | — | | | — | | PHI | 2,161 | | | 5 | | | — | | | — | | Pepco | 929 | | | 1 | | | — | | | — | | DPL | 631 | | | 2 | | | — | | | — | | ACE | 387 | | | 2 | | | — | | | — | |
__________ (a)Does not include CBAs that were extended in 2021 while negotiations are ongoing for renewal.
Environmental Matters and Regulation On February 21, 2021, Exelon's Board of Directors approved a plan to separate the Utility Registrants and Generation, creating two publicly traded companies. The separation was completed on February 1, 2022. See Note 26 — Separation of the Combined Notes to Consolidated Financial Statements for additional information. As such, the disclosures below do not include disclosures associated with Generation. The Registrants are subject to comprehensive and complex environmental legislation and regulation at the federal, state, and local levels, including requirements relating to climate change, air and water quality, solid and hazardous waste, and impacts on species and habitats. The Exelon Board of Directors is responsible for overseeing the management of environmental matters. Exelon has a management team to address environmental compliance and strategy, including the CEO; the Senior Vice President and Chief Strategy and Sustainability Officer; as well as senior management of the Utility Registrants. Performance of those individuals directly involved in environmental compliance and strategy is reviewed and affects compensation as part of the annual individual performance review process. The Exelon Board of Directors has delegated to the Corporate Governance Committee the authority to oversee Exelon’s compliance with health, environmental, and safety laws and regulations and its strategies and efforts to protect and improve the quality of the environment, including Exelon’s internal climate change and sustainability policies and programs, as discussed in further detail below. The respective Boards of the Utility Registrants oversee environmental, health, and safety issues related to these companies. Climate Change As detailed below, the Registrants face climate change mitigation and transition risks as well as adaptation risks. Mitigation and transition risks include changes to the energy systems as a result of new technologies, changing customer expectations and/or voluntary GHG goals, as well as local, state or federal regulatory requirements intended to reduce GHG emissions. Adaptation risk refers to risks to the Registrants' facilities or operations that may result from changes in the physical climate, such as changes to temperature, weather patterns and sea level. Climate Change Mitigation and Transition The Registrants support comprehensive federal climate legislation that addresses the urgent need to substantially reduce national GHG emissions while providing appropriate protections for consumers, businesses, and the economy. In the absence of comprehensive federal legislation, Exelon supports EPA moving forward with meaningful regulation of GHG emissions under the Clean Air Act. The Registrants currently are subject to, and may become subject to additional, federal and/or state legislation and/or regulations addressing GHG emissions. GHG emission sources associated with the Registrants include natural gas (methane) leakage on the natural gas systems, sulfur hexafluoride (SF6) leakage from electric transmission and distribution operations, refrigerant leakage from chilling and cooling equipment, and fossil fuel combustion in motor vehicles. In addition, PECO, BGE, and DPL distribute natural gas; and consumers' use of such natural gas produces GHG emissions. Since its inception, Exelon has positioned itself as a leader in climate change mitigation. In 2020, Exelon's Scope 1 and 2 GHG emissions, as revised following the separation, were just over 5.6 million metric tons carbon dioxide equivalent using the World Resources Institute Corporate Standard Market-based accounting. Of these emissions, 551,000 metric tons are considered to be operations-driven and in more direct control of our employees and processes. The remaining 5 million metric tons, approximately 90%, are the indirect emissions associated with electric distribution and transmission system uses and losses resulting from the Utility Registrant's delivery of electricity to their customers. These system uses and losses are driven primarily by customer use and generation assets on the grid that are not under our ownership. 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, while also supporting customers and communities to achieve their clean energy and emissions goals. 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. Over the next 10 years, Exelon anticipates investing approximately $4.8 billion towards its "path to clean" goal. Exelon believes it has line of sight into solutions available today to achieve 80% of its "path to clean" goal and that achieving full net-zero operations will require some technology advancement and continued policy support. Exelon is laying the groundwork by partnering with national labs, universities and research consortia to research, develop and pilot clean technologies. The Utility Registrants are also driving customer-driven emissions reductions in their communities through some of the nation's largest energy efficiency programs. During 2022 - 2025, estimated energy efficiency investments across the Utility Registrants total $3.4 billion. These programs enable customer savings through home energy audits, lighting discounts, appliance recycling, home improvement rebates, equipment upgrade incentives and innovative programs like smart thermostats and combined heat and power programs. The electric sector plays a key role in lowering GHG emissions across much of the economy. Electrification, where feasible for transportation, buildings, and industry coupled with simultaneous decarbonization of electric generation can be a key lever for emissions reductions. To support this transition, Exelon is advocating for public policy supportive of vehicle electrification, investing in enabling infrastructure and technology, and supporting customer education and adoption. In addition, the Utility Registrants will electrify 30% of their own vehicle fleet by 2025, increasing to 50% by 2030. Exelon also continues to explore other decarbonization opportunities, supporting pilots of emerging energy technologies and clean fuels to support both operational and customer-driven emissions reductions. International Climate Change Agreements. At the international level, the United States is a party to the United Nations Framework Convention on Climate Change (UNFCCC). The Parties to the UNFCCC adopted the Paris Agreement at the 21st session of the UNFCCC Conference of the Parties (COP 21) on December 12, 2015. Under the Agreement, which became effective on November 4, 2016, the parties committed to try to limit the global average temperature increase and to develop national GHG reduction commitments. On November 4, 2020, the United States formally withdrew from the Paris Agreement, retracting its commitment to reduce domestic GHG emissions by 26%-28% by 2025 compared with 2005 levels. However, on January 20, 2021, President Biden accepted the Paris Agreement, which resulted in the United States’ formal re-entry on February 19, 2021. The Biden administration has announced its intent to pursue ambitious GHG reductions in the United States and internationally, and the United States has now set an economy-wide target of reducing its net GHG emissions by 50-52% below 2005 levels by 2030. The 2021 UNFCCC Conference of the Parties (COP26) and resulting Glasgow Climate Pact indicated important global support for the Paris Agreement and continued progress toward decarbonization. Federal Climate Change Legislation and Regulation.It is uncertain whether federal legislation to significantly reduce GHG emissions will be enacted in the near-term. On November 15, 2021, President Biden signed the Infrastructure Investment and Jobs Act's (IIJA) into law, which does include provisions intended to address climate change. Exelon anticipates pursuing opportunities under IIJA. Regulation of GHGs from Power Plants under the Clean Air Act.TheEPA’s 2015 Clean Power Plan (CPP) established regulations addressing carbon dioxide emissions from existing fossil-fired power plants under Clean Air Act Section 111(d). The CPP’s carbon pollution limits could be met through changes to the electric generation system, including shifting generation from higher-emitting units to lower- or zero-emitting units, as well as the development of new or expanded zero-emissions generation. In July 2019, the EPA published its final Affordable Clean Energy rule, which repealed the CPP and replaced it with less stringent emissions guidelines for existing fossil-fired power plants based on heat rate improvement measures that could be achieved within the fence line of individual plants. Exelon, together with a coalition of other electric utilities, filed a lawsuit in the U.S. Court of Appeals for the D.C. Circuit on September 6, 2019, challenging the Affordable Clean Energy rule as unlawful. This lawsuit was consolidated with separate challenges to the Affordable Clean Energy rule filed by various states, non-governmental organizations, and business coalitions. On January 19, 2021, the U.S. Court of Appeals for the D.C. Circuit held the Affordable Clean Energy Rule to be unlawful, vacated the rule, and remanded it to the EPA. On October 29, 2021, the Supreme Court granted certiorari to examine the extent of EPA's authority to regulate GHGs from power plants; a decision is expected in 2022. The EPA has indicated it will promulgate new GHG limits for existing power plants. Increased regulation of GHG emissions from power plants could increase the cost of electricity delivered or sold by The Registrants. As of February 1, 2022, the Registrants no longer directly own electric generation plants.
State Climate Change Legislation and Regulation. A number of states in which the Registrants operate have state and regional programs to reduce GHG emissions and renewable and other portfolio standards, which impact the power sector. See discussion below for additional information on renewable and other portfolio standards. Eleven northeast and mid-Atlantic states (Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Rhode Island, Vermont, and Virginia) currently participate in the RGGI, which is in the process of strengthening its requirements. The program requires most fossil fuel-fired power plants in the region to hold allowances, purchased at auction, for each ton of CO2 emissions. Non-emitting resources do not have to purchase or hold these allowances. In October 2019, the Governor of Pennsylvania issued an Executive Order directing the PA DEP to begin a rulemaking process to allow Pennsylvania to join the RGGI, with the goal of reducing carbon emissions from the electricity sector. On November 7, 2020, the PA DEP proposed its rule, which is anticipated to support Pennsylvania's participation in RGGI beginning sometime in 2022. Broader state programs impact other sectors as well, such as the District of Columbia's Clean Energy DC Omnibus Act and cross-sector GHG reduction plans, which resulted in recent requirements for Pepco to develop 5-year and 30-year decarbonization programs and strategies. Maryland has a statewide GHG reduction mandate to reduce GHG emissions by 40% no later than 2030, which it expects to meet and surpass. New Jersey accelerated its goals through Executive Order 274, which establishes an interim goal of 50% reductions below 2006 levels by 2030 and affirms its goal of achieving 80% reductions by 2050 and includes programs to drive greater amounts of electrified transportation. Finally, 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. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on the Clean Energy Law. The Registrants cannot predict the nature of future regulations or how such regulations might impact future financial statements. Renewable and Clean Energy Standards. The states where Exelon operates have adopted some form of renewable or clean energy procurement requirement. These standards impose varying levels of mandates for procurement of renewable or clean electricity (the definition of which varies by state) and/or energy efficiency. These are generally expressed as a percentage of annual electric load, often increasing by year. The Utility Registrants comply with these various requirements through purchasing qualifying renewables, implementing efficiency programs, acquiring sufficient credits (e.g., RECs), paying an alternative compliance payment, and/or a combination of these compliance alternatives. The Utility Registrants are permitted to recover from retail customers the costs of complying with their state RPS requirements, including the procurement of RECs or other alternative energy resources. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. Climate Change Adaptation The Registrants' facilities and operations are subject to the global impacts of climate change. Long-term shifts in climactic patterns, such as sustained higher temperatures and sea level rise, may present challenges for the Registrants and their service territories. Exelon believes its operations could be significantly affected by the physical risks of climate change. See ITEM 1A. RISK FACTORS, The Registrants are subject to risks associated with climate change, for additional information. The Registrants' assets undergo seasonal readiness efforts to ensure they are ready for the weather projections of the summer and winter months. The Registrants consider and review national climate assessments to inform their planning. Each of the Utility Registrants also has well establish system recovery plans and is investing in its systems to install advanced equipment and reinforce the local electric system, making it more weather resistant and less vulnerable to anticipated storm damage. Other Environmental Regulation Water Quality Under the federal Clean Water Act, NPDES permits for discharges into waterways are required to be obtained from the EPA or from the state environmental agency to which the permit program has been delegated, and
permits must be renewed periodically. Certain of Exelon's facilities discharge water into waterways and are therefore subject to these regulations and operate under NPDES permits. Under Clean Water Act Section 404 and state laws and regulations, the Registrants may be required to obtain permits for projects involving dredge or fill activities in Waters of the United States. Where Registrants’ facilities are required to secure a federal license or permit for activities that may result in a discharge to covered waters, they may be required to obtain a state water quality certification under Clean Water Act section 401. Solid and Hazardous Waste and Environmental Remediation CERCLA provides for response and removal actions coordinated by the EPA in the event of threatened releases of hazardous substances and authorizes the EPA either to clean up sites at which hazardous substances have created actual or potential environmental hazards or to order persons responsible for the situation to do so. Under CERCLA, generators and transporters of hazardous substances, as well as past and present owners and operators of hazardous waste sites, are strictly, jointly and severally liable for the cleanup costs of hazardous waste at sites, many of which are listed by the EPA on the National Priorities List (NPL). These PRPs can be ordered to perform a cleanup, can be sued for costs associated with an EPA-directed cleanup, may voluntarily settle with the EPA concerning their liability for cleanup costs, or may voluntarily begin a site investigation and site remediation under state oversight. Most states have also enacted statutes that contain provisions substantially similar to CERCLA. Such statutes apply in many states where the Registrants currently own or operate, or previously owned or operated, facilities, including Delaware, Illinois, Maryland, New Jersey, and Pennsylvania and the District of Columbia. In addition, RCRA governs treatment, storage and disposal of solid and hazardous wastes and cleanup of sites where such activities were conducted. The Registrants’ operations have in the past, and may in the future, require substantial expenditures in order to comply with these Federal and state environmental laws. Under these laws, the Registrants may be 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. The Registrants and their subsidiaries are, or could become in the future, parties to proceedings initiated by the EPA, state agencies, and/or other responsible parties under CERCLA and RCRA or similar state laws with respect to a number of sites or may undertake to investigate and remediate sites for which they may be subject to enforcement actions by an agency or third-party. ComEd’s and PECO’s environmental liabilities primarily arise from contamination at former MGP sites. ComEd, pursuant to an ICC order, and PECO, pursuant to settlements of natural gas distribution rate cases with the PAPUC, have an on-going process to recover environmental remediation costs of the MGP sites through a provision within customer rates. BGE, ACE, Pepco, and DPL do not have material contingent liabilities relating to MGP sites. The amount to be expended in 2022 for compliance with environmental remediation related to contamination at former MGP sites and other gas purification sites is estimated to be approximately $54 million which consists primarily of $48 million at ComEd. As of December 31, 2021, the Registrants have established appropriate contingent liabilities for environmental remediation requirements. In addition, the Registrants may be required to make significant additional expenditures not presently determinable for other environmental remediation costs. See Note 3 — Regulatory Matters and Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information regarding the Registrants’ environmental matters, remediation efforts, and related impacts to the Registrants’ Consolidated Financial Statements.
Information about our Executive Officers as of February 25, 2022 Exelon | | | | | | | | | | | | | | | | | | | | | Name | | Age | | Position | | Period | Crane, Christopher M. | | 63 | | | Chief Executive Officer, Exelon; | | 2012 - Present | | | | | | | | | | | | | | | | | | | President, Exelon | | 2008 - Present | | | | | | | | | | | | | | | | | | | | | | Butler, Calvin G. | | 52 | | | Senior Executive Vice President, Exelon; Chief Operations Officer, Exelon | | 2021 - Present | | | | | Senior Executive Vice President, Exelon; Chief Executive Officer, Exelon Utilities | | 2019 - 2021 | | | | | Chief Executive Officer, BGE | | 2014 - 2019 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Glockner, David | | 61 | | | Executive Vice President, Compliance and Audit, Exelon | | 2020 - Present | | | | | Chief Compliance Officer, Citadel LLC | | 2017 - 2020 | | | | | Regional Director, U.S. Securities and Exchange Commission | | 2013 - 2017 | | | | | | | | Littleton, Gayle E. | | 49 | | | Executive Vice President, General Counsel, Exelon | | 2020- Present | | | | | Partner, Jenner & Block LLP | | 2015 -2020 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Quiniones, Gil | | 55 | | | Chief Executive Officer, ComEd | | 2021 - Present | | | | | President and Chief Executive Officer, New York Power Authority | | 2011 - 2021 | | | | | | | | Innocenzo, Michael A. | | 56 | | | President and Chief Executive Officer, PECO | | 2018 - Present | | | | | Senior Vice President and Chief Operations Officer, PECO | | 2012 - 2018 | | | | | | | | Khouzami, Carim V. | | 46 | | | Chief Executive Officer, BGE | | 2019 - Present | | | | | Senior Vice President, Chief Operating Officer, Exelon Utilities | | 2018 - 2019 | | | | | Senior Vice President, Chief Financial Officer, Exelon Utilities | | 2016 - 2018 | | | | | | | | Anthony, J. Tyler | | 57 | | | President and Chief Executive Officer, PHI | | 2021 - Present | | | | | Senior Vice President and Chief Operating Officer, PHI, Pepco, DPL, and ACE | | 2016 - 2021 | | | | | | | | Nigro, Joseph | | 57 | | | Senior Executive Vice President and Chief Financial Officer, Exelon | | 2018 - Present | | | | | Executive Vice President, Exelon; Chief Executive Officer, Constellation | | 2013 - 2018 | | | | | | | | Souza, Fabian E. | | 51 | | | Senior Vice President and Corporate Controller, Exelon | | 2018 - Present | | | | | Senior Vice President and Deputy Controller, Exelon | | 2017 - 2018 | | | | | Vice President, Controller and Chief Accounting Officer, The AES Corporation | | 2015 - 2017 |
ComEd | | | | | | | | | | | | | | | | | | | | | Name | | Age | | Position | | Period | Quiniones, Gil | | 55 | | | Chief Executive Officer, ComEd | | 2021 - Present | | | | | President and Chief Executive Officer, New York Power Authority | | 2011 - 2021 | | | | | | | | Donnelly, Terence R. | | 61 | | | President and Chief Operating Officer, ComEd | | 2018 - Present | | | | | Executive Vice President and Chief Operating Officer, ComEd | | 2012 - 2018 | | | | | | | | Trpik, Joseph | | 52 | | | Interim Senior Vice President, Chief Financial Officer and Treasurer, ComEd | | 2021 - Present | | | | | Senior Vice President, Chief Financial Officer, Exelon Utilities | | 2018 - Present | | | | | Senior Vice President, Chief Financial Officer and Treasurer, ComEd | | 2009 - 2018 | | | | | | | | Rippie, E. Glenn | | 61 | | | Senior Vice President and General Counsel, ComEd | | 2022 - Present | | | | | Partner, Jenner & Block LLP | | 2019 - 2021 | | | | | Partner and Chief Financial Officer, Rooney, Rippie & Ratnaswamy, LLP | | 2010 - 2019 | | | | | | | | Washington, Melissa | | 52 | | | Senior Vice President, Customer Operations and Chief Customer Officer, ComEd | | 2021 - Present | | | | | | | | | | | | Senior Vice President, Governmental and External Affairs, ComEd | | 2019 - 2021 | | | | | Vice President, Governmental and External Affairs, ComEd | | 2019 -2019 | | | | | Vice President, External Affairs and Large Customer Services, ComEd | | 2016 - 2019 | | | | | | | | Perez, David | | 52 | | | Senior Vice President, Distribution Operations, ComEd | | 2019 - Present | | | | | Vice President, Transmission and Substation, ComEd | | 2016 - 2019 | | | | | | | | Blaise, M. Michelle | | 60 | | | Senior Vice President, Technical Services, ComEd | | 2014 - Present | | | | | | | |
PECO | | | | | | | | | | | | | | | | | | | | | Name | | Age | | Position | | Period | Innocenzo, Michael A. | | 56 | | | President and Chief Executive Officer, PECO | | 2018 - Present | | | | | Senior Vice President and Chief Operations Officer, PECO | | 2012 - 2018 | | | | | | | | McDonald, John | | 64 | | | Senior Vice President and Chief Operations Officer, PECO | | 2018 - Present | | | | | Vice President, Integration, PHI | | 2016 - 2018 | Stefani, Robert J. | | 48 | | | Senior Vice President, Chief Financial Officer and Treasurer, PECO | | 2018 - Present | | | | | Vice President, Corporate Development, Exelon | | 2015 - 2018 | | | | | | | | Murphy, Elizabeth A. | | 62 | | | Senior Vice President, Governmental and External Affairs, PECO | | 2016 - Present | | | | | | | | | | | | | | | Webster Jr., Richard G. | | 60 | | | Vice President, Regulatory Policy and Strategy, PECO | | 2012 - Present | | | | | | | | | | | | | | | Williamson, Olufunmilayo | | 43 | | | Senior Vice President, Customer Operations, PECO | | 2020 - Present | | | | | Senior Vice President, Chief Commercial Risk Officer, Exelon | | 2017 - 2020 | | | | | Vice President, Commercial Risk Management, Exelon | | 2015 - 2017 | | | | | | | | Gay, Anthony | | 56 | | | Vice President and General Counsel, PECO | | 2019 - Present | | | | | | | | | | | | Vice President, Governmental and External Affairs, PECO | | 2016 - 2019 | | | | | | | |
BGE | | | | | | | | | | | | | | | | | | | | | Name | | Age | | Position | | Period | Khouzami, Carim V. | | 46 | | | Chief Executive Officer, BGE | | 2019 - Present | | | | | Senior Vice President, Chief Operating Officer, Exelon Utilities | | 2018 - 2019 | | | | | Senior Vice President, Chief Financial Officer, Exelon Utilities | | 2016 - 2018 | | | | | | | | Dickens, Derrick | | 56 | | | Senior Vice President and Chief Operating Officer, BGE | | 2021 - Present | | | | | Senior Vice President, Customer Operations, PHI | | 2020 - 2021 | | | | | Vice President, Technical Services, BGE | | 2016 - 2020 | | | | | | | | | | | | | | | Vahos, David M. | | 49 | | | Senior Vice President, Chief Financial Officer and Treasurer, BGE | | 2016 - Present | | | | | | | | | | | | | | | Núñez, Alexander G. | | 50 | | | Senior Vice President, Governmental, External and Regulatory Affairs, BGE | | 2021 - Present | | | | | Senior Vice President, Regulatory Affairs and Strategy, BGE | | 2020 - 2021 | | | | | Senior Vice President, Regulatory and External Affairs, BGE | | 2016 - 2020 | | | | | | | | Case, Mark D. | | 60 | | | Vice President, Strategy and Regulatory Affairs, BGE | | 2012 - Present | | | | | | | | | | | | | | | Galambos, Denise | | 59 | | | Senior Vice President, Customer Operations, BGE | | 2021 - Present | | | | | Vice President, Utility Oversight, Exelon Utilities | | 2020 - 2021 | | | | | VP, Human Resources, BGE | | 2018 - 2020 | | | | | Associate General Counsel, Exelon | | 2012 - 2017 | | | | | | | | Ralph, David | | 55 | | | Vice President and General Counsel, BGE | | 2021 - Present | | | | | Associate General Counsel, BGE | | 2019 - 2021 | | | | | Assistant General Counsel, Exelon | | 2017 - 2019 | | | | | City Attorney, City of Baltimore | | 2016 - 2017 |
PHI, Pepco, DPL, and ACE | | | | | | | | | | | | | | | | | | | | | Name | | Age | | Position | | Period | Anthony, J. Tyler | | 57 | | | President and Chief Executive Officer, PHI | | 2021 - Present | | | | | Senior Vice President and Chief Operating Officer, PHI, Pepco, DPL, and ACE | | 2016 - 2021 | | | | | | | | Olivier, Tamla | | 49 | | | Senior Vice President and Chief Operating Officer, PHI, Pepco, DPL, and ACE | | 2021 - Present | | | | | Senior Vice President, Customer Operations, BGE | | 2020 - 2021 | | | | | Senior Vice President, Constellation NewEnergy, Inc. | | 2016 - 2020 | | | | | | | | Barnett, Phillip S. | | 58 | | | Senior Vice President, Chief Financial Officer and Treasurer, PHI, Pepco, DPL, and ACE | | 2018 - Present | | | | | Senior Vice President and Chief Financial Officer, PECO | | 2007 - 2018 | | | | | Treasurer, PECO | | 2012 - 2018 | | | | | | | | Oddoye, Rodney | | 45 | | | Senior Vice President, Governmental & External Affairs, PHI, Pepco, DPL, and ACE | | 2021 - Present | | | | | Senior Vice President, Governmental and External Affairs, BGE | | 2020 - 2021 | | | | | Vice President, Customer Operations, BGE | | 2018 - 2020 | | | | | Director, Northeast Regional Electric Operations, BGE | | 2016 - 2018 | | | | | | | | Bancroft, Anne | | 55 | | | Vice President and General Counsel, PHI | | 2021 - Present | | | | | Associate General Counsel, Exelon | | 2017 - 2021 | | | | | Assistant General Counsel, Exelon | | 2010 - 2017 | | | | | | | | Bell-Izzard, Morlon | | 56 | | | Senior Vice President, Customer Operations & Chief Customer Officer, PHI | | 2021 - Present | | | | | Vice President, Customer Operations, PHI | | 2019 - 2021 | | | | | Director, Utility Performance Assessment, Exelon | | 2016 - 2019 | | | | | | | | O'Donnell, Morgan | | 46 | | | Vice President, Regulatory Policy and Strategy, DC/MD | | 2021 - Present | | | | | Director, Financial Planning and Analysis, PHI | | 2020 - 2021 | | | | | Director, Regulatory Strategy & Revenue Policy, PHI | | 2019 - 2020 | | | | | Manager, Regulatory Analysis, PHI | | 2016 - 2019 | | | | | | | | Humphrey, Marissa | | 42 | | Vice President, Regulatory Policy and Strategy, PHI, DPL, and ACE | | 2021 - Present | | | | | Vice President Finance, Exelon Utilities | | 2019 - 2020 | | | | | Vice President, Finance, PHI | | 2016 - 2019 | | | | | | | |
On February 21, 2021, Exelon’s Board of Directors approved a plan to separate the Utility Registrants and Generation, creating two publicly traded companies. The separation was completed on February 1, 2022. See Note 26 — Separation of the Combined Notes to Consolidated Financial Statements for additional information. As such, the risk factors discussed below do not include those associated with Generation. Each of the Registrants operates in a complex market and regulatory environment that involves significant risks, many of which are beyond that Registrant’s direct control. Such risks, which could negatively affect one or more of the Registrants’ consolidated financial statements, fall primarily under the categories below:
Risks related to market and financial factors primarily include: •the demand for electricity, reliability of service, and affordability in the markets where the Utility Registrants conduct their business, •the ability of the Utility Registrants to operate their respective transmission and distribution assets, their ability to access capital markets, and the impacts on their results of operations due to the global outbreak (pandemic) of the 2019 novel coronavirus (COVID-19), and •emerging technologies and business models, including those related to climate change mitigation and transition to a low carbon economy. Risks related to legislative, regulatory, and legal factors primarily include changes to, and compliance with, the laws and regulations that govern: •utility regulatory business models, •environmental and climate policy, and •tax policy. Risks related to operational factors primarily include: •changes in the global climate could produce extreme weather events, which could put the Registrant’s facilities at risk, and such changes could also affect the levels and patterns of demand for energy and related services, •the ability of the Utility Registrants to maintain the reliability, resiliency, and improve operations, including enhancing reliabilitysafety of their energy delivery systems, which could affect their ability to deliver energy to their customers and adding capacityaffect their operating costs, and •physical and cyber security risks for the Utility Registrants as the owner-operators of transmission and distribution facilities. Risks related to the separation primarilyinclude: •challenges to achieving the benefits of separation and •performance by Exelon and Generation under the transaction agreements, including indemnification responsibilities. There may be further risks and uncertainties that are not presently known or that are not currently believed to be material that could negatively affect the Registrants' consolidated financial statements in the future. Risks Related to Market and Financial Factors The Registrants are potentially affected by emerging technologies that could over time affect or transform the energy industry (All Registrants). Advancements in power generation technology, including commercial and residential solar generation installations and commercial micro turbine installations, are improving the cost-effectiveness of customer self-supply of electricity. Improvements in energy storage technology, including batteries and fuel cells, could also better position customers to meet their around-the-clock electricity requirements. Improvements in energy efficiency of lighting, appliances, equipment and building materials will also affect energy consumption by customers. Changes in power generation, storage, and use technologies could have significant effects on customer behaviors and their energy consumption. These developments could affect levels of customer-owned generation, customer expectations, and current business models and make portions of the Utility Registrants' transmission and/or distribution facilities uneconomic prior to the end of their useful lives. These factors could affect the Registrants’ consolidated financial statements through, among other things, increased operating and maintenance expenses, increased capital
expenditures, and potential asset impairment charges or accelerated depreciation over shortened remaining asset useful lives. Market performance and other factors could decrease the value of employee benefit plan assets and could increase the related employee benefit plan obligations, which then could require significant additional funding (All Registrants). Disruptions in the capital markets and their actual or perceived effects on particular businesses and the greater economy could adversely affect the value of the investments held within Exelon’s employee benefit plan trusts. The asset values are subject to market fluctuations and will yield uncertain returns, which could fall below Exelon's projected return rates. A decline in the market value of the pension and OPEB plan assets would increase the funding requirements associated with Exelon’s pension and OPEB plan obligations. Additionally, Exelon’s pension and OPEB plan liabilities are sensitive to changes in interest rates. As interest rates decrease, the liabilities increase, potentially increasing benefit costs and funding requirements. Changes in demographics, including increased numbers of retirements or changes in life expectancy assumptions or changes to Social Security or Medicare eligibility requirements could also increase the costs and funding requirements of the obligations related to the pension and OPEB plans. See Note 15 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information. The Registrants could be negatively affected by unstable capital and credit markets (All Registrants). The Registrants rely on the capital markets, particularly for publicly offered debt, as well as the banking and commercial paper markets, to meet their financial commitments and short-term liquidity needs. Disruptions in the capital and credit markets in the United States or abroad could negatively affect the Registrants’ ability to access the capital markets or draw on their respective bank revolving credit facilities. The banks may not be able to meet their funding commitments to the Registrants if they experience shortages of capital and liquidity or if they experience excessive volumes of borrowing requests within a short period of time. The inability to access capital markets or credit facilities, and longer-term disruptions in the capital and credit markets as a result of uncertainty, changing or increased regulation, reduced alternatives, or failures of significant financial institutions could result in the deferral of discretionary capital expenditures, or require a reduction in dividend payments or other discretionary uses of cash. In addition, the Registrants have exposure to worldwide financial markets, including Europe, Canada, and Asia. Disruptions in these markets could reduce or restrict the Registrants’ ability to secure sufficient liquidity or secure liquidity at reasonable terms. As of December 31, 2021, approximately 20%, 17%, and 16% of the Registrants’ available credit facilities (not including Generation's credit facilities) were with European, Canadian, and Asian banks, respectively. See Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the credit facilities. If any of the Registrants were to experience a downgrade in its credit ratings to below investment grade or otherwise fail to satisfy the credit standards in its agreements with its counterparties or regulatory financial requirements, it would be required to provide significant amounts of collateral that could affect its liquidity and could experience higher borrowing costs (All Registrants). The Utility Registrants' operating agreements with PJM and PECO's, BGE's, and DPL's natural gas procurement contracts contain collateral provisions that are affected by their credit rating and market prices. If certain wholesale market conditions were to exist and the Utility Registrants were to lose their investment grade credit ratings (based on their senior unsecured debt ratings), they would be required to provide collateral in the forms of letters of credit or cash, which could have a material adverse effect upon their remaining sources of liquidity. PJM collateral posting requirements will generally increase as market prices rise and decrease as market prices fall. Collateral posting requirements for PECO, BGE, and DPL, with respect to their natural gas supply contracts, will generally increase as forward market prices fall and decrease as forward market prices rise. If the Utility Registrants were downgraded, they could experience higher borrowing costs as a result of the downgrade. In addition, changes in ratings methodologies by the agencies could also have an adverse negative impact on the ratings of the Utility Registrants. The Utility Registrants conduct their respective businesses and operate under governance models and other arrangements and procedures intended to assure that the Utility Registrants are treated as separate,
independent companies, distinct from Exelon and other Exelon subsidiaries in order to isolate the Utility Registrants from Exelon and other Exelon subsidiaries in the event of financial difficulty at Exelon or another Exelon subsidiary. These measures (commonly referred to as “ring-fencing”) could help avoid or limit a downgrade in the credit ratings of the Utility Registrants in the event of a reduction in the credit rating of Exelon. Despite these ring-fencing measures, the credit ratings of the Utility Registrants could remain linked, to some degree, to the credit ratings of Exelon. Consequently, a reduction in the credit rating of Exelon could result in a reduction of the credit rating of some or all of the Utility Registrants. A reduction in the credit rating of a Utility Registrant could have a material adverse effect on the Utility Registrant. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Liquidity and Capital Resources — Credit Matters — Market Conditions and Security Ratings for additional information regarding the potential impacts of credit downgrades on the Registrants’ cash flows. The impacts of significant economic downturns or increases in customer rates, could lead to decreased volumes delivered and increased expense for uncollectible customer balances (All Registrants). The impacts of significant economic downturns on the Utility Registrants' customers and the related regulatory limitations on residential service terminations for the Utility Registrants, could result in an increase in the number of uncollectible customer balances and related expense. Further, increases in customer rates, including those related to increases in purchased power and natural gas prices, could result in declines in customer usage and lower revenues for the Utility Registrants that do not have decoupling mechanisms. See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for additional information on the Registrants’ credit risk. The Registrants' results were negatively affected by the impacts of COVID-19 (All Registrants). COVID-19 has disrupted economic activity in the Registrants’ respective markets and negatively affected the Registrants’ results of operations. The estimated impact of COVID-19 to the Utility Registrants’ Net income was approximately $75 million for the year ended December 31, 2020 and was not material for the year ended December 31, 2021. The Registrants cannot predict the full extent of the impacts of COVID-19, which will depend on, among other things, the rate, and public perceptions of the effectiveness, of vaccinations and rate of resumption of business activity. In addition, any future widespread pandemic or other local or global health issue could adversely affect customer demand and the Registrants’ ability to operate their transmission and distribution assets. See Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - Executive Overview for additional information. The Registrants could be negatively affected by the impacts of weather (All Registrants). Weather conditions directly influence the demand for electricity and natural gas and affect the price of energy commodities. Temperatures above normal levels in the summer tend to increase summer cooling electricity demand and revenues, and temperatures below normal levels in the winter tend to increase winter heating electricity and gas demand and revenues. Moderate temperatures adversely affect the usage of energy and resulting operating revenues at PECO and DPL Delaware. Due to revenue decoupling, operating revenues from electric distribution at ComEd, BGE, Pepco, DPL Maryland, and ACE are not affected by abnormal weather. Extreme weather conditions or damage resulting from storms could stress the Utility Registrants' transmission and distribution systems, communication systems, and technology, resulting in increased maintenance and capital costs and limiting each company’s ability to meet peak customer demand. First and third quarter financial results, in particular, are substantially dependent on weather conditions, and could make period comparisons less relevant. 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 the Utility Registrants have transmission and distribution assets. The frequency in which weather conditions emerge outside the current expected climate norms could contribute to weather-related impacts discussed above.
Long-lived assets, goodwill, and other assets could become impaired (All Registrants). Long-lived assets represent the single largest asset class on the Registrants’ statements of financial position. In addition, Exelon, ComEd, and PHI have material goodwill balances. The Registrants evaluate the recoverability of the carrying value of long-lived assets to be held and used whenever events or circumstances indicating a potential impairment exist. Factors such as, but not limited to, the business climate, including current and future energy and market conditions, environmental regulation, and the condition of assets are considered. ComEd and PHI perform an assessment for possible impairment of their goodwill at least annually or more frequently if an event occurs or circumstances change that would more likely than not reduce the fair value of the reporting units below their carrying amount. Regulatory actions or changes in significant assumptions, including discount and growth rates, utility sector market performance and transactions, projected operating and capital cash flows for ComEd’s, Pepco’s, DPL’s, and ACE’s business, and the fair value of debt, could potentially result in future impairments of Exelon’s, ComEd's, and PHI’s goodwill. An impairment would require the Registrants to reduce the carrying value of the long-lived asset or goodwill to fair value through a non-cash charge to expense by the amount of the impairment. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Critical Accounting Policies and Estimates, Note 8 — Property, Plant, and Equipment, Note 12 — Asset Impairments and Note 13 — Intangible Assets of the Combined Notes to the Consolidated Financial Statements for additional information on long-lived asset impairments and goodwill impairments. The Registrants could incur substantial costs in the event of non-performance by third-parties under indemnification agreements, or when the Registrants have guaranteed their performance (All Registrants). The Registrants have entered into various agreements with counterparties that require those counterparties to reimburse a Registrant and hold it harmless against specified obligations and claims. To the extent that any of these counterparties are affected by deterioration in their creditworthiness or the agreements are otherwise determined to be unenforceable, the affected Registrant could be held responsible for the obligations. Each of the Utility Registrants has transferred its former generation business to a third party and in each case the transferee has agreed to assume certain obligations and to indemnify the applicable Utility Registrant for such obligations. In connection with the restructurings under which ComEd, PECO, and BGE transferred their generating assets to Generation, Generation assumed certain of ComEd’s, PECO’s, and BGE's rights and obligations with respect to their former generation businesses. Further, ComEd, PECO, and BGE have entered into agreements with third parties under which the third-party agreed to indemnify ComEd, PECO, or BGE for certain obligations related to their respective former generation businesses that have been assumed by Generation as part of the restructuring. If the third-party, Generation, or the transferee of Pepco's, DPL's, or ACE’s generation facilities experienced events that reduced its creditworthiness or the indemnity arrangement became unenforceable, the applicable Utility Registrant could be liable for any existing or future claims. In addition, the Utility Registrants have residual liability under certain laws in connection with their former generation facilities. The Registrants have issued indemnities to third parties regarding environmental or other matters in connection with purchases and sales of assets, including several of the Utility Registrants in connection with Generation's absorption of their former generating assets. The Registrants could incur substantial costs to fulfill their obligations under these indemnities. The Registrants have issued guarantees of the performance of third parties, which obligate the Registrants to perform in the event that the third parties do not perform. In the event of non-performance by those third parties, the Registrants could incur substantial cost to fulfill their obligations under these guarantees.
Risks Related to Legislative, Regulatory, and Legal Factors The Registrants' businesses are highly regulated and could be negatively affected by legislative and/or regulatory actions (All Registrants). Substantial aspects of the Registrants' businesses are subject to comprehensive Federal or state legislation and/or regulation. The Utility Registrants' consolidated financial statements are heavily dependent on the ability of the Utility Registrants to recover their costs for the retail purchase and distribution of power and natural gas to their customers. Fundamental changes in regulations or adverse legislative actions affecting the Registrants’ businesses would require changes in their business planning models and operations. The Registrants cannot predict when or whether legislative or regulatory proposals could become law or what their effect would be on the Registrants. Changes in the Utility Registrants' construction commitments underrespective terms and conditions of service, including their respective rates, are subject to regulatory approval proceedings and/or negotiated settlements that are at times contentious, lengthy, and subject to appeal, which lead to uncertainty as to the ultimate result and which could introduce time delays in effectuating rate changes (All Registrants). The Utility Registrants are required to engage in regulatory approval proceedings as a part of the process of establishing the terms and rates for their respective services. These proceedings typically involve multiple parties, including governmental bodies and officials, consumer advocacy groups, and various consumers of energy, who have differing concerns but who have the common objective of limiting rate increases or even reducing rates. Decisions are subject to appeal, potentially leading to additional uncertainty associated with the approval proceedings. The potential duration of such proceedings creates a risk that rates ultimately approved by the applicable regulatory body may not be sufficient for a Utility Registrant to recover its costs by the time the rates become effective. Established rates are also subject to subsequent prudency reviews by state regulators, whereby various portions of rates could be adjusted, subject to refund or disallowed, including recovery mechanisms for costs associated with the procurement of electricity or gas, credit losses, MGP remediation, smart grid infrastructure, and energy efficiency and demand response programs. In certain instances, the Utility Registrants could agree to negotiated settlements related to various rate matters, customer initiatives, or franchise agreements. These settlements are subject to regulatory approval. The ultimate outcome and timing of regulatory rate proceedings have a significant effect on the ability of the Utility Registrants to recover their costs or earn an adequate return. See Note 3 — Regulatory Matters of the Combined Notes to the Consolidated Financial Statements for additional information. The Registrants could be subject to higher costs and/or penalties related to mandatory reliability standards, including the likely exposure of the Utility Registrants to the results of PJM’s RTEP.RTEP and NERC compliance requirements (All Registrants). The Utility Registrants as users, owners, and operators of the bulk power transmission ownerssystem are subject to mandatory reliability standards promulgated by NERC and enforced by FERC. PECO, BGE, and DPL, as operators of natural gas distribution systems, are also subject to mandatory reliability standards of the U.S. Department of Transportation. The standards are based on the functions that need to be performed to ensure the bulk power system operates reliably and are guided by reliability and market interface principles. Compliance with or changes in the reliability standards could subject the Registrants to higher operating costs and/or increased capital expenditures. In addition, the ICC, PAPUC, MDPSC, DCPSC, DEPSC, and NJBPU impose certain distribution reliability standards on the Utility Registrants. If the Utility Registrants were found in non-compliance with the Federal and state mandatory reliability standards, they could be subject to remediation costs as well as sanctions, which could include substantial monetary penalties.
The Registrants could incur substantial costs to fulfill their obligations related to environmental and other matters (All Registrants). The Registrants are subject to extensive environmental regulation and legislation by local, state, and Federal authorities. These laws and regulations affect the manner in which the Registrants conduct their operations and make capital expenditures including how they handle air and water emissions, hazardous and solid waste, and activities affecting surface waters, groundwater, and aquatic and other species. Violations of these requirements could subject the Registrants to enforcement actions, capital expenditures to bring existing facilities into compliance, additional operating costs for remediation and clean-up costs, civil penalties and exposure to third parties’ claims for alleged health or property damages, or operating restrictions to achieve compliance. In addition, the Registrants are subject to liability under these laws for the remediation costs for environmental contamination of property now or formerly owned by the Registrants and of property contaminated by hazardous substances they generated or released. Remediation activities associated with MGP operations conducted by predecessor companies are one component of such costs. Also, the Registrants are currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and could be subject to additional proceedings in the future. See ITEM 1. BUSINESS — Environmental Matters and Regulation for additional information. The Registrants could be negatively affected by federal and state RPS and/or energy conservation legislation, along with energy conservation by customers (All Registrants). Changes to current state legislation or the development of Federal legislation that requires the use of clean, renewable, and alternate fuel sources could significantly impact the Utility Registrants, especially if timely cost recovery is not allowed. Federal and state legislation mandating the implementation of energy conservation programs that require the implementation of new technologies, such as smart meters and smart grid, could increase capital expenditures and could significantly impact the Utility Registrants consolidated financial statements if timely cost recovery is not allowed. These energy conservation programs, regulated energy consumption reduction targets, and new energy consumption technologies could cause declines in customer energy consumption and lead to a decline in the Registrants' revenues. See ITEM 1. BUSINESS — Environmental Matters and Regulation — Renewable and Clean Energy Standards and "The Registrants are potentially affected by emerging technologies that could over time affect or transform the energy industry" above for additional information. The Registrants could be negatively affected by challenges to tax positions taken, tax law changes, and the inherent difficulty in quantifying potential tax effects of business decisions. (All Registrants). The Registrants are required to make judgments in order to estimate their obligations to taxing authorities. These tax obligations include income, real estate, sales and use, and employment-related taxes and ongoing appeal issues related to these tax matters. These judgments include reserves established for potential adverse outcomes regarding tax positions that have been taken that could be subject to challenge by the tax authorities. See Note 1 — Significant Accounting Policies and Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information. Legal proceedings could result in a negative outcome, which the Registrants cannot predict (All Registrants). The Registrants are involved in legal proceedings, claims, and litigation arising out of their business operations. The material ones are summarized in Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements. Adverse outcomes in these proceedings could require significant expenditures, result in lost revenue, or restrict existing business activities. The Registrants could be subject to adverse publicity and reputational risks, which make them vulnerable to negative customer perception and could lead to increased regulatory oversight or other consequences (All Registrants).
The Registrants could be the subject of public criticism. Adverse publicity of this nature could render public service commissions and other regulatory and legislative authorities less likely to view energy companies in a favorable light, and could cause those companies, including the Registrants, to be susceptible to less favorable legislative and regulatory outcomes, as well as increased regulatory oversight and more stringent legislative or regulatory requirements. Exelon and ComEd have received requests for information related to an SEC investigation into their lobbying activities. The outcome of the investigations could have a material adverse effect on their reputation and consolidated financial statements (Exelon and ComEd). On October 22, 2019, the SEC notified Exelon and ComEd that it had opened an investigation into their lobbying activities in the state of Illinois. Exelon and ComEd have cooperated fully, including by providing all information requested by the SEC, and intend to continue to cooperate fully and expeditiously with the SEC. The outcome of the SEC’s investigation cannot be predicted and could subject Exelon and ComEd to civil penalties, sanctions, or other remedial measures. Any of the foregoing, as well as the appearance of non-compliance with anti-corruption and anti-bribery laws, could have an adverse impact on Exelon’s and ComEd’s reputations or relationships with regulatory and legislative authorities, customers, and other stakeholders, as well as their consolidated financial statements. See Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements. If ComEd violates its Deferred Prosecution Agreement announced on July 17, 2020, it could have an adverse effect on the reputation and consolidated financial statements of Exelon and ComEd (Exelon and ComEd). On July 17, 2020, ComEd entered into a Deferred Prosecution Agreement (DPA) with the U.S. Attorney’s Office for the Northern District of Illinois (USAO) to resolve the USAO’s investigation into Exelon’s and ComEd’s lobbying activities in the State of Illinois. Exelon was not made a party to the DPA and the investigation by the USAO into Exelon’s activities ended with no charges being brought against Exelon. 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, but not limited to, the following: (i) payment to the United States Treasury of $200 million; (ii) continued full cooperation with the government’s investigation; and (iii) ComEd’s adoption and maintenance of remedial measures involving compliance and reporting undertakings as specified in the DPA. If ComEd is found to have breached the terms of the DPA, the USAO may elect to prosecute, or bring a civil action against, ComEd for conduct alleged in the DPA or known to the government, which could result in fines or penalties and could have an adverse impact on Exelon’s and ComEd’s reputation or relationships with regulatory and legislative authorities, customers and other stakeholders, as well as their consolidated financial statements. See Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements. Risks Related to Operational Factors The Registrants are subject to risks associated with climate change (All Registrants). Climate adaptation risk refers to risks to the Registrants' facilities or operations that may result from changes in the physical climate, such as changes to temperature, weather patterns and sea level. The Registrants periodically perform analyses to better understand how climate change could affect their facilities and operations. The Registrants primarily operate in the Midwest and East Coast of the United States, areas that historically have been prone to various types of severe weather events, and as such the Registrants have well-developed response and recovery programs based on these historical events. However, the Registrants’ physical facilities could be placed at greater risk of damage should changes in the global climate impact temperature and weather patterns, and result in more intense, frequent and extreme weather events, unprecedented levels of precipitation, sea level rise, increased surface water temperatures, and/or other effects.
Over time, the Registrants may need to make additional investments to protect their facilities from physical climate-related risks. In addition, changes to the climate may impact levels and patterns of demand for energy and related services, which could affect Registrants’ operations. Over time, the Registrants may need to make additional investments to adapt to changes in operational requirements as a result of climate change. Climate mitigation and transition risks include changes to the energy systems as a result of new technologies, changing customer expectations and/or voluntary GHG goals, as well as local, state or federal regulatory requirements intended to reduce GHG emissions. The Registrants also periodically perform analyses of potential pathways to reduce power sector and economy-wide GHG emissions to mitigate climate change. To the extent additional GHG reduction legislation and/or regulation becomes effective at the Federal and/or state levels, the Registrants could incur costs to further limit the GHG emissions from their operations or otherwise comply with applicable requirements. NERC provides guidanceSee ITEM 1. BUSINESS — Environmental Matters and Regulation — Climate Change and "The Registrants are potentially affected by emerging technologies that could over time affect or transform the energy industry" above for additional information. The Utility Registrants' operating costs are affected by their ability to maintain the availability and reliability of their delivery and operational systems (All Registrants). Failures of the equipment or facilities used in the Utility Registrants' delivery systems could interrupt the electric transmission owners regarding assessmentsand electric and natural gas delivery, which could result in a loss of revenues and an increase in maintenance and capital expenditures. Equipment or facilities failures can be due to a number of factors, including natural causes such as weather or information systems failure. Specifically, if the implementation of AMI, smart grid, or other technologies in the Utility Registrants' service territory fail to perform as intended or are not successfully integrated with billing and other information systems, or if any of the financial, accounting, or other data processing systems fail or have other significant shortcomings, the Utility Registrants' financial results could be negatively impacted. In addition, dependence upon automated systems could further increase the risk that operational system flaws or internal and/or external tampering or manipulation of those systems will result in losses that are difficult to detect. Regulated utilities, which are required to provide service to all customers within their service territory, have generally been afforded liability protections against claims by customers relating to failure of service. Under Illinois law, however, ComEd could be required to pay damages to its customers in some circumstances involving extended outages affecting large numbers of its customers, which could be material. The Registrants are subject to physical security and cybersecurity risks (All Registrants). The Registrants face physical security and cybersecurity risks. Threat sources continue to seek to exploit potential vulnerabilities in the electric and natural gas utility 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 advanced digital technologies increases the potentially unfavorable impacts of such attacks. 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 lines.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. The Registrants’ employees, contractors, customers, and the general public could be exposed to a risk of injury due to the nature of the energy industry (All Registrants). Employees and contractors throughout the organization work in, and customers and the general public could be exposed to, potentially dangerous environments near the Registrants’ operations. As a result, employees, contractors, customers, and the general public are at some risk for serious injury, including loss of life. These risks include gas explosions, pole strikes, and electric contact cases. Natural disasters, war, acts and threats of terrorism, pandemic, and other significant events could negatively impact the Registrants' results of operations, ability to raise capital and future growth (All Registrants). The Utility Registrants' distribution and transmission infrastructures could be affected by natural disasters and extreme weather events, which could result in increased costs, including supply chain costs. An extreme weather event within the Utility Registrants’ service areas can also directly affect their capital assets, causing disruption in service to customers due to downed wires and poles or damage to other operating equipment. The impact that potential terrorist attacks could have on the industry and the Registrants is uncertain. The Registrants face a risk that their operations would be direct targets or indirect casualties of an act of terror. Any retaliatory military strikes or sustained military campaign could affect their operations in unpredictable ways, such as changes in insurance markets and disruptions of fuel supplies and markets, particularly oil. Furthermore, these assessmentscatastrophic events could compromise the physical or cybersecurity of the Registrants' facilities, which could adversely affect the Registrants' ability to manage their businesses effectively. Instability in the financial markets as a result of terrorism, war, natural disasters, pandemic, credit crises, recession, or other factors also could result in a decline in energy consumption or interruption of fuel or the supply chain. In addition, the implementation of security guidelines and measures has resulted in and is expected to continue to result in increased costs. The Registrants could be significantly affected by the outbreak of a pandemic. Exelon has plans in place to respond to a pandemic. However, depending on the severity of a pandemic and the resulting impacts to workforce and other resource availability, the ability to operate Exelon's transmission and distribution assets could be adversely affected. See "The Registrants' results were negatively affected by the impacts of COVID-19" above for additional information. In addition, Exelon maintains a level of insurance coverage consistent with industry practices against property, casualty and cybersecurity losses subject to unforeseen occurrences or catastrophic events that could damage or destroy assets or interrupt operations. However, there can be no assurance that the amount of insurance will be adequate to address such property and casualty losses. The Registrants’ businesses are capital intensive, and their assets could require significant expenditures to maintain and are subject to operational failure, which could result in potential liability (All Registrants). The Utility Registrants’ businesses are capital intensive and require significant investments in transmission and distribution infrastructure projects. Equipment, even if maintained in accordance with good utility practices, is subject to operational failure, including events that are beyond the Utility Registrants’ control, and could require significant expenditures to operate efficiently. The Registrants consolidated financial statements could be negatively affected if they were unable to effectively manage their capital projects or raise the necessary capital.
See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Liquidity and Capital Resources for additional information regarding the Registrants’ potential future capital expenditures. The Utility Registrants' respective ability to deliver electricity, their operating costs, and their capital expenditures could be negatively impacted by transmission congestion and failures of neighboring transmission systems (All Registrants). Demand for electricity within the Utility Registrants' service areas could stress available transmission capacity requiring alternative routing or curtailment of electricity usage. Also, insufficient availability of electric supply to meet customer demand could jeopardize the Utility Registrants' ability to comply with reliability standards and strain customer and regulatory agency relationships. As with all utilities, potential concerns over transmission capacity or generation facility retirements could result in PJM or FERC requiring the Utility Registrants to incur incrementalupgrade or expand their respective transmission systems through additional capital or operatingexpenditures. PJM’s systems and maintenance expendituresoperations are designed to ensure the reliable operation of the transmission grid and prevent the operations of one utility from having an adverse impact on the operations of the other utilities. However, service interruptions at other utilities may cause interruptions in the Utility Registrants’ service areas. The Registrants' performance could be negatively affected if they fail to attract and retain an appropriately qualified workforce (All Registrants). Certain events, such as the separation transaction, an employee strike, loss of employees, loss of contract resources due to a major event, and an aging workforce without appropriate replacements, could lead to operating challenges and increased costs for the Registrants. The challenges include lack of resources, loss of knowledge and a lengthy time period associated with skill development. In this case, costs, including costs for contractors to replace employees, productivity costs, and safety costs, could arise. The Registrants are particularly affected due to the specialized knowledge required of the technical and support employees for their transmission lines meet NERC standards. In 2010, NERC provided guidanceand distribution operations. The Registrants could make acquisitions or investments in new business initiatives and new markets, which may not be successful or achieve the intended financial results (All Registrants). The Utility Registrants face risks associated with their regulatory-mandated initiatives, such as smart grids and utility of the future. These risks include, but are not limited to, transmission owners that recommendedcost recovery, regulatory concerns, cybersecurity, and obsolescence of technology. Such initiatives may not be successful. Risks Related to the Separation (Exelon) The separation may not achieve some or all of the benefits anticipated by Exelon and, following the separation, Exelon's common stock price may underperform relative to Exelon's expectations. By separating the Utility Registrants perform assessmentsand Generation, Exelon created two publicly traded companies with the resources necessary to best serve customers and sustain long-term investment and operating excellence. The separate companies are expected to create value by having the strategic flexibility to focus on their unique customer, market and community priorities. However, the separation may not provide such results on the scope or scale that Exelon anticipates, and Exelon may not realize the anticipated benefits of the separation. Failure to do so could have a material adverse effect on Exelon's financial statements and its common stock price. In connection with the separation into two public companies, Exelon and Generation will indemnify each other for certain liabilities. If Exelon is required to pay under these indemnities to Generation, Exelon's financial results could be negatively impacted. The Generation indemnities may not be sufficient to hold Exelon harmless from the full amount of liabilities for which Generation will be allocated responsibility, and Generation may not be able to satisfy its indemnification obligations in the future.
Pursuant to the separation agreement and certain other agreements between Exelon and Generation, each party will agree to indemnify the other for certain liabilities, in each case for uncapped amounts. Indemnities that Exelon may be required to provide Generation are not subject to any cap, may be significant and could negatively impact its business. Third parties could also seek to hold Exelon responsible for any of the liabilities that Generation has agreed to retain. Any amounts Exelon is required to pay pursuant to these indemnification obligations and other liabilities could require Exelon to divert cash that would otherwise have been used in furtherance of its operating business. Further, the indemnities from Generation for Exelon's benefit may not be sufficient to protect Exelon against the full amount of such liabilities, and Generation may not be able to fully satisfy its indemnification obligations. Moreover, even if Exelon ultimately succeeds in recovering from Generation any amounts for which Exelon is held liable, Exelon may be temporarily required to bear these losses. Each of these risks could negatively affect Exelon's business, results of operations and financial condition. | | | | | | ITEM 1B. | UNRESOLVED STAFF COMMENTS |
All Registrants None.
Generation The following table presents Generation’s interests in net electric generating capacity by station at December 31, 2021: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Station(a) | | Location | | No. of Units | | Percent Owned(b) | | Primary Fuel Type | | Primary Dispatch Type(c) | | Net Generation Capacity (MW)(d) | | Midwest | | | | | | | | | | | | | | Braidwood | | Braidwood, IL | | 2 | | | | | Uranium | | Base-load | | 2,386 | | | Byron | | Byron, IL | | 2 | | | | | Uranium | | Base-load | | 2,347 | | (e) | LaSalle | | Seneca, IL | | 2 | | | | | Uranium | | Base-load | | 2,320 | | | Dresden | | Morris, IL | | 2 | | | | | Uranium | | Base-load | | 1,845 | | (e) | Quad Cities | | Cordova, IL | | 2 | | | 75 | | | Uranium | | Base-load | | 1,403 | | (f) | Clinton | | Clinton, IL | | 1 | | | | | Uranium | | Base-load | | 1,080 | | | Michigan Wind 2 | | Sanilac Co., MI | | 50 | | | 51 | | (g) | Wind | | Intermittent | | 46 | | (f) | Beebe | | Gratiot Co., MI | | 34 | | | 51 | | (g) | Wind | | Intermittent | | 42 | | (f) | Michigan Wind 1 | | Huron Co., MI | | 46 | | | 51 | | (g) | Wind | | Intermittent | | 35 | | (f) | Harvest 2 | | Huron Co., MI | | 33 | | | 51 | | (g) | Wind | | Intermittent | | 30 | | (f) | Harvest | | Huron Co., MI | | 32 | | | 51 | | (g) | Wind | | Intermittent | | 27 | | (f) | Beebe 1B | | Gratiot Co., MI | | 21 | | | 51 | | (g) | Wind | | Intermittent | | 26 | | (f) | Blue Breezes | | Faribault Co., MN | | 2 | | | | | Wind | | Intermittent | | 3 | | | CP Windfarm | | Faribault Co., MN | | 2 | | | 51 | | (g) | Wind | | Intermittent | | 2 | | (f) | Southeast Chicago | | Chicago, IL | | 8 | | | | | Gas | | Peaking | | 296 | | (h) | Clinton Battery Storage | | Blanchester, OH | | 1 | | | | | Energy Storage | | Peaking | | 10 | | | Total Midwest | | | | | | | | | | | | 11,898 | | | | | | | | | | | | | | | | | Mid-Atlantic | | | | | | | | | | | | | | Limerick | | Sanatoga, PA | | 2 | | | | | Uranium | | Base-load | | 2,317 | | | Calvert Cliffs | | Lusby, MD | | 2 | | | | | Uranium | | Base-load | | 1,789 | | | Peach Bottom | | Delta, PA | | 2 | | | 50 | | | Uranium | | Base-load | | 1,324 | | (f) | Salem | | Lower Alloways Creek Township, NJ | | 2 | | | 42.59 | | | Uranium | | Base-load | | 995 | | (f) | Conowingo | | Darlington, MD | | 11 | | | | | Hydroelectric | | Base-load | | 572 | | | Criterion | | Oakland, MD | | 28 | | | 51 | | (g) | Wind | | Intermittent | | 36 | | (f) | Fair Wind | | Garrett County, MD | | 12 | | | | | Wind | | Intermittent | | 30 | | | Fourmile Ridge | | Garrett County, MD | | 16 | | | 51 | | (g) | Wind | | Intermittent | | 20 | | (f) | Solar Horizons | | Emmitsburg, MD | | 1 | | | 51 | | (g) | Solar | | Intermittent | | 16 | | (f) | Solar New Jersey 3 | | Middle Township, NJ | | 4 | | | 51 | | (g) | Solar | | Intermittent | | 2 | | (f) | Muddy Run | | Drumore, PA | | 8 | | | | | Hydroelectric | | Intermediate | | 1,070 | | | Eddystone 3, 4 | | Eddystone, PA | | 2 | | | | | Oil/Gas | | Peaking | | 760 | | | Perryman | | Aberdeen, MD | | 5 | | | | | Oil/Gas | | Peaking | | 404 | | | Croydon | | West Bristol, PA | | 8 | | | | | Oil | | Peaking | | 391 | | | Handsome Lake | | Kennerdell, PA | | 5 | | | | | Gas | | Peaking | | 268 | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Station(a) | | Location | | No. of Units | | Percent Owned(b) | | Primary Fuel Type | | Primary Dispatch Type(c) | | Net Generation Capacity (MW)(d) | | Richmond | | Philadelphia, PA | | 2 | | | | | Oil | | Peaking | | 98 | | | Philadelphia Road | | Baltimore, MD | | 4 | | | | | Oil | | Peaking | | 61 | | | Eddystone | | Eddystone, PA | | 4 | | | | | Oil | | Peaking | | 60 | | | Delaware | | Philadelphia, PA | | 4 | | | | | Oil | | Peaking | | 56 | | | Southwark | | Philadelphia, PA | | 4 | | | | | Oil | | Peaking | | 52 | | | Falls | | Morrisville, PA | | 3 | | | | | Oil | | Peaking | | 51 | | | Moser | | Lower Pottsgrove Twp., PA | | 3 | | | | | Oil | | Peaking | | 51 | | | Chester | | Chester, PA | | 3 | | | | | Oil | | Peaking | | 39 | | | Schuylkill | | Philadelphia, PA | | 2 | | | | | Oil | | Peaking | | 30 | | | Salem | | Lower Alloways Creek Township, NJ | | 1 | | | 42.59 | | | Oil | | Peaking | | 16 | | (f) | Total Mid-Atlantic | | | | | | | | | | | | 10,508 | | | | | | | | | | | | | | | | | ERCOT | | | | | | | | | | | | | | Whitetail | | Webb County, TX | | 57 | | | 51 | | (g) | Wind | | Intermittent | | 47 | | (f) | Sendero | | Jim Hogg and Zapata County, TX | | 39 | | | 51 | | (g) | Wind | | Intermittent | | 40 | | (f) | Colorado Bend II | | Wharton, TX | | 3 | | | | | Gas | | Intermediate | | 1,143 | | | Wolf Hollow II | | Granbury, TX | | 3 | | | | | Gas | | Intermediate | | 1,115 | | | Handley 3 | | Fort Worth, TX | | 1 | | | | | Gas | | Intermediate | | 395 | | | Handley 4, 5 | | Fort Worth, TX | | 2 | | | | | Gas | | Peaking | | 870 | | | Total ERCOT | | | | | | | | | | | | 3,610 | | | | | | | | | | | | | | | | | New York | | | | | | | | | | | | | | Nine Mile Point | | Scriba, NY | | 2 | | | | (i) | Uranium | | Base-load | | 1,675 | | (f) | FitzPatrick | | Scriba, NY | | 1 | | | | | Uranium | | Base-load | | 842 | | | Ginna | | Ontario, NY | | 1 | | | | | Uranium | | Base-load | | 576 | | | Total New York | | | | | | | | | | | | 3,093 | | | | | | | | | | | | | | | | | Other | | | | | | | | | | | | | | Antelope Valley | | Lancaster, CA | | 1 | | | | | Solar | | Intermittent | | 242 | | | Bluestem | | Beaver County, OK | | 60 | | | 51 | | (g)(j) | Wind | | Intermittent | | 101 | | (f) | Shooting Star | | Kiowa County, KS | | 65 | | | 51 | | (g) | Wind | | Intermittent | | 53 | | (f) | Sacramento PV Energy | | Sacramento, CA | | 4 | | | 51 | | (g) | Solar | | Intermittent | | 30 | | (f) | Bluegrass Ridge | | King City, MO | | 27 | | | 51 | | (g) | Wind | | Intermittent | | 29 | | (f) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Station(a) | | Location | | No. of Units | | Percent Owned(b) | | Primary Fuel Type | | Primary Dispatch Type(c) | | Net Generation Capacity (MW)(d) | | Conception | | Barnard, MO | | 24 | | | 51 | | (g) | Wind | | Intermittent | | 26 | | (f) | Cow Branch | | Rock Port, MO | | 24 | | | 51 | | (g) | Wind | | Intermittent | | 26 | | (f) | Mountain Home | | Glenns Ferry, ID | | 20 | | | 51 | | (g) | Wind | | Intermittent | | 21 | | (f) | High Mesa | | Elmore Co., ID | | 19 | | | 51 | | (g) | Wind | | Intermittent | | 20 | | (f) | Echo 1 | | Echo, OR | | 21 | | | 50.49 | | (g) | Wind | | Intermittent | | 17 | | (f) | Cassia | | Buhl, ID | | 14 | | | 51 | | (g) | Wind | | Intermittent | | 15 | | (f) | Wildcat | | Lovington, NM | | 13 | | | 51 | | (g) | Wind | | Intermittent | | 14 | | (f) | Echo 2 | | Echo, OR | | 10 | | | 51 | | (g) | Wind | | Intermittent | | 10 | | (f) | Tuana Springs | | Hagerman, ID | | 8 | | | 51 | | (g) | Wind | | Intermittent | | 9 | | (f) | Greensburg | | Greensburg, KS | | 10 | | | 51 | | (g) | Wind | | Intermittent | | 6 | | (f) | Echo 3 | | Echo, OR | | 6 | | | 50.49 | | (g) | Wind | | Intermittent | | 5 | | (f) | Three Mile Canyon | | Boardman, OR | | 6 | | | 51 | | (g) | Wind | | Intermittent | | 5 | | (f) | Loess Hills | | Rock Port, MO | | 4 | | | | | Wind | | Intermittent | | 5 | | | Denver Airport Solar | | Denver, CO | | 1 | | | 51 | | (g) | Solar | | Intermittent | | 4 | | (f) | Mystic 8, 9 | | Charlestown, MA | | 6 | | | | | Gas | | Intermediate | | 1,417 | | (e) | Hillabee | | Alexander City, AL | | 3 | | | | | Gas | | Intermediate | | 753 | | | Wyman 4 | | Yarmouth, ME | | 1 | | | 5.9 | | | Oil | | Intermediate | | 34 | | (f) | West Medway II | | West Medway, MA | | 2 | | | | | Oil/Gas | | Peaking | | 189 | | | West Medway | | West Medway, MA | | 3 | | | | | Oil | | Peaking | | 124 | | | Grand Prairie | | Alberta, Canada | | 1 | | | | | Gas | | Peaking | | 105 | | | Framingham | | Framingham, MA | | 3 | | | | | Oil | | Peaking | | 31 | | | Total Other | | | | | | | | | | | | 3,291 | | | Total | | | | | | | | | | | | 32,400 | | |
__________ (a)All nuclear stations are boiling water reactors except Braidwood, Byron, Calvert Cliffs, Ginna, and Salem, which are pressurized water reactors. (b)100%, unless otherwise indicated. (c)Base-load units are plants that normally operate to take all or part of the minimum continuous load of a system and, consequently, produce electricity at an essentially constant rate. Intermittent units are plants with output controlled by the natural variability of the energy resource rather than dispatched based on system requirements. Intermediate units are plants that normally operate to take load of a system during the daytime higher load hours and, consequently, produce electricity by cycling on and off daily. Peaking units consist of lower-efficiency, quick response steam units, gas turbines and diesels normally used during the maximum load periods. (d)For nuclear stations, capacity reflects the annual mean rating. Fossil stations and wind and solar facilities reflect a summer rating. (e)On August 9, 2020, Generation announced it would permanently cease generation operations at Byron and Dresden nuclear facilities in 2021 and Mystic Unit 8 and 9 in 2024. On September 15, 2021, Generation reversed its previous decision to retire Byron and Dresden. See Note 7 — Early Plant Retirements of the Combined Notes to the Consolidated Financial Statements for additional information. (f)Net generation capacity is stated at proportionate ownership share. (g)Reflects the prior sale of 49% of CRP to a third party. See Note 23 — Variable Interest Entities of the Combined Notes to Consolidated Financial Statements for additional information. (h)Generation has deactivated the site and is evaluating for potential return of service or retirement beyond 2023. (i)Generation wholly owns Nine Mile Point Unit 1 and has an 82% undivided ownership interest in Nine Mile Point Unit 2. (j)CRP owns 100% of the Class A membership interests and a tax equity investor owns 100% of the Class B membership interests of the entity that owns the Bluestem generating assets. The net generation capability available for operation at any time may be less due to regulatory restrictions, transmission congestion, fuel restrictions, efficiency of cooling facilities, level of water supplies, or generating
units being temporarily out of service for inspection, maintenance, refueling, repairs, or modifications required by regulatory authorities. Generation maintains property insurance against loss or damage to its principal plants and properties by fire or other perils, subject to certain exceptions. For additional information regarding nuclear insurance of generating facilities, see ITEM 1. BUSINESS — Generation. For its insured losses, Generation is self-insured to the extent that any losses are within the policy deductible or exceed the amount of insurance maintained. Any such losses could have a material adverse effect on Generation’s consolidated financial condition or results of operations.
The Utility Registrants The Utility Registrants' electric substations and a portion of their transmission lines.rights are located on property that they own. A significant portion of their electric transmission and distribution facilities are located above or underneath highways, streets, other public places, or property that others own. The Utility Registrants believe that they have satisfactory rights to use those places or property in the form of permits, grants, easements, licenses, and franchise rights; however, they have not necessarily undertaken to examine the underlying title to the land upon which the rights rest. Transmission and Distribution The Utility Registrants’ high voltage electric transmission lines owned and in service at December 31, 2021 were as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Voltage | Circuit Miles | (Volts) | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE | 765,000 | 90 | | — | | — | | — | | — | | — | 500,000(a) | — | | 188 | | 216 | | 109 | | 16 | | — | 345,000 | 2,676 | | — | | — | | — | | — | | — | 230,000 | — | | 550 | | 358 | | 770 | | 472 | | 274 | 138,000 | 2,246 | | 135 | | 55 | | 61 | | 586 | | 214 | 115,000 | — | | — | | 700 | | 25 | | — | | — | 69,000 | — | | 177 | | — | | — | | 567 | | 667 |
___________ (a) In addition, PECO, DPL, and ACE have an ownership interest located in Delaware and New Jersey. See Note 9 - Jointly Owned Electric Utility Plant of the Combined Notes to the Consolidated Financial Statements for additional information. The Utility Registrants' electric distribution system includes the following number of circuit miles of overhead and underground lines: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Circuit Miles | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE | Overhead | 35,387 | | 12,981 | | 9,164 | | 4,127 | | 6,006 | | 7,364 | Underground | 32,498 | | 9,555 | | 17,796 | | 7,162 | | 6,427 | | 2,951 |
Gas The following table presents PECO’s, BGE’s, and DPL’s natural gas pipeline miles at December 31, 2021: | | | | | | | | | | | | | | | | | | | PECO | | BGE | | DPL | Transmission(a) | 9 | | 152 | | 8 | Distribution | 6,956 | | 7,482 | | 2,166 | Service piping | 6,479 | | 6,407 | | 1,473 | Total | 13,444 | | 14,041 | | 3,647 |
___________ (a) DPL has a 10% undivided interest in approximately 8 miles of natural gas transmission mains located in Delaware which are used by DPL for its natural gas operations and by 90% owner for distribution of natural gas to its electric generating facilities.
The following table presents PECO’s, BGE’s, and DPL’s natural gas facilities: | | | | | | | | | | | | | | | | | | | | | | | | Registrant | Facility | | Location | | Storage Capacity (mmcf) | | Send-out or Peaking Capacity (mmcf/day) | PECO | LNG Facility | | West Conshohocken, PA | | 1,200 | | 160 | PECO | Propane Air Plant | | Chester, PA | | 105 | | 25 | BGE | LNG Facility | | Baltimore, MD | | 1,056 | | 332 | BGE | Propane Air Plant | | Baltimore, MD | | 550 | | 85 | DPL | LNG Facility | | Wilmington, DE | | 250 | | 25 |
PECO, BGE, and DPL also own 30, 30, and 10 natural gas city gate stations and direct pipeline customer delivery points at various locations throughout their gas service territory, respectively. First Mortgage and Insurance The principal properties of ComEd, PECO, and BGE submitted their final bi-annual reports to NERC in January 2014. ComEd and PECO will be incurring incremental capital expenditures associated with this guidance following the completion of the assessments. Specific projects and expenditures are identified as the assessments are completed. ComEd’s and PECO’s forecasted 2020 capital expenditures above reflect capital spending for remediation to be completed through 2020. BGE,PEPCO, DPL, and ACE are complete withsubject to the lien of their assessmentsrespective Mortgages under which their respective First Mortgage Bonds are issued. See Note 17 — Debt and Pepco has substantially completed its assessment and thus do not expect significant capital expenditures relatedCredit Agreements of the Combined Notes to this guidance in 2020.Consolidated Financial Statements for additional information.
The Utility Registrants anticipatemaintain property insurance against loss or damage to their properties by fire or other perils, subject to certain exceptions. For their insured losses, the Utility Registrants are self-insured to the extent that any losses are within the policy deductible or exceed the amount of insurance maintained. Any such losses could have a material adverse effect in the consolidated financial condition or results of operations of the Utility Registrants.
Exelon Security Measures The Registrants have initiated and work to maintain security measures. On a continuing basis, the Registrants evaluate enhanced security measures at certain critical locations, enhanced response and recovery plans, long-term design changes, and redundancy measures. Additionally, the energy industry has strategic relationships with governmental authorities to ensure that emergency plans are in place and critical infrastructure vulnerabilities are addressed in order to maintain the reliability of the country’s energy systems.
All Registrants 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 Note 3 — Regulatory Matters and Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements. Such descriptions are incorporated herein by these references.
| | | | | | ITEM 4. | MINE SAFETY DISCLOSURES | Not Applicable
PART II (Dollars in millions except per share data, unless otherwise noted) | | | | | | ITEM 5. | MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES |
Exelon Exelon’s common stock is listed on the Nasdaq (trading symbol: EXC). As of January 31, 2022, there were 980,136,968 shares of common stock outstanding and approximately 85,423 record holders of common stock. Stock Performance Graph The performance graph below illustrates a five-year comparison of cumulative total returns based on an initial investment of $100 in Exelon common stock, as compared with the S&P 500 Stock Index and the S&P Utility Index, for the period 2017 through 2021. This performance chart assumes: •$100 invested on December 31, 2016 in Exelon common stock, the S&P 500 Stock Index, and the S&P Utility Index; and •All dividends are reinvested.
| | | | | | | | | | | | | | | | | | | | | Value of Investment at December 31, | | 2016 | 2017 | 2018 | 2019 | 2020 | 2021 | Exelon Corporation | $100 | $115.05 | $136.13 | $141.96 | $136.44 | $192.94 | S&P 500 | $100 | $121.83 | $116.49 | $153.17 | $181.35 | $233.41 | S&P Utilities | $100 | $112.11 | $116.71 | $147.46 | $148.18 | $174.36 |
ComEd As of January 31, 2022, there were 127,021,391 outstanding shares of common stock, $12.50 par value, of ComEd, of which 127,002,904 shares were indirectly held by Exelon. At January 31, 2022, in addition to Exelon, there were 285 record holders of ComEd common stock. There is no established market for shares of the common stock of ComEd. PECO As of January 31, 2022, there were 170,478,507 outstanding shares of common stock, without par value, of PECO, all of which were indirectly held by Exelon. BGE As of January 31, 2022, there were 1,000 outstanding shares of common stock, without par value, of BGE, all of which were indirectly held by Exelon. PHI As of January 31, 2022, Exelon indirectly held the entire membership interest in PHI. Pepco As of January 31, 2022, there were 100 outstanding shares of common stock, $0.01 par value, of Pepco, all of which were indirectly held by Exelon. DPL As of January 31, 2022, there were 1,000 outstanding shares of common stock, $2.25 par value, of DPL, all of which were indirectly held by Exelon. ACE As of January 31, 2022, there were 8,546,017 outstanding shares of common stock, $3.00 par value, of ACE, all of which were indirectly held by Exelon. All Registrants Dividends Under applicable Federal law, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE can pay dividends only from retained, undistributed or current earnings. A significant loss recorded at, ComEd, PECO, BGE, PHI, Pepco, DPL, or ACE may limit the dividends that these companies can distribute to Exelon. ComEd has agreed in connection with a financing arranged through ComEd Financing III that ComEd will not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debt securities issued to ComEd Financing III; (2) it defaults on its guarantee of the payment of distributions on the preferred trust securities of ComEd Financing III; or (3) an event of default occurs under the Indenture under which the subordinated debt securities are issued. No such event has occurred.
PECO has agreed in connection with financings arranged through PEC L.P. and PECO Trust IV that PECO will not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debentures which were issued to PEC L.P. or PECO Trust IV; (2) it defaults on its guarantee of the payment of distributions on the Series D Preferred Securities of PEC L.P. or the preferred trust securities of PECO Trust IV; or (3) an event of default occurs under the Indenture under which the subordinated debentures are issued. No such event has occurred. BGE is subject to restrictions established by the MDPSC that prohibit BGE from paying a dividend on its common shares if (a) after the dividend payment, BGE’s equity ratio would be below 48% as calculated pursuant to the MDPSC’s ratemaking precedents or (b) BGE’s senior unsecured credit rating is rated by two of the three major credit rating agencies below investment grade. No such event has occurred. Pepco is subject to certain dividend restrictions established by settlements approved in Maryland and the District of Columbia. Pepco is prohibited from paying a dividend on its common shares if (a) after the dividend payment, Pepco's equity ratio would be below 48% as equity levels are calculated under the ratemaking precedents of the MDPSC and DCPSC or (b) Pepco’s senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. No such event has occurred. DPL is subject to certain dividend restrictions established by settlements approved in Delaware and Maryland. DPL is prohibited from paying a dividend on its common shares if (a) after the dividend payment, DPL's equity ratio would be below 48% as equity levels are calculated under the ratemaking precedents of the DEPSC and MDPSC or (b) DPL’s senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. No such event has occurred. ACE is subject to certain dividend restrictions established by settlements approved in New Jersey. ACE is prohibited from paying a dividend on its common shares if (a) after the dividend payment, ACE's equity ratio would be below 48% as equity levels are calculated under the ratemaking precedents of the NJBPU or (b) ACE's senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. ACE is also subject to a dividend restriction which requires ACE to obtain the prior approval of the NJBPU before dividends can be paid if its equity as a percent of its total capitalization, excluding securitization debt, falls below 30%. No such events have occurred. Exelon’s Board of Directors approved an updated dividend policy for 2022. The 2022 quarterly dividend will be $0.3375 per share. At December 31, 2021, Exelon had retained earnings of $16,942 million, ComEd’s retained earnings of $1,691 million consisting of retained earnings appropriated for future dividends of $3,330 million, partially offset by $1,639 million of unappropriated accumulated deficits, PECO’s retained earnings of $1,684 million, BGE’s retained earnings of $1,995 million, and PHI's undistributed losses of $210 million. The following table sets forth Exelon’s quarterly cash dividends per share paid during 2021 and 2020: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2021 | | 2020 | (per share) | Fourth Quarter | | Third Quarter | | Second Quarter | | First Quarter | | Fourth Quarter | | Third Quarter | | Second Quarter | | First Quarter | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exelon | $ | 0.3825 | | | $ | 0.3825 | | | $ | 0.3825 | | | $ | 0.3825 | | | $ | 0.3825 | | | $ | 0.3825 | | | $ | 0.3825 | | | $ | 0.3825 | |
The following table sets forth PHI's quarterly distributions and ComEd’s, PECO’s, BGE's, Pepco's, DPL's, and ACE's quarterly common dividend payments: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2021 | | 2020 | (in millions) | 4th Quarter | | 3rd Quarter | | 2nd Quarter | | 1st Quarter | | 4th Quarter | | 3rd Quarter | | 2nd Quarter | | 1st Quarter | | | | | | | | | | | | | | | | | ComEd | 127 | | | 127 | | | 126 | | | 127 | | | 126 | | | 124 | | | 124 | | | 125 | | PECO | 85 | | | 85 | | | 84 | | | 85 | | | 85 | | | 85 | | | 85 | | | 85 | | BGE | 73 | | | 73 | | | 72 | | | 74 | | | 60 | | | 62 | | | 62 | | | 62 | | PHI | 98 | | | 191 | | | 333 | | | 81 | | | 102 | | | 183 | | | 134 | | | 134 | | Pepco | 47 | | | 98 | | | 95 | | | 28 | | | 58 | | | 73 | | | 73 | | | 28 | | DPL | 41 | | | 43 | | | 23 | | | 40 | | | 42 | | | 33 | | | 14 | | | 52 | | ACE | 8 | | | 51 | | | 215 | | | 14 | | | 3 | | | 76 | | | 12 | | | 23 | |
First Quarter 2022 Dividend On February 8, 2022, Exelon's Board of Directors declared a regular quarterly dividend of $0.3375 per share on Exelon’s common stock for the first quarter of 2022. The dividend is payable on Monday, March 10, 2022, to shareholders of record of Exelon as of 5 p.m. Eastern time on Friday, February 25, 2022.
| | | | | | ITEM 6. | SELECTED FINANCIAL DATA |
Not Applicable
| | | | | | Item 7. | 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 As of December 31, 2021, Exelon was 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 eleven 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 seven separate operating subsidiary registrants, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE and its subsidiary Generation. The following combined Management’s Discussion and Analysis of Financial Condition and Results of Operations summarizes results for the year ended December 31, 2021 compared to the year ended December 31, 2020, and is separately filed by Exelon, 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. For discussion of the year ended December 31, 2020 compared to the year ended December 31, 2019, refer to ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS in the 2020 Form 10-K, which was filed with the SEC on February 24, 2021. COVID-19. The Registrants have taken steps to mitigate the potential risks posed by the global outbreak (pandemic) of COVID-19. The Registrants provide a critical service to our customers which means that it is paramount that we keep our employees who operate our businesses safe and minimize unnecessary risk of exposure to the virus by taking extra precautions for employees who work in the field and in our facilities. The Registrants have implemented work from home policies where appropriate, and imposed travel limitations on employees. The Registrants continue to implement strong physical and cyber-security measures to ensure that our systems remain functional in order to both serve our operational needs with a remote workforce and keep them running to ensure uninterrupted service to our customers. There were no changes in internal control over financial reporting as a result of COVID-19 that materially affected, or are reasonably likely to materially affect, any of the Registrants’ internal control over financial reporting. See ITEM 9A. CONTROLS AND PROCEDURES for additional information. Unfavorable economic conditions due to COVID-19 resulted in an estimated reduction to Exelon’s Net income of approximately $245 million for the year ended December 31, 2020. The impact was not material for the year ended December 31, 2021. To offset the unfavorable impacts from COVID-19, Exelon identified approximately $250 million in cost savings in 2020. The cost savings achieved in 2020 were higher than originally anticipated. The Registrants assessed long-lived assets, goodwill, and investments for recoverability and there were no material impairment charges recorded in 2020 or 2021 as a result of COVID-19. See Note 12 — Asset Impairments of the Combined Notes to Consolidated Financial Statements for additional information related to other impairment assessments. The Registrants will continue to monitor developments affecting their workforce, customers, and suppliers and will take additional precautions that they determine to be necessary in order to mitigate the impacts. The Registrants cannot predict the full extent of the impacts of COVID-19, which will depend on, among other things, the rate, and public perceptions of the effectiveness, of vaccinations and rate of resumption of business activity.
Financial Results of Operations GAAP Results of Operations. The following table sets forth Exelon's GAAP consolidated Net Income attributable to common shareholders by Registrant or subsidiary for the year ended December 31, 2021 compared to the same period in 2020. For additional information regarding the financial results for the years ended December 31, 2021and2020 see the discussions of Results of Operations by Registrant or subsidiary. | | | | | | | | | | | | | | | | | | | 2021 | | 2020 | | (Unfavorable) Favorable Variance | Exelon | $ | 1,706 | | | $ | 1,963 | | | $ | (257) | | | | | | | | ComEd | 742 | | | 438 | | | 304 | | PECO | 504 | | | 447 | | | 57 | | BGE | 408 | | | 349 | | | 59 | | PHI | 561 | | | 495 | | | 66 | | Pepco | 296 | | | 266 | | | 30 | | DPL | 128 | | | 125 | | | 3 | | ACE | 146 | | | 112 | | | 34 | | Generation | (205) | | | 589 | | | (794) | | Other(a) | (304) | | | (355) | | | 51 | |
__________ (a)Primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities, and other financing and investing activities. Year Ended December 31, 2021 Compared to Year Ended December 31, 2020. Net income attributable to common shareholdersdecreased by $257 million and diluted earnings per average common share decreased to $1.74 in 2021 from $2.01 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; •Higher net unrealized and realized losses on equity investments; and •The absence of prior year one-time tax settlements. The decreases were partially offset by;
•Higher electric distribution earnings from higher rate base and higher allowed ROE due to an increase in treasury rates at ComEd; •The favorable impacts of the multi-year plan at BGE and Pepco and regulatory rate increases at DPL and ACE; •Favorable weather conditions at PECO and DPL's Delaware service territory; •Favorable volume at PECO and ACE; •Lower storm costs at PECO and DPL due to the absence of the June 2020 and August 2020 storms, respectively; •Lower operating and maintenance expense at ComEd due to the payments that ComEd made in 2020 under the Deferred Prosecution Agreement; •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; •Favorable sales and hedges of excess emission credits; •Favorable commodity prices on fuel hedges; •Lower nuclear fuel costs due to accelerated amortization of nuclear fuel and lower prices; and •Higher New York ZEC revenues due to higher generation and an increase in ZEC prices. 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 table provides a reconciliation between Net income attributable to common shareholders as determined in accordance with GAAP and Adjusted (non-GAAP) operating earnings for the year ended December 31, 2021 as compared to 2020: | | | | | | | | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | | 2021 | | 2020 | (In millions, except per share data) | | | Earnings per Diluted Share | | | | Earnings per Diluted Share | Net Income Attributable to Common Shareholders | $ | 1,706 | | | $ | 1.74 | | | $ | 1,963 | | | $ | 2.01 | | Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $145 and $73, respectively) | (421) | | | (0.43) | | | (213) | | | (0.22) | | Unrealized Gains Related to NDT Fund Investments (net of taxes of $141 and $278, respectively)(a) | (139) | | | (0.14) | | | (256) | | | (0.26) | | | | | | | | | | Asset Impairments (net of taxes of $136 and $135, respectively)(b) | 405 | | | 0.41 | | | 396 | | | 0.41 | | Plant Retirements and Divestitures (net of taxes of $290 and $244, respectively)(c) | 865 | | | 0.88 | | | 718 | | | 0.74 | | Cost Management Program (net of taxes of $2 and $14, respectively)(d) | 9 | | | 0.01 | | | 45 | | | 0.05 | | | | | | | | | | Asset Retirement Obligation (net of taxes of $12 and $16, respectively)(e) | (35) | | | (0.04) | | | 48 | | | 0.05 | | Change in Environmental Liabilities (net of taxes of $3 and $6, respectively) | 9 | | | 0.01 | | | 18 | | | 0.02 | | COVID-19 Direct Costs (net of taxes of $13 and $19, respectively)(f) | 36 | | | 0.04 | | | 50 | | | 0.05 | | Deferred Prosecution Agreement Payments (net of taxes of $0)(g) | — | | | — | | | 200 | | | 0.20 | | Acquisition Related Costs (net of taxes of $5 and $1, respectively)(h) | 15 | | | 0.02 | | | 4 | | | — | | ERP System Implementation Costs (net of taxes of $4 and $1, respectively)(i) | 13 | | | 0.01 | | | 3 | | | — | | Separation Costs (net of taxes of $31)(j) | 90 | | | 0.09 | | | — | | | — | | Costs Related to Suspension of Contractual Offset (net of taxes of $45)(k) | 148 | | | 0.15 | | | — | | | — | | Income Tax-Related Adjustments (entire amount represents tax expense)(l) | 47 | | | 0.05 | | | 71 | | | 0.07 | | Noncontrolling Interests (net of taxes of $2 and $19, respectively)(m) | 16 | | | 0.02 | | | 103 | | | 0.11 | | Adjusted (non-GAAP) Operating Earnings | $ | 2,764 | | | $ | 2.82 | | | $ | 3,149 | | | $ | 3.22 | |
__________ Note: Amounts may not sum due to rounding. Unless otherwise noted, the income tax impact of each reconciling item between GAAP Net Income 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 funds, the marginal statutory income tax rates for 2021 and 2020 ranged from 25.0% 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 funds were 50.4% and 52.1% for the years ended December 31, 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 of 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 of the New England asset group in the third quarter of 2020 at Generation. (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)For Generation, reflects an adjustment to the nuclear asset obligation for the Non-Regulatory Agreement Units resulting from the annual update in the third quarter of 2021 and fourth quarter of 2020, respectively. (f)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. (g)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. (h)Reflects costs related to the acquisition of EDF's interest in CENG, which was completed in the third quarter of 2021. (i)Reflects costs related to a multi-year Enterprise Resource Program (ERP) system implementation. (j)Represents costs related to the 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. (k)Decommissioning-related activities for 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 consolidated statements of operations. These costs reflect the 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. (l)In 2021, primarily reflects the recognition of a valuation allowance against a deferred tax asset associated with Delaware net operating loss carryforwards due to a change in Delaware tax law. In 2021 and 2020, also 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 2021 Transactions and Developments 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 customers and sustain long-term investment and operating excellence ("the separation"). The separation gives each company the financial and strategic independence to focus on its specific customer needs, while executing its core business strategy. Exelon completed the separation on February 1, 2022. The new publicly traded company is Constellation Energy Corporation. See Note 26 — Separation of the Combined Notes to Consolidated Financial Statements for additional information. In connection with the separation, Exelon incurred transaction costs of $122 million on a pre-tax basis for the year ended December 31, 2021, which are recorded in Operating and maintenance expense. Exelon expects to incur incremental transaction costs of approximately $90 million in 2022. These costs are excluded from Adjusted (non-GAAP) Operating Earnings. The transaction costs are primarily comprised of system-related costs, third-party costs paid to advisors, consultants, lawyers, and other experts assisting in the separation, and employee-related severance costs. 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. 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 Note 2 — Mergers, Acquisitions, and Dispositions and Note 17 — 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 authorized 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 participated in the CMC procurement process and were awarded contracts that commit each plant to operate through May 31, 2027. Pursuant to these contracts, ComEd will procure CMCs based upon the number of MWhs produced annually by each plant, subject to minimum performance requirements. ComEd is required to purchase CMCs pursuant to these contracts 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 the 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 of the Combined Notes to Consolidated Financial Statements 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 of the Combined Notes to Consolidated Financial Statements for additional information and other features of the Clean Energy Law. Early Retirement of Generation Facilities In August 2020, Generation announced the intention 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 recognized a $500 million pre-tax impairment for the New England asset group along with certain one-time charges in the third and fourth quarters of 2020 in addition to 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. 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. Exelon recorded pre-tax charges of $53 million and $140 million, in the second and third quarters of 2021, respectively, for decommissioning-related activities that were not offset for the Byron units due to the inability to recognize a regulatory asset at ComEd. On September 15, 2021, Generation reversed the previous decision to early retire Byron and Dresden and the expected economic useful life for both facilities was updated 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 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. All of the charges were excluded from Exelon's Adjusted (non-GAAP) Operating Earnings.
Exelon recognized pre-tax expenses for Byron, Dresden, and Mystic Units 8 and 9 of $1,458 million for the year ended December 31, 2021, primarily due to accelerated depreciation and amortization of plant assets, partially offset by the reversal of one-time charges for Byron and Dresden. See Note 7 — Early Plant Retirements, Note 10 — Asset Retirement Obligations, and Note 12 — 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 Net income for the year ended December 31, 2021 arising from these market and weather conditions was a reduction of approximately $800 million. The ultimate impact to Exelon’s consolidated financial statements may be affected by a number of factors, including the impacts of customer and counterparty defaults and recoveries, any additional solutions to address the financial challenges caused by the event, and related litigation and contract disputes. See Note 3 — Regulatory Matters and Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information. To offset a portion of the unfavorable impacts, Exelon identified between $410 million and $490 million of enhanced revenue opportunities, deferral of selected non-essential maintenance, and primarily one-time cost savings, primarily at Generation, which was achieved in 2021. Agreement for the Sale of a Generation Biomass Facility On April 28, 2021, 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 recorded a pre-tax impairment charge of $140 million which is excluded from Exelon’s Adjusted (non-GAAP) Operating Earnings. The sale was completed on June 30, 2021 for a net purchase price of $36 million. Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information. Utility Distribution 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. 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 | | April 16, 2021 | | Electric | | 51 | | | 46 | | | 7.36 | % | | December 1, 2021 | | January 1, 2022 | PECO - Pennsylvania | | September 30, 2020 | | Natural Gas | | 69 | | | 29 | | | 10.24 | % | | June 22, 2021 | | July 1, 2021 | | 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 - 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 |
Pending Distribution Base Rate Case Proceedings | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Registrant/Jurisdiction | | Filing Date | | Service | | Requested Revenue Requirement Increase | | Requested ROE | | Expected Approval Timing | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | DPL - Delaware | | January 14, 2022 | | Natural Gas | | $ | 14 | | | 10.30 | % | | First quarter of 2023 | DPL - Maryland | | September 1, 2021 (amended December 23, 2021) | | Electric | | 27 | | | 10.10 | % | | First quarter of 2022 | | | | | | | | | | | |
Transmission Formula Rates The following total increases/(decreases) were included in the Utility Registrants' 2021 annual electric transmission formula rate updates. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Registrant | | Initial Revenue Requirement Increase (Decrease) | | Annual Reconciliation Increase | | Total Revenue Requirement Increase | | Allowed Return on Rate Base | | Allowed ROE | 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 | % |
Other Key Business Drivers and Management Strategies
Utility Rates and Rate Proceedings The Utility Registrants file 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 results of operations, cash flows, and financial positions. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on these regulatory proceedings. 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 the 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.
Critical Accounting Policies and Estimates The preparation of financial statements in conformity with GAAP requires that management apply accounting policies and make estimates and assumptions that affect results of operations and the amounts of assets and liabilities reported in the financial statements. Management believes that the accounting policies described below require significant judgment in their application or incorporate estimates and assumptions that are inherently uncertain and that may change in subsequent periods. Additional information on the application of these accounting policies can be found in the Combined Notes to Consolidated Financial Statements. Nuclear Decommissioning Asset Retirement Obligations (Exelon) Exelon recorded AROs associated with decommissioning Generation's nuclear units of $12.7 billion at December 31, 2021. The authoritative guidance requires that Generation estimate its obligation for the future decommissioning of its nuclear generating plants. To estimate that liability, Generation uses an internally-developed, probability-weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple decommissioning outcome scenarios. As a result of nuclear plant retirements in the industry, in recent years, nuclear operators and third-party service providers are obtaining more information about costs associated with decommissioning activities. At the same time, regulators are gaining more information about decommissioning activities which could result in changes to existing decommissioning requirements. In addition, as more nuclear plants are retired, it is possible that technological advances will be identified that could create efficiencies and lead to a reduction in decommissioning costs. The amount of NDT funds could also impact the timing of the decommissioning activities. Additionally, certain factors such as changes in regulatory requirements during plant operations or the profitability of a nuclear plant could impact the timing of plant retirements. The nuclear decommissioning obligation is adjusted on a regular basis due to the passage of time and revisions to the key assumptions for the expected timing and/or estimated amounts of the future undiscounted cash flows required to decommission the nuclear plants, based upon the following methodologies and significant estimates and assumptions: Decommissioning Cost Studies. Generation uses unit-by-unit decommissioning cost studies to provide a marketplace assessment of the expected costs (in current year dollars) and timing of decommissioning activities, which are validated by comparison to current decommissioning projects within the industry and other estimates. Decommissioning cost studies are updated, on a rotational basis, for each of Generation’s nuclear units at least every five years, unless circumstances warrant more frequent updates. As part of the annual cost study update process, Generation evaluates newly assumed costs or substantive changes in previously assumed costs to determine if the cost estimate impacts are sufficiently material to warrant application of the updated estimates to the AROs across the nuclear fleet outside of the normal five-year rotating cost study update cycle. Cost Escalation Factors. Generation uses cost escalation factors to escalate the decommissioning costs from the decommissioning cost studies discussed above through the assumed decommissioning period for each of the units. Cost escalation studies, updated on an annual basis, are used to determine escalation factors, and are
based on inflation indices for labor, equipment and materials, energy, LLRW disposal, and other costs. All the nuclear AROs are adjusted each year for updated cost escalation factors. Probabilistic Cash Flow Models. Generation’s probabilistic cash flow models include the assignment of probabilities to various scenarios for decommissioning cost levels, decommissioning approaches, and timing of plant shutdown on a unit-by-unit basis. Probabilities assigned to cost levels include an assessment of the likelihood of costs 20% higher (high-cost scenario) or 15% lower (low-cost scenario) than the base cost scenario. The assumed decommissioning scenarios generally include the following three alternatives: (1) DECON, which assumes major decommissioning activities begin shortly after the cessation of operation, (2) Shortened SAFSTOR, which generally assumes a 30-year delay prior to onset of major decommissioning activities, and (3) SAFSTOR, which assumes the nuclear facility is placed and maintained in such condition during decommissioning so that the nuclear facility can be safely stored and subsequently decontaminated within 60 years after cessation of operations. In each decommissioning scenario, spent fuel is transferred to dry cask storage as soon as possible until DOE acceptance for disposal. The actual decommissioning approach selected once a nuclear facility is shutdown will be determined by Generation at the time of shutdown and may be influenced by multiple factors including the funding status of the NDT funds at the time of shutdown and regulatory or other commitments. The assumed plant shutdown timing scenarios include the following four alternatives: (1) the probability of operating through the original 40-year nuclear license term, (2) the probability of operating through an initial 20-year license renewal term, (3) the probability of a second, 20-year license renewal term, and (4) the probability of early plant retirement for certain sites due to changing market conditions and regulatory environments. As power market and regulatory environment developments occur, Generation evaluates and incorporates, as necessary, the impacts of such developments into its nuclear ARO assumptions and estimates. Generation’s probabilistic cash flow models also include an assessment of the timing of DOE acceptance of SNF for disposal. Generation currently assumes DOE will begin accepting SNF from the industry in 2035. The SNF acceptance date assumption is based on management’s estimates of the amount of time required for DOE to select a site location and develop the necessary infrastructure for long-term SNF storage. For additional information regarding SNF, see Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements. Discount Rates. The probability-weighted estimated future cash flows for the various assumed scenarios are discounted using credit-adjusted, risk-free rates (CARFR). Generation initially recognizes an ARO at fair value and subsequently adjusts it for changes to estimated costs, timing of future cash flows and modifications to decommissioning assumptions. The ARO is not required or permitted to be re-measured for changes in the CARFR that occur in isolation. Increases in the ARO due to upward revisions in estimated undiscounted cash flows are considered new obligations and are measured using a current CARFR as the increase creates a new cost layer within the ARO. Any decrease in the estimated undiscounted future cash flows relating to the ARO are treated as a modification of an existing ARO cost layer and, therefore, are measured using the average historical CARFR rates used in creating the initial ARO cost layers. If all of Generation's future nominal cash flows associated with the ARO were to be discounted at the current prevailing CARFR, the obligation would increase from approximately $12.7 billion to approximately $16.0 billion. The following table illustrates the significant impact that changes in the CARFR, when combined with changes in projected amounts and expected timing of cash flows, can have on the valuation of the ARO: | | | | | | Change in the CARFR applied to the annual ARO update | (Decrease) Increase to ARO as of December 31, 2021 | 2020 CARFR rather than the 2021 CARFR | $ | (490) | | 2021 CARFR increased by 50 basis points | (600) | | 2021 CARFR decreased by 50 basis points | 750 | |
ARO Sensitivities. Changes in the assumptions underlying the ARO could materially affect the decommissioning obligation. The impact of a change in any one of these assumptions to the ARO is highly dependent on how the other assumptions may correspondingly change. The following table illustrates the effects of changing certain ARO assumptions while holding all other assumptions constant: | | | | | | Change in ARO Assumption | Increase to ARO as of December 31, 2021 | Cost escalation studies | | Uniform increase in escalation rates of 50 basis points | $ | 2,900 | | Probabilistic cash flow models | | Increase the estimated costs to decommission the nuclear plants by 10 percent | 1,110 | | Increase the likelihood of the DECON scenario by 10 percent and decrease the likelihood of the SAFSTOR scenario by 10 percent(a) | 480 | | Shorten each unit's probability weighted operating life assumption by 10 percent(b) | 1,570 | | Extend the estimated date for DOE acceptance of SNF to 2040 | 290 | |
__________ (a)Excludes any sites in which management has committed to a specific decommissioning approach. (b)Excludes any retired sites. See Note 1 — Significant Accounting Policies and Note 10 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information regarding accounting for nuclear AROs. Goodwill (Exelon, ComEd, and PHI) As of December 31, 2021, Exelon’s $6.7 billion carrying amount of goodwill consists primarily of $2.6 billion at ComEd and $4 billion at PHI. These entities are required to perform an assessment for possible impairment of their goodwill at least annually or more frequently if an event occurs or circumstances change that would more likely than not reduce the fair value of the reporting units below their carrying amount. A reporting unit is an operating segment or one level below an operating segment (known as a component) and is the level at which goodwill is assessed for impairment. ComEd has a single operating segment and reporting unit. PHI’s operating segments and reporting units are Pepco, DPL, and ACE. See Note 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for additional information. Exelon's and ComEd’s goodwill has been assigned entirely to the ComEd reporting unit. Exelon's and PHI’s goodwill has been assigned to the Pepco, DPL, and ACE reporting units in the amounts of $2.1 billion, $1.4 billion, and $0.5 billion, respectively. See Note 13 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information. Entities assessing goodwill for impairment have the option of first performing a qualitative assessment to determine whether a quantitative assessment is necessary. As part of the qualitative assessments, Exelon, ComEd, and PHI evaluate, among other things, management's best estimate of projected operating and capital cash flows for their businesses, outcomes of recent regulatory proceedings, changes in certain market conditions, including the discount rate and regulated utility peer EBITDA multiples, and the passing margin from their last quantitative assessments performed. Application of the goodwill impairment assessment requires management judgment, including the identification of reporting units and determining the fair value of the reporting unit, which management estimates using a weighted combination of a discounted cash flow analysis and a market multiples analysis. Significant assumptions used in these fair value analyses include discount and growth rates, utility sector market performance and transactions, and projected operating and capital cash flows for ComEd’s, Pepco's, DPL's, and ACE's businesses and the fair value of debt. While the 2021 annual assessments indicated no impairments, certain assumptions used in the assessment are highly sensitive to changes. Adverse regulatory actions or changes in significant assumptions could potentially result in future impairments of Exelon’s, ComEd's, or PHI’s goodwill, which could be material. See Note 1 — Significant Accounting Policies and Note 13 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information.
Unamortized Energy Contract Assets and Liabilities (Exelon and PHI) Unamortized energy contract assets and liabilities represent the remaining unamortized balances of non-derivative energy contracts that Generation has acquired and the electricity contracts Exelon acquired as part of the PHI merger. The initial amount recorded represents the difference between the fair value of the contracts at the time of acquisition and the contract value based on the terms of each contract. At Exelon and PHI, offsetting regulatory assets or liabilities were also recorded for those energy contract costs that are probable of recovery or refund through customer rates. The unamortized energy contract assets and liabilities and any corresponding regulatory assets or liabilities, respectively, are amortized over the life of the contract in relation to the expected realization of the underlying cash flows. Amortization of the unamortized energy contract assets and liabilities are recorded through purchased power and fuel expense or operating revenues, depending on the nature of the underlying contract. See Note 3 — Regulatory Matters and Note 13 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information. Impairment of Long-Lived Assets (Exelon) Exelon regularly monitors and evaluates 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 potential impairment may include a deteriorating business climate, including, but not limited to, declines in energy prices, condition of the asset, or plans to dispose of a long-lived asset significantly before the end of its useful life. The review of long-lived assets or asset groups for impairment utilizes significant assumptions about operating strategies and estimates of future cash flows, which require assessments of current and projected market conditions. For Generation, forecasting future cash flows requires assumptions regarding forecasted commodity prices for the sale of power and purchases of fuel and the expected operations of assets. A variation in the assumptions used could lead to a different conclusion regarding the recoverability of an asset or asset group. An impairment evaluation is based on an undiscounted cash flow analysis at the lowest level at which cash flows of the long-lived assets or asset groups are largely independent of the cash flows of other assets and liabilities. For Generation, the lowest level of independent cash flows is determined by the evaluation of several factors, including the geographic dispatch of the generation units and the hedging strategies related to those units. The cash flows from the generating units are generally evaluated at a regional portfolio level given the interdependency of cash flows generated from the customer supply and risk management activities within each region. In certain cases, the generating assets may be evaluated on an individual basis where those assets are contracted on a long-term basis with a third party and operations are independent of other generating assets (typically contracted renewables). On a quarterly basis, Generation assesses its long-lived assets or asset groups for indicators of potential impairment. If indicators are present for a long-lived asset or asset group, a comparison of the undiscounted expected future cash flows to the carrying value is performed. When the undiscounted cash flow analysis indicates the carrying value of a long-lived asset or asset group may not be 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 of the long-lived asset or asset group is dependent upon a market participant’s view of the exit price of the asset or asset groups. This includes significant assumptions of the estimated future cash flows generated by the asset or asset groups and market discount rates. Events and circumstances often do not occur as expected, resulting in differences between prospective financial information and actual results, which may be material. The determination of fair value is driven by both internal assumptions that include significant unobservable inputs (Level 3), such as revenue and generation forecasts, projected capital, maintenance expenditures, and discount rates, as well as information from various public, financial and industry sources. See Note 12 — Asset Impairments of the Combined Notes to Consolidated Financial Statements for a discussion of asset impairment assessments. Depreciable Lives of Property, Plant, and Equipment (All Registrants) The Registrants have significant investments in electric generation assets and electric and natural gas transmission and distribution assets. These assets are generally depreciated on a straight-line basis, using the group, composite, or unitary methods of depreciation. The group approach is typically for groups of similar assets
that have approximately the same useful lives and the composite approach is used for heterogeneous assets that have different lives. Under both methods, a reporting entity depreciates the assets over the average life of the assets in the group. The estimation of asset useful lives requires management judgment, supported by formal depreciation studies of historical asset retirement experience. Depreciation studies are conducted periodically and as required by a rate regulator or if an event, regulatory action, or change in retirement patterns indicate an update is necessary. For the Utility Registrants, depreciation studies generally serve as the basis for amounts allowed in customer rates for recovery of depreciation costs. Generally, the Utility Registrants adjust their depreciation rates for financial reporting purposes concurrent with adjustments to depreciation rates reflected in customer rates, unless the depreciation rates reflected in customer rates do not align with management’s judgment as to an appropriate estimated useful life or have not been updated on a timely basis. Depreciation expense and customer rates for ComEd, BGE, Pepco, DPL, and ACE include an estimate of the future costs of dismantling and removing plant from service upon retirement. See Note 3 — Regulatory Matters of the Combined Notes to the Consolidated Financial Statements for information regarding regulatory liabilities and assets recorded by ComEd, BGE, Pepco, DPL, and ACE related to removal costs. PECO’s removal costs are capitalized to accumulated depreciation when incurred, and recorded to depreciation expense over the life of the new asset constructed consistent with PECO’s regulatory recovery method. Estimates for such removal costs are also evaluated in the periodic depreciation studies. At Generation, along with depreciation study results, management considers expected future energy market conditions and generation plant operating costs and capital investment requirements in determining the estimated service lives of its generating facilities and reassesses the reasonableness of estimated useful lives whenever events or changes in circumstances warrant. When a determination has been made that an asset will be retired before the end of its current estimated useful life, depreciation provisions will be accelerated to reflect the shortened estimated useful life. See Note 7 — Early Plant Retirements of the Combined Notes to the Consolidated Financial Statements for additional information. Changes in estimated useful lives of electric generation assets and of electric and natural gas transmission and distribution assets could have a significant impact on the Registrants’ future results of operations. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for information regarding depreciation and estimated service lives of the property, plant, and equipment of the Registrants. Defined Benefit Pension and Other Postretirement Employee Benefits (All Registrants) Exelon sponsors defined benefit pension plans and OPEB plans for substantially all current employees. The measurement of the plan obligations and costs of providing benefits involves various factors, including the development of valuation assumptions and inputs and accounting policy elections. When developing the required assumptions, Exelon considers historical information as well as future expectations. The measurement of benefit obligations and costs is affected by several assumptions including the discount rate, the long-term expected rate of return on plan assets, the anticipated rate of increase of health care costs, Exelon's contributions, the rate of compensation increases, and the long-term expected investment rate credited to employees of certain plans, among others. The assumptions are updated annually and upon any interim remeasurement of the plan obligations. Pension and OPEB plan assets include equity securities, including U.S. and international securities, and fixed income securities, as well as certain alternative investment classes such as real estate, private equity, and hedge funds. Expected Rate of Return on Plan Assets. In determining the EROA, Exelon considers historical economic indicators (including inflation and GDP growth) that impact asset returns, as well as expectation regarding future long-term capital market performance, weighted by Exelon’s target asset class allocations. Exelon calculates the amount of expected return on pension and OPEB plan assets by multiplying the EROA by the MRV of plan assets at the beginning of the year, taking into consideration anticipated contributions and benefit payments to be made during the year. In determining MRV, the authoritative guidance for pensions and postretirement benefits allows the use of either fair value or a calculated value that recognizes changes in fair value in a systematic and rational manner over not more than five years. For the majority of pension plan assets, Exelon uses a calculated value that adjusts for 20% of the difference between fair value and expected MRV of plan assets. Use of this
calculated value approach enables less volatile expected asset returns to be recognized as a component of pension cost from year to year. For OPEB plan assets and certain pension plan assets, Exelon uses fair value to calculate the MRV. Discount Rate. The discount rates are determined by developing a spot rate curve based on the yield to maturity of a universe of high-quality non-callable (or callable with make whole provisions) bonds with similar maturities to the related pension and OPEB obligations. The spot rates are used to discount the estimated future benefit distribution amounts under the pension and OPEB plans. The discount rate is the single level rate that produces the same result as the spot rate curve. Exelon utilizes an analytical tool developed by its actuaries to determine the discount rates. Mortality. The mortality assumption is composed of a base table that represents the current expectation of life expectancy of the population adjusted by an improvement scale that attempts to anticipate future improvements in life expectancy. Exelon’s mortality assumption utilizes the SOA 2019 base table (Pri-2012) and MP-2021 improvement scale adjusted to use Proxy SSA ultimate improvement rates. Sensitivity to Changes in Key Assumptions. The following tables illustrate the effects of changing certain of the actuarial assumptions discussed above, while holding all other assumptions constant: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Actual Assumption | | | | | | | | | Actuarial Assumption | Pension | | OPEB | | Change in Assumption | | Pension | | OPEB | | Total | Change in 2021 cost: | | | | | | | | | | | | Discount rate(a) | 2.58% | | 2.51% | | 0.5% | | $ | (57) | | | $ | (10) | | | $ | (67) | | | 2.58% | | 2.51% | | (0.5)% | | 82 | | | 11 | | | 93 | | EROA | 7.00% | | 6.46% | | 0.5% | | (95) | | | (12) | | | (107) | | | 7.00% | | 6.46% | | (0.5)% | | 95 | | | 12 | | | 107 | | Change in benefit obligation at December 31, 2021: | | | | | | | | | | | | Discount rate(a) | 2.92% | | 2.88% | | 0.5% | | (1,393) | | | (242) | | | (1,635) | | | 2.92% | | 2.88% | | (0.5)% | | 1,618 | | | 279 | | | 1,897 | |
__________ (a)In general, the discount rate will have a larger impact on the pension and OPEB cost and obligation as the rate moves closer to 0%. Therefore, the discount rate sensitivities above cannot necessarily be extrapolated for larger increases or decreases in the discount rate. Additionally, Exelon utilizes a liability-driven investment strategy for its pension asset portfolio. The sensitivities shown above do not reflect the offsetting impact that changes in discount rates may have on pension asset returns. See Note 1 — Significant Accounting Policies and Note 15 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information regarding the accounting for the defined benefit pension plans and OPEB plans. Regulatory Accounting (All Registrants) For their regulated electric and gas operations, the Registrants reflect the effects of cost-based rate regulation in their financial statements, which is required for entities with regulated operations that meet the following criteria: (1) rates are established or approved by a third-party regulator; (2) rates are designed to recover the entities’ cost of providing services or products; and (3) a reasonable expectation that rates designed to recover costs can be charged to and collected from customers. Regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent (1) revenue or gains that have been deferred because it is probable such amounts will be returned to customers through future regulated rates; or (2) billings in advance of expenditures for approved regulatory programs. If it is concluded in a future period that a separable portion of operations no longer meets the criteria discussed above, the Registrants would be required to eliminate any associated regulatory assets and liabilities and the impact, which could be material, would be recognized in the Consolidated Statements of Operations and Comprehensive Income.
The following table illustrates gains (losses) to be included in net income that could result from the elimination of regulatory assets and liabilities and charges against OCI related to deferred costs associated with Exelon's pension and OPEB plans that are recorded as regulatory assets in Exelon's Consolidated Balance Sheets (before taxes): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2021 | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Gain (loss) | $ | 3,743 | | | $ | 4,739 | | | $ | (262) | | | $ | 268 | | | $ | (920) | | | $ | (182) | | | $ | 186 | | | $ | (239) | | Charge against OCI(a) | $ | (3,259) | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
___________ (a)Exelon's charge against OCI (before taxes) consists of up to $2.2 billion, $391 million, $703 million, $323 million, $154 million, and $91 million related to ComEd's, BGE's, PHI's, Pepco's, DPL's, and ACE's respective portions of the deferred costs associated with Exelon's pension and OPEB plans. Exelon also has a net regulatory liability of $66 million (before taxes) related to PECO’s portion of the deferred costs associated with Exelon’s OPEB plans that would result in an increase in OCI if reversed. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information regarding regulatory matters, including the regulatory assets and liabilities of the Registrants. For each regulatory jurisdiction in which they conduct business, the Registrants assess whether the regulatory assets and liabilities continue to meet the criteria for probable future recovery or refund at each balance sheet date and when regulatory events occur. This assessment includes consideration of recent rate orders, historical regulatory treatment for similar costs in each Registrant's jurisdictions, and factors such as changes in applicable regulatory and political environments. If the assessments and estimates made by the Registrants for regulatory assets and regulatory liabilities are ultimately different than actual regulatory outcomes, the impact in their consolidated financial statements could be material. Refer to the revenue recognition discussion below for additional information on the annual revenue reconciliations associated with ICC-approved electric distribution and energy efficiency formula rates for ComEd, and FERC transmission formula rate tariffs for the Utility Registrants. Accounting for Derivative Instruments (All Registrants) The Registrants use derivative instruments to manage commodity price risk, foreign currency exchange risk, and interest rate risk related to ongoing business operations. The Registrants’ derivative activities are in accordance with Exelon’s Risk Management Policy (RMP). See Note 16 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information. The Registrants account for derivative financial instruments under the applicable authoritative guidance. Determining whether a contract qualifies as a derivative requires that management exercise significant judgment, including assessing market liquidity as well as determining whether a contract has one or more underlying and one or more notional quantities. Changes in management’s assessment of contracts and the liquidity of their markets, and changes in authoritative guidance, could result in previously excluded contracts becoming in scope of new authoritative guidance. All derivatives are recognized on the balance sheet at their fair value, except for certain derivatives that qualify for, and are elected under, NPNS. Derivatives entered for economic hedging and for proprietary trading purposes are recorded at fair value through earnings. For economic hedges that are not designated for hedge accounting for the Utility Registrants, changes in the fair value each period are generally recorded with a corresponding offsetting regulatory asset or liability given the likelihood of recovering the associated costs through customer rates. NPNS. As part of Generation’s energy marketing business, Generation enters contracts to buy and sell energy to meet the requirements of its customers. These contracts include short-term and long-term commitments to purchase and sell energy and energy-related products in the retail and wholesale markets with the intent and ability to deliver or take delivery. While some of these contracts are considered derivative financial instruments under the authoritative guidance, certain of these qualifying transactions have been designated by Generation as NPNS transactions, which are thus not required to be recorded at fair value, but rather on an accrual basis of accounting. Determining whether a contract qualifies for the NPNS requires judgment on whether the contract will physically deliver and requires that management ensure compliance with all the associated qualification and
documentation requirements. Revenues and expenses on contracts that qualify as NPNS are recognized when the underlying physical transaction is completed. Contracts that qualify for the NPNS are those for which physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable period, and the contract is not financially settled on a net basis. The contracts that ComEd has entered into with suppliers as part of ComEd’s energy procurement process, PECO’s full requirement contracts under the PAPUC-approved DSP program, most of PECO’s natural gas supply agreements, all of BGE’s full requirement contracts and natural gas supply agreements that are derivatives, and certain Pepco, DPL, and ACE full requirement contracts qualify for and are accounted for under the NPNS. Commodity Contracts. Identification of a commodity contract as an economic hedge requires Generation to determine that the contract is in accordance with the RMP. Generation reassesses its economic hedges on a regular basis to determine if they continue to be within the guidelines of the RMP. As a part of the authoritative guidance, the Registrants make estimates and assumptions concerning future commodity prices, load requirements, interest rates, the timing of future transactions and their probable cash flows, the fair value of contracts and the expected changes in the fair value in deciding whether to enter derivative transactions, and in determining the initial accounting treatment for derivative transactions. Under the authoritative guidance for fair value measurements, the Registrants categorize these derivatives under a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. Derivative contracts are traded in both exchange-based and non-exchange-based markets. Exchange-based derivatives that are valued using unadjusted quoted prices in active markets are generally categorized in Level 1 in the fair value hierarchy. Certain derivative pricing is verified using indicative price quotations available through brokers or over-the-counter, online exchanges. The price quotations reflect the average of the mid-point of the bid-ask spread from observable markets that the Registrants believe provide the most liquid market for the commodity. The price quotations are reviewed and corroborated to ensure the prices are observable and representative of an orderly transaction between market participants. The Registrant’s derivatives are traded predominantly at liquid trading points. The remaining derivative contracts are valued using models that consider inputs such as contract terms, including maturity, and market parameters, and assumptions of the future prices of energy, interest rates, volatility, credit worthiness, and credit spread. For derivatives that trade in liquid markets, such as generic forwards, swaps, and options, the model inputs are generally observable. Such instruments are categorized in Level 2. For derivatives that trade in less liquid markets with limited pricing information, the model inputs generally would include both observable and unobservable inputs and are categorized in Level 3. The Registrants consider nonperformance risk, including credit risk in the valuation of derivative contracts, and both historical and current market data in its assessment of nonperformance risk. The impacts of nonperformance and credit risk to date have generally not been material to the financial statements. See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK and Note 18 — Fair Value of Financial Assets and Liabilities and Note 16 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding the Registrants’ derivative instruments. Taxation (All Registrants) Significant management judgment is required in determining the Registrants’ provisions for income taxes, primarily due to the uncertainty related to tax positions taken, as well as deferred tax assets and liabilities and valuation allowances. The Registrants account for uncertain income tax positions using a benefit recognition model with a two-step approach including a more-likely-than-not recognition threshold and a measurement approach based on the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. Management evaluates each position based solely on the technical merits and facts and circumstances of the position, assuming the position will be examined by a taxing authority having full knowledge of all relevant information. Significant judgment is required to determine whether the recognition threshold has been met and, if so, the appropriate amount of tax benefits to be recorded in the Registrants’ consolidated financial statements.
The Registrants evaluate quarterly the probability of realizing deferred tax assets by reviewing a forecast of future taxable income and their intent and ability to implement tax planning strategies, if necessary, to realize deferred tax assets. The Registrants also assess negative evidence, such as the expiration of historical operating loss or tax credit carryforwards, that could indicate the Registrant's inability to realize its deferred tax assets. Based on the combined assessment, the Registrants record valuation allowances for deferred tax assets when it is more-likely-than-not such benefit will not be realized in future periods. Actual income taxes could vary from estimated amounts due to the future impacts of various items, including future changes in income tax laws, the Registrants’ forecasted financial condition and results of operations, failure to successfully implement tax planning strategies, as well as results of audits and examinations of filed tax returns by taxing authorities. See Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information. Accounting for Loss Contingencies (All Registrants) In the preparation of their financial statements, the Registrants make judgments regarding the future outcome of contingent events and record liabilities for loss contingencies that are probable and can be reasonably estimated based upon available information. The amount recorded may differ from the actual expense incurred when the uncertainty is resolved. Such difference could have a significant impact in the Registrants' consolidated financial statements. Environmental Costs. Environmental investigation and remediation liabilities are based upon estimates with respect to the number of sites for which the Registrants will be responsible, the scope and cost of work to be performed at each site, the portion of costs that will be shared with other parties, the timing of the remediation work, regulations, and the requirements of local governmental authorities. Annual studies and/or reviews are conducted at ComEd, PECO, BGE, and DPL to determine future remediation requirements for MGP sites and estimates are adjusted accordingly. In addition, periodic reviews are performed at each of the Registrants to assess the adequacy of other environmental reserves. These matters, if resolved in a manner different from the estimate, could have a significant impact in the Registrants’ consolidated financial statements. See Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information. Other, Including Personal Injury Claims. The Registrants are self-insured for general liability, automotive liability, workers’ compensation, and personal injury claims to the extent that losses are within policy deductibles or exceed the amount of insurance maintained. The Registrants have reserves for both open claims asserted, and an estimate of claims incurred but not reported (IBNR). The IBNR reserve is estimated based on actuarial assumptions and analysis and is updated annually. Future events, such as the number of new claims to be filed each year, the average cost of disposing of claims, as well as the numerous uncertainties surrounding litigation and possible state and national legislative measures could cause the actual costs to be higher or lower than estimated. Accordingly, these claims, if resolved in a manner different from the estimate, could have a material impact to the Registrants’ consolidated financial statements.
Revenue Recognition (All Registrants) Sources of Revenue and Determination of Accounting Treatment. The Registrants earn revenues from various business activities including: the sale of power and energy-related products, such as natural gas, capacity, and other commodities in non-regulated markets (wholesale and retail); the sale and delivery of power and natural gas in regulated markets; and the provision of other energy-related non-regulated products and services. The accounting treatment for revenue recognition is based on the nature of the underlying transaction and applicable authoritative guidance. The Registrants primarily apply the Revenue from Contracts with Customers, Derivative Revenues, and Alternative Revenue Program Accounting guidance to recognize revenue as discussed in more detail below. Revenue from Contracts with Customers. The Registrants recognize revenues in the period in which the performance obligations within contracts with customers are satisfied, which generally occurs when power, natural gas, and other energy-related commodities are physically delivered to the customer. Transactions of the Registrants within the scope of Revenue from Contracts with Customers generally include non-derivative agreements, contracts that are designated as NPNS, sales to utility customers under regulated service tariffs, and spot-market energy commodity sales, including settlements with ISOs. The determination of Generation’s and the Utility Registrants' retail power and natural gas sales to individual customers is based on systematic readings of customer meters, generally monthly. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated, and corresponding unbilled revenue is recorded. The measurement of unbilled revenue is affected by the following factors: daily customer usage measured by generation or gas throughput volume, customer usage by class, losses of energy during delivery to customers and applicable customer rates. Increases or decreases in volumes delivered to the utilities’ customers and favorable or unfavorable rate mix due to changes in usage patterns in customer classes in the period could be significant to the calculation of unbilled revenue. In addition, revenues may fluctuate monthly as a result of customers electing to use an alternative supplier, since unbilled commodity revenues are not recorded for these customers. Changes in the timing of meter reading schedules and the number and type of customers scheduled for each meter reading date also impact the measurement of unbilled revenue; however, total operating revenues would remain materially unchanged. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional information. Derivative Revenues. The Registrants record revenues and expenses using the mark-to-market method of accounting for transactions that are accounted for as derivatives. These derivative transactions primarily relate to commodity price risk management activities. Mark-to-market revenues and expenses include: inception gains or losses on new transactions where the fair value is observable, unrealized gains and losses from changes in the fair value of open contracts, and realized gains and losses. Alternative Revenue Program Accounting. Certain of the Utility Registrants’ ratemaking mechanisms qualify as ARPs if they (i) are established by a regulatory order and allow for automatic adjustment to future rates, (ii) provide for additional revenues (above those amounts currently reflected in the price of utility service) that are objectively determinable and probable of recovery, and (iii) allow for the collection of those additional revenues within 24 months following the end of the period in which they were recognized. For mechanisms that meet these criteria, which include the Utility Registrants’ formula rate mechanisms and revenue decoupling mechanisms, the Utility Registrants adjust revenue and record an offsetting regulatory asset or liability once the condition or event allowing additional billing or refund has occurred. The ARP revenues presented in the Utility Registrants’ Consolidated Statements of Operations and Comprehensive Income include both: (i) the recognition of “originating” ARP revenues (when the regulator-specified condition or event allowing for additional billing or refund has occurred) and (ii) an equal and offsetting reversal of the “originating” ARP revenues as those amounts are reflected in the price of utility service and recognized as Revenue from Contracts with Customers. ComEd records ARP revenue for its best estimate of the electric distribution, energy efficiency, distributed generation rebates, and transmission revenue impacts resulting from future changes in rates that ComEd believes are probable of approval by the ICC and FERC in accordance with its formula rate mechanisms. BGE, Pepco, DPL, and ACE record ARP revenue for their best estimate of the electric and natural gas distribution revenue impacts resulting from future changes in rates that they believe are probable of approval by the MDPSC, DCPSC, and/or NJBPU in accordance with their revenue decoupling mechanisms. PECO, BGE, Pepco, DPL,
and ACE record ARP revenue for their best estimate of the transmission revenue impacts resulting from future changes in rates that they believe are probable of approval by FERC in accordance with their formula rate mechanisms. Estimates of the current year revenue requirement are based on actual and/or forecasted costs and investments in rate base for the period and the rates of return on common equity and associated regulatory capital structure allowed under the applicable tariff. The estimated reconciliation can be affected by, among other things, variances in costs incurred, investments made, allowed ROE, and actions by regulators or courts. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. Allowance for Credit Losses on Customer Accounts Receivable (All Registrants) Utility Registrants estimate the allowance for credit losses on customer receivables by applying loss rates developed specifically for each company based on historical loss experience, current conditions, and forward-looking risk factors to the outstanding receivable balance by customer risk segment. Risk segments represent a group of customers with similar forward-looking credit quality indicators and risk factors that are comprised based on various attributes, including delinquency of their balances and payment history and represent expected, future customer behavior. Loss rates applied to the accounts receivable balances are based on a historical average of charge-offs as a percentage of accounts receivable in each risk segment. The Utility Registrants' customer accounts are generally considered delinquent if the amount billed is not received by the time the next bill is issued, which normally occurs on a monthly basis. Utility Registrants' customer accounts are written off consistent with approved regulatory requirements. Utility Registrants' allowances for credit losses will continue to be affected by changes in volume, prices, and economic conditions as well as changes in ICC, PAPUC, MDPSC, DCPSC, DEPSC, and NJBPU regulations.
Results of Operations by Registrant or Subsidiary Results of Operations—ComEd | | | | | | | | | | | | | | | | | | | 2021 | | 2020 | | Favorable (Unfavorable) Variance | Operating revenues | $ | 6,406 | | | $ | 5,904 | | | $ | 502 | | | | | | | | | | | | | | Operating expenses | | | | | | Purchased power expense | 2,271 | | | 1,998 | | | (273) | | Operating and maintenance | 1,355 | | | 1,520 | | | 165 | | Depreciation and amortization | 1,205 | | | 1,133 | | | (72) | | Taxes other than income taxes | 320 | | | 299 | | | (21) | | Total operating expenses | 5,151 | | | 4,950 | | | (201) | | | | | | | | Operating income | 1,255 | | | 954 | | | 301 | | Other income and (deductions) | | | | | | Interest expense, net | (389) | | | (382) | | | (7) | | Other, net | 48 | | | 43 | | | 5 | | Total other income and (deductions) | (341) | | | (339) | | | (2) | | Income before income taxes | 914 | | | 615 | | | 299 | | Income taxes | 172 | | | 177 | | | 5 | | Net income | $ | 742 | | | $ | 438 | | | $ | 304 | |
Year Ended December 31, 2021 Compared to Year Ended December 31, 2020.Net income increased by $304 million 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) and payments that ComEd made in 2020 under the Deferred Prosecution Agreement. See Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information related to the Deferred Prosecution Agreement. The changes in Operating revenues consisted of the following: | | | | | | | 2021 vs. 2020 | | Increase | Electric Distribution | $ | 135 | | Energy efficiency | 42 | | Transmission | 13 | | Other | 23 | | 213 | | Regulatory required programs | 289 | | Total increase | $ | 502 | |
Revenue Decoupling. The demand for electricity is affected by weather and customer usage. Operating revenues are not impacted by abnormal weather, usage per customer, or number of customers as a result of revenue decoupling mechanisms implemented 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 during the year ended December 31, 2021, as compared to the same period in 2020, due to the impact of higher rate base and higher allowed ROE due to an increase in treasury rates.
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. Under FEJA, energy efficiency revenue varies from year to year based upon fluctuations in the underlying costs, investments being recovered, and allowed ROE. Energy efficiency revenue increased during the year ended December 31, 2021, as compared to the same period in 2020, primarily due to increased regulatory asset amortization, which is fully recoverable. 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. During the year ended December 31, 2021, as compared to the same period in 2020, transmission revenues increased primarily due to the impact of a higher rate base. Other Revenue primarily includes assistance provided to other utilities through mutual assistance programs. Other revenue increased for the year ended December 31, 2021, as compared to the same period in 2020, which primarily reflects mutual assistance revenues associated with storm restoration efforts. 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, and costs related to electricity, ZEC, and REC procurement. 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 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, 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 ComEd's revenue disaggregation. The increase of $273 million for the year ended December 31, 2021, as compared to the same period in 2020, 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: | | | | | | | | | 2021 vs. 2020 | | | | (Decrease) Increase | | | Deferred Prosecution Agreement payments(a) | $ | (200) | | | | BSC costs | 21 | | | | Labor, other benefits, contracting, and materials | (5) | | | | Pension and non-pension postretirement benefits expense | 6 | | | | Storm-related costs | (6) | | | | Other | 4 | | | | | (180) | | | | Regulatory required programs(b) | 15 | | | | Total decrease | $ | (165) | | | | | | | | | | | | | | | | | | | |
__________ (a)See Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information. (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: | | | | | | | | | 2021 vs. 2020 | | | | Increase | | | Depreciation and amortization(a) | $ | 48 | | | | Regulatory asset amortization(b) | 24 | | | | | | | | Total increase | $ | 72 | | | |
__________ (a)Reflects ongoing capital expenditures. (b)Includes amortization of ComEd's energy efficiency formula rate regulatory asset. Effective income tax rates for the years ended December 31, 2021and2020, were 18.8%and 28.8%, respectively. See Note 14 — 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 | | | | | | | | | | | | | | | | | | | 2021 | | 2020 | | (Unfavorable) Favorable Variance | Operating revenues | $ | 3,198 | | | $ | 3,058 | | | $ | 140 | | Operating expenses | | | | | | Purchased power and fuel expense | 1,081 | | | 1,018 | | | (63) | | Operating and maintenance | 934 | | | 975 | | | 41 | | Depreciation and amortization | 348 | | | 347 | | | (1) | | Taxes other than income taxes | 184 | | | 172 | | | (12) | | Total operating expenses | 2,547 | | | 2,512 | | | (35) | | | | | | | | Operating income | 651 | | | 546 | | | 105 | | Other income and (deductions) | | | | | | Interest expense, net | (161) | | | (147) | | | (14) | | Other, net | 26 | | | 18 | | | 8 | | Total other income and (deductions) | (135) | | | (129) | | | (6) | | Income before income taxes | 516 | | | 417 | | | 99 | | Income taxes | 12 | | | (30) | | | (42) | | | | | | | | | | | | | | Net income | $ | 504 | | | $ | 447 | | | $ | 57 | |
Year Ended December 31, 2021 Compared to Year Ended December 31, 2020.Net income increased by $57 million primarily due to favorable weather conditions, an increase in volume, and a decrease in storm cost activity, net of tax repair deductions. The changes in Operating revenues consisted of the following: | | | | | | | | | | | | | | | | | | | 2021 vs. 2020 | | (Decrease) Increase | | Electric | | Gas | | Total | Weather | $ | 16 | | | $ | 1 | | | $ | 17 | | Volume | 15 | | | 13 | | | 28 | | Pricing | 12 | | | 7 | | | 19 | | Transmission | 13 | | | — | | | 13 | | Other | 1 | | | 3 | | | 4 | | | 57 | | | 24 | | | 81 | | Regulatory required programs | 58 | | | 1 | | | 59 | | Total increase | $ | 115 | | | $ | 25 | | | $ | 140 | |
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. For the year ended December 31, 2021 compared to the same period in 2020, Operating revenues related to weather increased due to the impact of favorable 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 years ended December 31, 2021 compared to the same period in 2020 and normal weather consisted of the following:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | | | | % Change | Heating and Cooling Degree-Days | 2021 | | 2020 | | Normal | | 2021 vs. 2020 | | 2021 vs. Normal | Heating Degree-Days | 3,946 | | | 3,959 | | | 4,409 | | | (0.3) | % | | (10.5) | % | Cooling Degree-Days | 1,586 | | | 1,521 | | | 1,435 | | | 4.3 | % | | 10.5 | % |
Volume. Electric volume, exclusive of the effects of weather, for the year ended December 31, 2021 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. Natural gas volume for the year ended December 31, 2021 compared to the same period in 2020, increased due to retail load growth. | | | | | | | | | | | | | | | | | | | | | | | | Electric Retail Deliveries to Customers (in GWhs) | 2021 | | 2020 | | % Change 2021 vs. 2020 | | Weather - Normal % Change(b) | Retail Deliveries(a) | | | | | | | | Residential | 14,262 | | | 14,041 | | | 1.6 | % | | 0.1 | % | Small commercial & industrial | 7,597 | | | 7,210 | | | 5.4 | % | | 4.3 | % | Large commercial & industrial | 14,003 | | | 13,669 | | | 2.4 | % | | 2.1 | % | Public authorities & electric railroads | 559 | | | 575 | | | (2.8) | % | | (2.8) | % | Total electric retail deliveries | 36,421 | | | 35,495 | | | 2.6 | % | | 1.7 | % |
__________ (a)Reflects delivery volumes and revenue 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.
| | | | | | | | | | | | | As of December 31, | Number of Electric Customers | 2021 | | 2020 | Residential | 1,517,806 | | | 1,508,622 | | Small commercial & industrial | 155,308 | | | 154,421 | | Large commercial & industrial | 3,107 | | | 3,101 | | Public authorities & electric railroads | 10,306 | | | 10,206 | | Total | 1,686,527 | | | 1,676,350 | |
| | | | | | | | | | | | | | | | | | | | | | | | Natural Gas Deliveries to customers (in mmcf) | 2021 | | 2020 | | % Change 2021 vs. 2020 | | Weather - Normal % Change(b) | Retail Deliveries(a) | | | | | | | | Residential | 39,580 | | | 38,272 | | | 3.4 | % | | 1.4 | % | Small commercial & industrial | 21,361 | | | 19,341 | | | 10.4 | % | | 7.0 | % | Large commercial & industrial | 34 | | | 36 | | | (5.6) | % | | 8.3 | % | Transportation | 25,081 | | | 24,533 | | | 2.2 | % | | 1.4 | % | Total natural gas deliveries | 86,056 | | | 82,182 | | | 4.7 | % | | 2.8 | % |
__________ (a)Reflects delivery volumes and revenue 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.
| | | | | | | | | | | | | As of December 31, | Number of Gas Customers | 2021 | | 2020 | Residential | 497,873 | | | 492,298 | | Small commercial & industrial | 44,815 | | | 44,472 | | Large commercial & industrial | 6 | | | 5 | | Transportation | 670 | | | 713 | | Total | 543,364 | | | 537,488 | |
Pricing for the year ended December 31, 2021 compared to the same period in 2020 increased primarily due to higher overall effective rates due to favorable customer mix. Additionally, the increase represents revenue from higher natural gas distribution rates. 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. Other Revenue primarily includes revenue related to late payment charges. Other revenues for the year ended December 31, 2021 compared to the same period in 2020, remained relatively consistent. 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. See Note 5—Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of PECO's revenue disaggregation. The increase of $63 million for the year ended December 31, 2021 compared to the same period in 2020, 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: | | | | | | | | 2021 vs. 2020 | | | Increase (Decrease) | | | | | Storm-related costs(a) | $ | (64) | | | Credit loss expense | (3) | | | | | | | | | Labor, other benefits, contracting, and materials | 23 | | | BSC costs | 19 | | | Pension and non-pension postretirement benefits expense | 2 | | | Other | (8) | | | | (31) | | | Regulatory Required Programs | (10) | | | Total decrease | $ | (41) | | | | | | | | | | | | | | | | | | | | | | | |
__________ (a)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: | | | | | | | 2021 vs. 2020 | | Increase (Decrease) | Depreciation and amortization(a) | $ | 17 | | | | | | Regulatory asset amortization | (16) | | | | Total increase | $ | 1 | |
__________ (a)Depreciation and amortization expense increased primarily due to ongoing capital expenditures.
Taxes other than income taxes increased by $12 million for the year ended December 31, 2021 compared to the same period in 2020, primarily due to higher PA gross receipts tax, which is offset in operating revenues, and PA Use Tax. Interest expense, net increased $14 million for the year ended December 31, 2021 compared to the same period in 2020, respectively, primarily due to the issuance of debt in 2021. Effective income tax rates were 2.3% and (7.2)% for the years ended December 31, 2021 and 2020, respectively. See Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information of the change in effective income tax rates.
Results of Operations—BGE | | | | | | | | | | | | | | | | | | | | | | | 2021 | | 2020 | | Favorable (Unfavorable) Variance | | | | | Operating revenues | $ | 3,341 | | | $ | 3,098 | | | $ | 243 | | | | | | Operating expenses | | | | | | | | | | Purchased power and fuel | 1,175 | | | 991 | | | (184) | | | | | | Operating and maintenance | 811 | | | 789 | | | (22) | | | | | | Depreciation and amortization | 591 | | | 550 | | | (41) | | | | | | Taxes other than income taxes | 283 | | | 268 | | | (15) | | | | | | Total operating expenses | 2,860 | | | 2,598 | | | (262) | | | | | | | | | | | | | | | | Operating income | 481 | | | 500 | | | (19) | | | | | | Other income and (deductions) | | | | | | | | | | Interest expense, net | (138) | | | (133) | | | (5) | | | | | | Other, net | 30 | | | 23 | | | 7 | | | | | | Total other income and (deductions) | (108) | | | (110) | | | 2 | | | | | | Income before income taxes | 373 | | | 390 | | | (17) | | | | | | Income taxes | (35) | | | 41 | | | 76 | | | | | | Net income | $ | 408 | | | $ | 349 | | | $ | 59 | | | | | | | | | | | | | | | |
Year Ended December 31, 2021 Compared to Year Ended December 31, 2020.Net income increased by $59 million primarily due to favorable impacts of the multi-year plan, partially offset by an increase in depreciation and amortization expense. 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: | | | | | | | | | | | | | | | | | | | | | | | | | 2021 vs. 2020 | | | | Increase | | | | Electric | | Gas | | Total | | | | | | | Distribution | $ | 7 | | | $ | 2 | | | $ | 9 | | | | | | | | Transmission | 35 | | | — | | | 35 | | | | | | | | Other | 13 | | | 3 | | | 16 | | | | | | | | | 55 | | | 5 | | | 60 | | | | | | | | Regulatory required programs | 116 | | | 67 | | | 183 | | | | | | | | Total increase | $ | 171 | | | $ | 72 | | | $ | 243 | | | | | | | |
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 monthly rate adjustment that provides for fixed distribution revenue 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. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on revenue decoupling for BGE. | | | | | | | | | | | | | | | As of December 31, | | | Number of Electric Customers | 2021 | | 2020 | | | Residential | 1,195,929 | | | 1,190,678 | | | | Small commercial & industrial | 115,049 | | | 114,173 | | | | Large commercial & industrial | 12,637 | | | 12,478 | | | | Public authorities & electric railroads | 268 | | | 267 | | | | Total | 1,323,883 | | | 1,317,596 | | | |
| | | | | | | | | | | | | | | As of December 31, | | | Number of Gas Customers | 2021 | | 2020 | | | Residential | 651,589 | | | 647,188 | | | | Small commercial & industrial | 38,300 | | | 38,267 | | | | Large commercial & industrial | 6,179 | | | 6,101 | | | | Total | 696,068 | | | 691,556 | | | |
Distribution Revenue increased for the year ended December 31, 2021 compared to the same period in 2020, due to customer growth. 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 increased for the year ended December 31, 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 revenue related to late payment charges, mutual assistance, off-system sales, and service application fees. Other revenue increased for the year ended December 31, 2021 compared to the same period in 2020, as BGE had temporarily suspended customer disconnections for non-payment and temporarily ceased new late fees for all customers in 2020 which has resumed in 2021. 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 acts as the billing agent and therefore 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 $184 million for the year ended December 31, 2021 compared to the same period in 2020, 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: | | | | | | | | | 2021 vs. 2020 | | | | Increase (Decrease) | | | BSC costs | 19 | | | | Storm-related costs | 7 | | | | Credit loss expense | 2 | | | | | | | | Labor, other benefits, contracting, and materials | 4 | | | | Pension and non-pension postretirement benefits expense | 1 | | | | | | | | Small business grants commitment(a) | (15) | | | | Other | (3) | | | | | 15 | | | | Regulatory required programs | 7 | | | | Total increase | $ | 22 | | | |
__________ (a)Reflects charitable contributions expensed as a result of a commitment in 2020 to a multi-year small business grants program. The changes in Depreciation and amortization expense consisted of the following: | | | | | | | | | 2021 vs. 2020 | | | | Increase (Decrease) | | | Depreciation and amortization(a) | $ | 44 | | | | Regulatory required programs | (4) | | | | Regulatory asset amortization | 1 | | | | Total increase | $ | 41 | | | |
__________ (a)Depreciation and amortization increased primarily due to ongoing capital expenditures. Taxes other than income taxes increased for the year ended December 31, 2021 compared to the same period in 2020, primarily due to higher property taxes. Effective income tax rates were (9.4)% and 10.5% for the years ended December 31, 2021 and 2020, respectively. The change is primarily due to the multi-year plan which resulted in the acceleration of certain income tax benefits and the April 24, 2020 settlement agreement of ongoing transmission related income tax regulatory liabilities. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on both the three-year electric and natural gas distribution multi-year plans and the April 24, 2020 settlement agreement and Note 14 — 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 year ended December 31, 2021 compared to the same period in 2020. See the Results of Operations for Pepco, DPL, and ACE for additional information. | | | | | | | | | | | | | | | | | | | 2021 | | 2020 | | Favorable (Unfavorable) Variance | PHI | $ | 561 | | | $ | 495 | | | $ | 66 | | Pepco | 296 | | | 266 | | | 30 | | DPL | 128 | | | 125 | | | 3 | | ACE | 146 | | | 112 | | | 34 | | Other(a) | (9) | | | (8) | | | (1) | |
__________ (a)Primarily includes eliminating and consolidating adjustments, PHI's corporate operations, shared service entities, and other financing and investing activities. Year Ended December 31, 2021 Compared to Year Ended December 31, 2020. Net income increased by $66 million primarily due to favorable impacts as a result of rate case outcomes, 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 electric service territory, a decrease in storm costs due to the August 2020 storms in Delaware at DPL, a decrease in credit loss expense at Pepco and DPL, and partially offset by recognition of a valuation allowance against a deferred tax asset at DPL, due to a change in Delaware tax law and an increase in depreciation and amortization expense.
Results of Operations—Pepco | | | | | | | | | | | | | | | | | | | 2021 | | 2020 | | Favorable (Unfavorable) Variance | Operating revenues | $ | 2,274 | | | $ | 2,149 | | | $ | 125 | | Operating expenses | | | | | | Purchased power | 624 | | | 602 | | | (22) | | Operating and maintenance | 471 | | | 453 | | | (18) | | Depreciation and amortization | 403 | | | 377 | | | (26) | | Taxes other than income taxes | 373 | | | 367 | | | (6) | | Total operating expenses | 1,871 | | | 1,799 | | | (72) | | Gain on sales of assets | — | | | 9 | | | (9) | | Operating income | 403 | | | 359 | | | 44 | | Other income and (deductions) | | | | | | Interest expense, net | (140) | | | (138) | | | (2) | | Other, net | 48 | | | 38 | | | 10 | | Total other income and (deductions) | (92) | | | (100) | | | 8 | | Income before income taxes | 311 | | | 259 | | | 52 | | Income taxes | 15 | | | (7) | | | (22) | | Net income | $ | 296 | | | $ | 266 | | | $ | 30 | |
Year Ended December 31, 2021 Compared to Year Ended December 31, 2020.Net income increased by $30 million primarily due to favorable impacts of the Maryland and District of Columbia multi-year plans, and a decrease in credit loss expense, partially offset by an increase in depreciation and amortization expense and various operating expenses. The changes in Operating revenues consisted of the following: | | | | | | | | | 2021 vs. 2020 | | | | Increase | | | Distribution | $ | 31 | | | | Transmission | 32 | | | | Other | 7 | | | | | 70 | | | | Regulatory required programs | 55 | | | | Total increase | $ | 125 | | | |
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 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. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on revenue decoupling for Pepco Maryland and District of Columbia.
| | | | | | | | | | | | | | | As of December 31, | | | Number of Electric Customers | 2021 | | 2020 | | | Residential | 841,831 | | | 832,190 | | | | Small commercial & industrial | 54,216 | | | 53,800 | | | | Large commercial & industrial | 22,568 | | | 22,459 | | | | Public authorities & electric railroads | 181 | | | 168 | | | | Total | 918,796 | | | 908,617 | | | |
Distribution Revenue increased for the year ended December 31, 2021 compared to the same period in 2020, primarily due to favorable impacts of the Maryland and District of Columbia multi-year plans in 2021. 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. Transmission revenue increased for the year ended December 31, 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. 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 acts as the billing agent and therefore 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 $22 million for the year ended December 31, 2021 compared to the same period in 2020, 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: | | | | | | | | | 2021 vs. 2020 | | | | Increase (Decrease) | | | | | | | | | | | Storm related costs | $ | 5 | | | | BSC and PHISCO costs | 3 | | | | Pension and non-pension postretirement benefits expense | (4) | | | | Labor, other benefits, contracting, and materials | (5) | | | | Credit loss expense | (6) | | | | | | | | | | | | | | | | | | | | Other | 21 | | | | | 14 | | | | Regulatory required programs | 4 | | | | Total increase | $ | 18 | | | |
The changes in Depreciation and amortizationexpense consisted of the following: | | | | | | | | | 2021 vs. 2020 | | | | Increase (Decrease) | | | Depreciation and amortization(a) | $ | 17 | | | | Regulatory asset amortization | (13) | | | | Regulatory required programs | 22 | | | | Total increase | $ | 26 | | | |
__________ (a)Depreciation and amortization increased primarily due to ongoing capital expenditures. Taxes other than income taxes increased for the year ended December 31, 2021 compared to the same period in 2020, primarily due to an increase in property taxes. Gain on sales of assets decreased for the year ended December 31, 2021 compared to the year ended December 31, 2020 due to the sale of land in the fourth quarter of 2020. Other, net increased for the year ended December 31, 2021 compared to the same period in 2020, primarily due to higher AFUDC equity. Effective income tax rates were 4.8% and (2.7)% for the years ended December 31, 2021 and 2020, respectively. The change is primarily related to the settlement agreement of ongoing transmission-related income tax regulatory liabilities, partially offset by the multi-year plan which resulted in the acceleration of certain income tax benefits. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on the three-year electric distribution multi-year plan and the April 24, 2020 settlement agreement, and Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective income tax rates.
Results of Operations—DPL | | | | | | | | | | | | | | | | | | | 2021 | | 2020 | | Favorable (Unfavorable) Variance | Operating revenues | $ | 1,380 | | | $ | 1,271 | | | $ | 109 | | Operating expenses | | | | | | Purchased power and fuel | 539 | | | 503 | | | (36) | | Operating and maintenance | 345 | | | 361 | | | 16 | | Depreciation and amortization | 210 | | | 191 | | | (19) | | Taxes other than income taxes | 67 | | | 65 | | | (2) | | Total operating expenses | 1,161 | | | 1,120 | | | (41) | | | | | | | | Operating income | 219 | | | 151 | | | 68 | | Other income and (deductions) | | | | | | Interest expense, net | (61) | | | (61) | | | — | | Other, net | 12 | | | 10 | | | 2 | | Total other income and (deductions) | (49) | | | (51) | | | 2 | | Income before income taxes | 170 | | | 100 | | | 70 | | Income taxes | 42 | | | (25) | | | (67) | | Net income | $ | 128 | | | $ | 125 | | | $ | 3 | |
Year Ended December 31, 2021 Compared to Year Ended December 31, 2020.Net income increased by $3 million primarily due to higher electric distribution rates, a decrease in storm costs due to the August 2020 storms in Delaware, a decrease in credit loss expense, higher transmission revenues due to an increase in capital investments, and favorable weather conditions at DPL's Delaware electric service territories, which was partially offset by the recognition of a valuation allowance against a deferred tax asset due to a change in Delaware tax law and an increase in depreciation and amortization expense. The changes in Operating revenues consisted of the following: | | | | | | | | | | | | | | | | | | | | | | | | | 2021 vs. 2020 | | | | Increase (Decrease) | | | | Electric | | Gas | | Total | | | | | | | Weather | $ | 5 | | | $ | 1 | | | $ | 6 | | | | | | | | Volume | 1 | | | (1) | | | — | | | | | | | | Distribution | 21 | | | 2 | | | 23 | | | | | | | | Transmission | 33 | | | — | | | 33 | | | | | | | | Other | 2 | | | — | | | 2 | | | | | | | | | 62 | | | 2 | | | 64 | | | | | | | | Regulatory required programs | 41 | | | 4 | | | 45 | | | | | | | | Total increase | $ | 103 | | | $ | 6 | | | $ | 109 | | | | | | | |
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 BSA that provides for a fixed distribution charge per customer by customer class. While Operating revenues from electric distribution in Maryland 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 Consolidated Financial Statements for additional information on revenue decoupling for DPL Maryland. 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 year ended December 31, 2021 compared to the same period in 2020, Operating revenues related to weather increased due to favorable weather conditions in DPL's Delaware electric 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 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 year ended December 31, 2021 compared to same period in 2020 and normal weather consisted of the following: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | | | | % Change | Delaware Electric Service Territory | 2021 | | 2020 | | Normal | | 2021 vs. 2020 | | 2021 vs. Normal | Heating Degree-Days | 4,239 | | | 4,146 | | | 4,608 | | | 2.2 | % | | (8.0) | % | Cooling Degree-Days | 1,380 | | | 1,264 | | | 1,256 | | | 9.2 | % | | 9.9 | % | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | | | | % Change | Delaware Natural Gas Service Territory | 2021 | | 2020 | | Normal | | 2021 vs. 2020 | | 2021 vs. Normal | Heating Degree-Days | 4,239 | | | 4,146 | | | 4,679 | | | 2.2 | % | | (9.4) | % | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Volume, exclusive of the effects of weather, remained relatively consistent for the year ended December 31, 2021 compared to the same period in 2020. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Electric Retail Deliveries to Delaware Customers (in GWhs) | 2021 | | 2020 | | % Change 2021 vs. 2020 | | Weather - Normal % Change (b) | | | | | | | Residential | 3,214 | | | 3,149 | | | 2.1 | % | | (0.1) | % | | | | | | | Small commercial & industrial | 1,452 | | | 1,255 | | | 15.7 | % | | 14.4 | % | | | | | | | Large commercial & industrial | 3,149 | | | 3,225 | | | (2.4) | % | | (2.9) | % | | | | | | | Public authorities & electric railroads | 34 | | | 32 | | | 6.3 | % | | 9.1 | % | | | | | | | Total electric retail deliveries(a) | 7,849 | | | 7,661 | | | 2.5 | % | | 1.1 | % | | | | | | |
| | | | | | | | | | | | | | | As of December 31, | | | Number of Total Electric Customers (Maryland and Delaware) | 2021 | | 2020 | | | Residential | 476,260 | | | 472,621 | | | | Small commercial & industrial | 63,195 | | | 62,461 | | | | Large commercial & industrial | 1,218 | | | 1,223 | | | | Public authorities & electric railroads | 604 | | | 609 | | | | Total | 541,277 | | | 536,914 | | | |
__________ (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) | 2021 | | 2020 | | % Change 2021 vs. 2020 | | Weather - Normal % Change(b) | | | | | | | Residential | 7,914 | | | 7,832 | | | 1.0 | % | | (0.9) | % | | | | | | | Small commercial & industrial | 3,747 | | | 3,718 | | | 0.8 | % | | (1.2) | % | | | | | | | Large commercial & industrial | 1,679 | | | 1,703 | | | (1.4) | % | | (1.5) | % | | | | | | | Transportation | 6,778 | | | 6,631 | | | 2.2 | % | | 1.7 | % | | | | | | | Total natural gas deliveries(a) | 20,118 | | | 19,884 | | | 1.2 | % | | (0.2) | % | | | | | | |
| | | | | | | | | | | | | | | As of December 31, | | | Number of Delaware Natural Gas Customers | 2021 | | 2020 | | | Residential | 128,121 | | | 127,128 | | | | Small commercial & industrial | 10,027 | | | 10,017 | | | | Large commercial & industrial | 20 | | | 16 | | | | Transportation | 158 | | | 161 | | | | Total | 138,326 | | | 137,322 | | | |
__________ (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 year ended December 31, 2021 compared to the same period in 2020 primarily due to higher electric distribution rates in Maryland that became effective in July 2020 and higher electric distribution rates in Delaware that became effective in October 2020. 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 increased for the year ended December 31, 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. All 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 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 DPL, DPL is permitted to recover the electricity, natural gas, and REC procurement costs from customers 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. See Note 5 - Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of DPL's revenue disaggregation. The increase of $36 million for the year ended December 31, 2021 compared to the same period in 2020, 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: | | | | | | | | | 2021 vs. 2020 | | | | (Decrease) Increase | | | Storm-related costs | $ | (20) | | | | Credit loss expense | (7) | | | | | | | | | | | | Pension and non-pension postretirement benefits expense | (3) | | | | Labor, other benefits, contracting, and materials | (2) | | | | BSC and PHISCO costs | 10 | | | | Other | 7 | | | | | (15) | | | | Regulatory required programs | (1) | | | | Total decrease | $ | (16) | | | |
The changes in Depreciation and amortization expense consisted of the following: | | | | | | | | | 2021 vs. 2020 | | | | Increase (Decrease) | | | Depreciation and amortization(a) | $ | 14 | | | | Regulatory asset amortization | (1) | | | | Regulatory required programs | 6 | | | | Total increase | $ | 19 | | | |
__________ (a)Depreciation and amortization increased primarily due to ongoing capital expenditures. Effective income tax rates were 24.7% and (25.0)% for the years ended December 31, 2021 and 2020, respectively. The increase for the year ended December 31, 2021 is primarily related to the recognition of a valuation allowance against a deferred tax asset associated with Delaware net operating loss carryforwards due to a change in Delaware tax law and nonrecurring impact related to the settlement agreement of transmission-related income tax regulatory liabilities in 2020. See Note 3 — Regulatory Matters for additional information on the April 24, 2020 settlement agreement, and Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective income tax rates.
Results of Operations—ACE | | | | | | | | | | | | | | | | | | | 2021 | | 2020 | | Favorable (Unfavorable) Variance | Operating revenues | $ | 1,388 | | | $ | 1,245 | | | $ | 143 | | Operating expenses | | | | | | Purchased power | 694 | | | 609 | | | (85) | | Operating and maintenance | 320 | | | 326 | | | 6 | | Depreciation and amortization | 179 | | | 180 | | | 1 | | Taxes other than income taxes | 8 | | | 8 | | | — | | Total operating expenses | 1,201 | | | 1,123 | | | (78) | | Gain on sale of assets | — | | | 2 | | | (2) | | Operating income | 187 | | | 124 | | | 63 | | Other income and (deductions) | | | | | | Interest expense, net | (58) | | | (59) | | | 1 | | Other, net | 4 | | | 6 | | | (2) | | Total other income and (deductions) | (54) | | | (53) | | | (1) | | Income before income taxes | 133 | | | 71 | | | 62 | | Income taxes | (13) | | | (41) | | | (28) | | Net income | $ | 146 | | | $ | 112 | | | $ | 34 | |
Year Ended December 31, 2021 Compared to Year Ended December 31, 2020. Net income increased $34 million primarily due to favorable impacts as a result of outcomes from a distribution base rate case, higher distribution revenues due to an increase in volume, and higher transmission revenues due to an increase in capital investments which was partially offset by an increase in depreciation and amortization expense. The changes in Operating revenues consisted of the following: | | | | | | | | | 2021 vs. 2020 | | | | Increase (Decrease) | | | Weather | $ | 2 | | | | Volume | 17 | | | | Distribution | 1 | | | | | | | | Transmission | 51 | | | | | | | | | | | | | | | | Other | (3) | | | | | 68 | | | | Regulatory required programs | 75 | | | | Total increase | $ | 143 | | | |
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) 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 on the ACE CIP. 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. There was an increase related to weather for the year
ended December 31, 2021 compared to the same period in 2020 due to the absence of impacts in the second half of 2021 as a result of the CIP. 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 year ended December 31, 2021 compared to same period in 2020, and normal weather consisted of the following: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | | Normal | | % Change | Heating and Cooling Degree-Days | 2021 | | 2020 | | | 2021 vs. 2020 | | 2021 vs. Normal | Heating Degree-Days | 4,256 | | | 4,029 | | | 4,609 | | | 5.6 | % | | (7.7) | % | Cooling Degree-Days | 1,284 | | | 1,314 | | | 1,197 | | | (2.3) | % | | 7.3 | % | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Volume,exclusive of the effects of weather, increased for the year ended December 31, 2021 compared to the same period in 2020, primarily due to customer growth, usage and absence of impacts in the second half of 2021 as a result of the CIP. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Electric Retail Deliveries to Customers (in GWhs) | 2021 | | 2020 | | % Change 2021 vs. 2020 | | Weather - Normal % Change(b) | | | | | | | Residential | 4,220 | | | 4,029 | | | 4.7 | % | | 3.8 | % | | | | | | | Small commercial & industrial | 1,409 | | | 1,277 | | | 10.3 | % | | 10.0 | % | | | | | | | Large commercial & industrial | 3,146 | | | 3,067 | | | 2.6 | % | | 2.8 | % | | | | | | | Public authorities & electric railroads | 46 | | | 47 | | | (2.1) | % | | (1.9) | % | | | | | | | Total retail deliveries(a) | 8,821 | | | 8,420 | | | 4.8 | % | | 4.3 | % | | | | | | |
| | | | | | | | | | | | | | | As of December 31, | | | Number of Electric Customers | 2021 | | 2020 | | | Residential | 499,628 | | | 497,672 | | | | Small commercial & industrial | 61,900 | | | 61,622 | | | | Large commercial & industrial | 3,156 | | | 3,282 | | | | Public authorities & electric railroads | 717 | | | 701 | | | | Total | 565,401 | | | 563,277 | | | |
__________ (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 remained relatively consistent for the year ended December 31, 2021 compared to the same period in 2020. 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. Transmission revenue increased for the year ended December 31, 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, 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 acts as the billing agent and therefore 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 increase of $85 million for the year ended December 31, 2021 compared to same period in 2020, 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: | | | | | | | | | 2021 vs. 2020 | | | | (Decrease) Increase | | | Storm-related costs | $ | (9) | | | | Pension and non-pension postretirement benefits expense | (1) | | | | Labor, other benefits, contracting and materials | 1 | | | | BSC and PHISCO costs | 7 | | | | | | | | | | | | Other | (6) | | | | | (8) | | | | Regulatory required programs(a) | 2 | | | | Total decrease | $ | (6) | | | |
__________ (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 amortizationexpense consisted of the following: | | | | | | | | | 2021 vs. 2020 | | | | Increase (Decrease) | | | Depreciation and amortization(a) | $ | 15 | | | | Regulatory asset amortization | (1) | | | | Regulatory required programs | (15) | | | | | | | | Total decrease | $ | (1) | | | |
__________ (a)Depreciation and amortization increased primarily due to ongoing capital expenditures. Effective income tax rates were (9.8)% and (57.7)% for the years ended December 31, 2021 and 2020, respectively. The change is primarily related to the settlement agreement of ongoing transmission-related income tax regulatory liabilities, partially offset by the July 14, 2021 settlement which allowed ACE to retain certain tax benefits. See Note 3 — Regulatory Matters for additional information on the April 24, 2020 and July 14, 2021 settlement agreements, and Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective income tax rates.
Results of Operations—Generation | | | | | | | | | | | | | | | | | | | | | | | 2021 | | 2020 | | Favorable (Unfavorable) Variance | | | | | Operating revenues | $ | 19,649 | | | $ | 17,603 | | | $ | 2,046 | | | | | | Operating expenses | | | | | | | | | | Purchased power and fuel | 12,163 | | | 9,585 | | | (2,578) | | | | | | Operating and maintenance | 4,555 | | | 5,168 | | | 613 | | | | | | Depreciation and amortization | 3,003 | | | 2,123 | | | (880) | | | | | | Taxes other than income taxes | 475 | | | 482 | | | 7 | | | | | | Total operating expenses | 20,196 | | | 17,358 | | | (2,838) | | | | | | | | | | | | | | | | Gain on sales of assets and businesses | 201 | | | 11 | | | 190 | | | | | | | | | | | | | | | | | | | | | | | | | | Operating (loss) income | (346) | | | 256 | | | (602) | | | | | | Other income and (deductions) | | | | | | | | | | Interest expense, net | (297) | | | (357) | | | 60 | | | | | | Other, net | 795 | | | 937 | | | (142) | | | | | | Total other income and (deductions) | 498 | | | 580 | | | (82) | | | | | | Income before income taxes | 152 | | | 836 | | | (684) | | | | | | Income taxes | 225 | | | 249 | | | 24 | | | | | | Equity in losses of unconsolidated affiliates | (10) | | | (8) | | | (2) | | | | | | Net (loss) income | (83) | | | 579 | | | (662) | | | | | | Net income (loss) attributable to noncontrolling interests | 122 | | | (10) | | | 132 | | | | | | Net (loss) income attributable to membership interest | $ | (205) | | | $ | 589 | | | $ | (794) | | | | | |
Year Ended December 31, 2021 Compared to Year Ended December 31, 2020. Net income attributable to membership interest decreased by $794 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; •Higher net unrealized and realized losses on equity investments; and •The absence of prior year one-time tax settlements. 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 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; •Favorable sales and hedges of excess emission credits; •Favorable commodity prices on fuel hedges; •Lower nuclear fuel costs due to accelerated amortization of nuclear fuel and lower prices; 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 year ended December 31, 2021 compared to 2020, Operating revenues by region were as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2021 vs. 2020 | | 2021 | | 2020 | | Variance | | % Change(a) | Mid-Atlantic(b) | $ | 4,584 | | | $ | 4,645 | | | $ | (61) | | | (1.3) | % | Midwest(c) | 4,060 | | | 4,024 | | | 36 | | | 0.9 | % | New York | 1,575 | | | 1,431 | | | 144 | | | 10.1 | % | ERCOT | 1,181 | | | 958 | | | 223 | | | 23.3 | % | Other Power Regions | 4,890 | | | 4,002 | | | 888 | | | 22.2 | % | Total electric revenues | 16,290 | | | 15,060 | | | 1,230 | | | 8.2 | % | Other | 3,992 | | | 2,433 | | | 1,559 | | | 64.1 | % | Mark-to-market (losses) gains | (633) | | | 110 | | | (743) | | | | Total Operating revenues | $ | 19,649 | | | $ | 17,603 | | | $ | 2,046 | | | 11.6 | % |
__________ (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: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2021 vs. 2020 | Supply Source (GWhs) | 2021 | | 2020 | | Variance | | % Change | Nuclear Generation(a) | | | | | | | | Mid-Atlantic | 53,589 | | | 52,202 | | | 1,387 | | | 2.7 | % | Midwest | 93,107 | | | 96,322 | | | (3,215) | | | (3.3) | % | New York | 28,291 | | | 26,561 | | | 1,730 | | | 6.5 | % | Total Nuclear Generation | 174,987 | | | 175,085 | | | (98) | | | (0.1) | % | Fossil and Renewables | | | | | | | | Mid-Atlantic | 2,271 | | | 2,206 | | | 65 | | | 2.9 | % | Midwest | 1,083 | | | 1,240 | | | (157) | | | (12.7) | % | New York | 1 | | | 4 | | | (3) | | | (75.0) | % | ERCOT | 13,187 | | | 11,982 | | | 1,205 | | | 10.1 | % | Other Power Regions | 9,995 | | | 11,121 | | | (1,126) | | | (10.1) | % | Total Fossil and Renewables | 26,537 | | | 26,553 | | | (16) | | | (0.1) | % | Purchased Power | | | | | | | | Mid-Atlantic | 13,576 | | | 22,487 | | | (8,911) | | | (39.6) | % | Midwest | 561 | | | 770 | | | (209) | | | (27.1) | % | | | | | | | | | ERCOT | 3,256 | | | 5,636 | | | (2,380) | | | (42.2) | % | Other Power Regions | 50,212 | | | 51,079 | | | (867) | | | (1.7) | % | Total Purchased Power | 67,605 | | | 79,972 | | | (12,367) | | | (15.5) | % | Total Supply/Sales by Region | | | | | | | | Mid-Atlantic(b) | 69,436 | | | 76,895 | | | (7,459) | | | (9.7) | % | Midwest(b) | 94,751 | | | 98,332 | | | (3,581) | | | (3.6) | % | New York | 28,292 | | | 26,565 | | | 1,727 | | | 6.5 | % | ERCOT | 16,443 | | | 17,618 | | | (1,175) | | | (6.7) | % | Other Power Regions | 60,207 | | | 62,200 | | | (1,993) | | | (3.2) | % | Total Supply/Sales by Region | 269,129 | | | 281,610 | | | (12,481) | | | (4.4) | % |
__________ (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. | | | | | | | | | | | | | 2021 | | 2020 | Nuclear fleet capacity factor | 94.5 | % | | 95.4 | % | Refueling outage days | 262 | | | 260 | | Non-refueling outage days | 34 | | | 19 | |
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. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2021 vs. 2020 | State (Region) | 2021 | | 2020 | | Variance | | % Change | New Jersey (Mid-Atlantic) | $ | 10.00 | | | $ | 10.00 | | | $ | — | | | — | % | Illinois (Midwest) | 16.50 | | | 16.50 | | | — | | | — | % | New York (New York) | 20.93 | | | 19.59 | | | 1.34 | | | 6.8 | % |
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. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2021 vs. 2020 | Location (Region) | 2021 | | 2020 | | Variance | | % Change | Eastern Mid-Atlantic Area Council (Mid-Atlantic and Midwest) | $ | 174.96 | | | $ | 159.50 | | | $ | 15.46 | | | 9.7 | % | ComEd (Midwest) | 192.45 | | | 194.22 | | | (1.77) | | | (0.9) | % | Rest of State (New York) | 98.35 | | | 47.81 | | | 50.54 | | | 105.7 | % | Southeast New England (Other) | 163.66 | | | 200.69 | | | (37.03) | | | (18.5) | % |
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. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2021 vs. 2020 | Location (Region) | 2021 | | 2020 | | Variance | | % Change | PJM West (Mid-Atlantic) | $ | 38.91 | | | $ | 20.95 | | | $ | 17.96 | | | 85.7 | % | ComEd (Midwest) | 34.76 | | | 18.96 | | | 15.80 | | | 83.3 | % | Central (New York) | 29.90 | | | 16.36 | | | 13.54 | | | 82.8 | % | North (ERCOT) | 146.63 | | | 22.03 | | | 124.60 | | | 565.6 | % | Southeast Massachusetts (Other)(a) | 46.38 | | | 23.57 | | | 22.81 | | | 96.8 | % |
__________ (a)Reflects New England, which comprises the majority of the activity in the Other region.
For the year ended December 31, 2021 compared to 2020, changes in Operating revenues by region were approximately as follows: | | | | | | | | | | | | | | | | | | | 2021 vs. 2020 | | | | Variance | | % Change(a) | | Description | Mid-Atlantic | $ | (61) | | | (1.3) | % | | • unfavorable wholesale load revenue of $(520) primarily due to lower volumes; partially offset by • favorable settled economic hedges of $365 due to settled prices relative to hedged prices • favorable retail load revenue of $95 primarily due to higher prices | Midwest | 36 | | | 0.9 | % | | • favorable net wholesale load and generation revenue of $540 primarily due to higher prices, partially offset by decreased generation due to higher nuclear outage days • unfavorable settled economic hedges of $(525) due to settled prices relative to hedged prices | New York | 144 | | | 10.1 | % | | • favorable nuclear generation revenue of $75 primarily due to higher prices and lower nuclear outage days • favorable ZEC revenue of $70 due to higher prices and higher nuclear generation | ERCOT | 223 | | | 23.3 | % | | • favorable retail load revenue of $140 primarily due to higher prices in part due to the February 2021 extreme cold weather event • favorable settled economic hedges of $65 due to settled prices relative to hedged prices | Other Power Regions | 888 | | | 22.2 | % | | • favorable settled economic hedges of $655 due to settled prices relative to hedged prices • favorable retail load revenue of $535 due to higher prices and higher volumes; partially offset by • unfavorable wholesale load revenue of $(380) primarily due to lower volumes | Other | 1,559 | | | 64.1 | % | | • favorable gas revenue of $1,375 primarily due to higher prices in part due to the February 2021 extreme cold weather event | Mark-to-market(b) | (743) | | | | | • losses on economic hedging activities of $(633) in 2021 compared to gains of $110 in 2020 | Total | $ | 2,046 | | | 11.6 | % | | |
__________ (a)% Change in mark-to-market is not a meaningful measure. (b)See Note 16 — 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 year ended December 31, 2021 compared to 2020, Purchased power and fuel by region were as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2021 vs. 2020 | | 2021 | | 2020 | | Variance | | % Change(a) | Mid-Atlantic(b) | $ | 2,320 | | | $ | 2,442 | | | $ | 122 | | | 5.0 | % | Midwest(c) | 1,343 | | | 1,121 | | | (222) | | | (19.8) | % | New York | 414 | | | 434 | | | 20 | | | 4.6 | % | ERCOT | 2,006 | | | 532 | | | (1,474) | | | (277.1) | % | Other Power Regions | 3,999 | | | 3,336 | | | (663) | | | (19.9) | % | Total electric purchased power and fuel | 10,082 | | | 7,865 | | | (2,217) | | | (28.2) | % | Other | 3,279 | | | 1,904 | | | (1,375) | | | (72.2) | % | Mark-to-market gains | (1,198) | | | (184) | | | 1,014 | | | | Total purchased power and fuel | $ | 12,163 | | | $ | 9,585 | | | $ | (2,578) | | | (26.9) | % |
__________ (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 year ended December 31, 2021 compared to 2020, changes in Purchased power and fuel by region were approximately as follows: | | | | | | | | | | | | | | | | | | | 2021 vs. 2020 | | | | Variance | | % Change(a) | | Description | Mid-Atlantic | $ | 122 | | | 5.0 | % | | • favorable purchased power and net capacity impact of $80 primarily due to higher nuclear generation, lower load and higher capacity prices earned partially offset by lower cleared capacity volumes • favorable settlement of economic hedges of $70 due to settled prices relative to hedged prices | Midwest | (222) | | | (19.8) | % | | • unfavorable purchased power and net capacity impact of $(330) primarily due to higher energy prices, lower nuclear generation, lower cleared capacity volumes, and lower capacity prices; partially offset by • favorable nuclear fuel cost of $75 primarily due to accelerated amortization of nuclear fuel and lower nuclear fuel prices | New York | 20 | | | 4.6 | % | | • favorable settlement of economic hedges of $45 due to settled prices relative to hedged prices; partially offset by • unfavorable purchased power and net capacity impact of $(40) primarily due to higher energy prices partially offset by higher nuclear generation and higher capacity prices earned | ERCOT | (1,474) | | | (277.1) | % | | • unfavorable purchased power of $(755) primarily due to higher energy prices primarily during the February 2021 extreme cold weather event • unfavorable settlement of economic hedges of $(535) due to settled prices relative to hedged prices • unfavorable fuel cost of $(170) primarily due to higher gas prices | Other Power Regions | (663) | | | (19.9) | % | | • unfavorable purchased power and net capacity impact of $(855) primarily due to higher energy prices, lower generation, lower cleared capacity volumes, and lower capacity prices • unfavorable fuel cost of $(80) primarily due to higher gas prices; partially offset by • net favorable environmental products activity of $270 primarily driven by favorable emissions activity partially offset by unfavorable RPS activity | Other | (1,375) | | | (72.2) | % | | • unfavorable net gas purchase costs and settlement of economic hedges of $(1,150) • unfavorable accelerated nuclear fuel amortization associated with announced early plant retirements of $(90) | Mark-to-market(b) | 1,014 | | | | | • gains on economic hedging activities of $1,198 in 2021 compared to gains of $184 in 2020 | Total | $ | (2,578) | | | (26.9) | % | | |
__________ (a)% Change in mark-to-market is not a meaningful measure. (b)See Note 16 — 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 expense consisted of the following: | | | | | | | 2021 vs. 2020 | | (Decrease) Increase | Plant retirements and divestitures(a) | $ | (484) | | ARO update | (109) | | Labor, other benefits, contracting, and materials | (64) | | Insurance | (45) | | Cost management program | (34) | | Nuclear refueling outage costs, including the co-owned Salem plants | (16) | | Corporate allocations | (14) | | Acquisition related costs | 15 | | Credit loss expense | 21 | | Asset impairments | 27 | | Separation costs | 49 | | Other | 41 | | Total decrease | $ | (613) | |
__________ (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 10 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information. Depreciation and amortization expense increasedfor the year ended December 31, 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 businesses increased for the year ended December 31, 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 a gain on sale of Generation's solar business. Interest expense, net decreased for the year ended December 31, 2021 compared to the same period in 2020, primarily due to decreased expense related to the CR nonrecourse senior secured term loan credit facility and interest rate swaps, and decreases in interest rates. See Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the CR credit facility and interest rate swaps. Other, net decreased for the year ended December 31, 2021 compared to the same period in 2020, due to activity described in the table below:
| | | | | | | | | | | | | 2021 | | 2020 | Net unrealized gains on NDT funds(a) | $ | 204 | | | $ | 391 | | Net realized gains on sale of NDT funds(a) | 381 | | | 70 | | Interest and dividend income on NDT funds(a) | 98 | | | 90 | | Contractual elimination of income tax expense(b) | 226 | | | 180 | | Net unrealized (losses) gains from equity investments(c) | (160) | | | 186 | | Other | 46 | | | 20 | | Total other, net | $ | 795 | | | $ | 937 | |
__________ (a)Unrealized gains, realized gains, and interest and dividend income on the NDT funds are associated with the Non-Regulatory Agreement Units. In addition, also includes unrealized gains, realized gains, and interest and dividend income on the NDT funds associated with the Byron units as decommissioning-related impacts were not offset starting in the second quarter of 2021 due to the inability to recognize a regulatory asset at ComEd. With the 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 Combined Notes to Consolidated Financial Statements for additional information. (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 gains and 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 148.0%and29.8% for the years ended December 31, 2021 and 2020, respectively. The higher effective tax rate in 2021 is primarily due to the impacts of the February 2021 extreme cold weather event on Income before income taxes. See Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information. Net income attributable to noncontrolling interests increased for the year ended December 31, 2021 compared to the same period in 2020, primarily due to CENG's results of operations prior to Generation's acquisition of EDF's interest in CENG on August 6, 2021.
Liquidity and Capital Resources All results included throughout the liquidity and capital resources section are presented on a GAAP basis. The Registrants’ operating and capital expenditures with a combination ofrequirements 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, 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. A broad spectrum 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.). 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 billion, as of December 31, 2021. 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” section below for additional information. The Registrants expect cash flows to be sufficient to meet operating expenses, financing costs, and capital contributions from parent.expenditure requirements. See Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ debt and credit agreements.
Cash Flows from FinancingOperating Activities (All Registrants) 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. Generation's cash flows from operating activities primarily result from the sale of electric energy and energy-related products and services to customers. See Note 3 — Regulatory Matters and Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information on regulatory and legal proceedings and proposed legislation. The following tablestable provides a summary of the change in cash provided by (used in) financingflows from operating activities for the years ended December 31, 2019, 20182021 and 2017:2020 by Registrant: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (Decrease) increase in cash flows from operating activities | Exelon | | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Net income | $ | (125) | | | | | $ | 304 | | | $ | 57 | | | $ | 59 | | | $ | 66 | | | $ | 30 | | | $ | 3 | | | $ | 34 | | Adjustments to reconcile net income to cash: | | | | | | | | | | | | | | | | | | Non-cash operating activities | (332) | | | | | 12 | | | 11 | | | (35) | | | 45 | | | 35 | | | 23 | | | (15) | | Option premiums paid, net | (199) | | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Collateral (posted) received, net | (568) | | | | | (14) | | | — | | | — | | | — | | | — | | | — | | | — | | Income taxes | 187 | | | | | (8) | | | (26) | | | (40) | | | 42 | | | 12 | | | 38 | | | 1 | | Pension and non-pension postretirement benefit contributions | (64) | | | | | (48) | | | — | | | (3) | | | (9) | | | — | | | (1) | | | (1) | | Changes in working capital and other noncurrent assets and liabilities | (122) | | | | | 25 | | | (46) | | | (136) | | | 11 | | | (116) | | | 50 | | | 77 | | (Decrease) increase in cash flows from operating activities | $ | (1,223) | | | | | $ | 271 | | | $ | (4) | | | $ | (155) | | | $ | 155 | | | $ | (39) | | | $ | 113 | | | $ | 96 | |
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, significant operating cash flow impacts for the Registrants for 2021 and 2020 were as follows: •See Note 24 —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. •Option premiums paid relate to options contracts that Generation purchases and sells as part of its established policies and procedures to manage risks associated with market fluctuations in commodity prices. See Note 16 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on derivative contracts. •Depending upon whether Exelon is in a net mark-to-market liability or asset position, collateral may be required 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. See Note 16 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ collateral. •See Note 14 —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 at Exelon resulting from the impact of cash received 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 at Exelon resulting from the impact of certain penalties for natural gas delivery associated with the February 2021 extreme cold weather event at
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2019 vs. 2018 Variance | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Changes in short-term borrowings, net | $ | 869 |
| | $ | 320 |
| | $ | 130 |
| | $ | — |
| | $ | 82 |
| | $ | 200 |
| | $ | 28 |
| | $ | 272 |
| | $ | (100 | ) | Long-term debt, net | (665 | ) | | (645 | ) | | (110 | ) | | 125 |
| | 100 |
| | (123 | ) | | (51 | ) | | (133 | ) | | 63 |
| Changes in Exelon intercompany money pool | — |
| | (146 | ) | | — |
| | — |
| | — |
| | 12 |
| | — |
| | — |
| | — |
| Common stock issued from treasury stock | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Dividends paid on common stock | (76 | ) | | — |
| | (49 | ) | | (52 | ) | | (15 | ) | | — |
| | (44 | ) | | (43 | ) | | (65 | ) | Distributions to member | — |
| | 102 |
| | — |
| | — |
| | — |
| | (200 | ) | | — |
| | — |
| | — |
| Contributions from parent/member | — |
| | (114 | ) | | (250 | ) | | 99 |
| | 84 |
| | 13 |
| | (6 | ) | | (87 | ) | | 108 |
| Sale of noncontrolling interest | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Other financing activities | 33 |
| | 4 |
| | 1 |
| | 16 |
| | (6 | ) | | 4 |
| | 1 |
| | 1 |
| | 2 |
| Net cash flows provided by (used in) financing activities | $ | 161 |
| | $ | (479 | ) | | $ | (278 | ) | | $ | 188 |
| | $ | 245 |
| | $ | (94 | ) | | $ | (72 | ) | | $ | 10 |
| | $ | 8 |
|
Generation and increases in natural gas prices at 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 receivable and on the February 2021 extreme cold weather event, respectively.Cash Flows from Investing Activities (All Registrants) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2018 vs. 2017 Variance | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Changes in short-term borrowings, net | $ | 127 |
| | $ | 699 |
| | $ | — |
| | $ | — |
| | $ | (74 | ) | | $ | 1 |
| | $ | 11 |
| | $ | (432 | ) | | $ | (77 | ) | Long-term debt, net | 599 |
| | (510 | ) | | (65 | ) | | (125 | ) | | 291 |
| | 418 |
| | (3 | ) | | 236 |
| | 104 |
| Changes in Exelon intercompany money pool | — |
| | 47 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Common stock issued from treasury stock | (1,150 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Dividends paid on common stock | (96 | ) | | — |
| | (37 | ) | | (18 | ) | | (11 | ) | | — |
| | (36 | ) | | 16 |
| | 9 |
| Distributions to member | — |
| | (342 | ) | | — |
| | — |
| | — |
| | (15 | ) | | — |
| | — |
| | — |
| Contributions from parent/member | — |
| | 53 |
| | (151 | ) | | 73 |
| | (75 | ) | | (373 | ) | | 5 |
| | 150 |
| | 67 |
| Sale of noncontrolling interest | (396 | ) | | (396 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Other financing activities | (70 | ) | | (1 | ) | | (2 | ) | | (19 | ) | | 3 |
| | (7 | ) | | (3 | ) | | (2 | ) | | (3 | ) | Net cash flows provided by (used in) financing activities | $ | (986 | ) | | $ | (450 | ) | | $ | (255 | ) | | $ | (89 | ) | | $ | 134 |
| | $ | 24 |
| | $ | (26 | ) | | $ | (32 | ) | | $ | 100 |
|
The following table provides a summary of the change in cash flows from investing activities for the years ended December 31, 2021 and 2020 by Registrant: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Increase (decrease) in cash flows from investing activities | Exelon | | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Capital expenditures | $ | 67 | | | | | $ | (170) | | | $ | (93) | | | $ | 21 | | | $ | (116) | | | $ | (70) | | | $ | (5) | | | $ | (44) | | Investment in NDT fund sales, net | (18) | | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | | | | | | | | | | | | | | | | | | Collection of DPP | 131 | | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Proceeds from sales of assets and businesses | 831 | | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Changes in intercompany money pool | — | | | | | — | | | (68) | | | — | | | — | | | — | | | — | | | — | | Other investing activities | 8 | | | | | 24 | | | 2 | | | 16 | | | (5) | | | (1) | | | 7 | | | (5) | | Increase (decrease) in cash flows from investing activities | $ | 1,019 | | | | | $ | (146) | | | $ | (159) | | | $ | 37 | | | $ | (121) | | | $ | (71) | | | $ | 2 | | | $ | (49) | |
Significant investing cash flow impacts for the Registrants for 2019, 20182021 and 20172020 were as follows: | | • | Changes in short-term borrowings, net•Variances in capital expenditures are primarily due to the timing of cash expenditures for capital projects. See the "Credit Matters" section below for additional information on projected capital expenditure spending. •See Note 6 — Accounts Receivable of the Combined Notes to Consolidated Financial Statements for additional information on the Collection of DPP. •Proceeds from sales of assets and businesses increased primarily due to the sale of a significant portion of Exelon's solar business and a biomass facility and proceeds received on sales of equity investments. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information on the sale of Exelon's solar business and biomass facility. •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 (All Registrants) The following table provides a summary of the change in cash flows from financing activities for the years ended December 31, 2021 and 2020 by Registrant: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Increase (decrease) in cash flows from financing activities | Exelon | | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Changes in short-term borrowings, net | $ | 638 | | | | | $ | (516) | | | $ | — | | | $ | 206 | | | $ | (60) | | | $ | 187 | | | $ | (87) | | | $ | (160) | | Long-term debt, net | 774 | | | | | 300 | | | 100 | | | (100) | | | 91 | | | (22) | | | 27 | | | 86 | | Changes in intercompany money pool | — | | | | | — | | | (80) | | | — | | | (23) | | | — | | | — | | | — | | | | | | | | | | | | | | | | | | | | Dividends paid on common stock | (5) | | | | | (8) | | | 1 | | | (46) | | | — | | | (36) | | | (6) | | | (174) | | Acquisition of noncontrolling interest | (885) | | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Distributions to member | — | | | | | — | | | — | | | — | | | (150) | | | — | | | — | | | — | | Contributions from/(to) parent/member | — | | | | | 79 | | | 166 | | | (154) | | | 189 | | | (18) | | | 8 | | | 202 | | | | | | | | | | | | | | | | | | | | Other financing activities | 91 | | | | | (3) | | | (5) | | | 2 | | | (7) | | | — | | | (3) | | | (4) | | Increase (decrease) in cash flows from financing activities | $ | 613 | | | | | $ | (148) | | | $ | 182 | | | $ | (92) | | | $ | 40 | | | $ | 111 | | | $ | (61) | | | $ | (50) | |
, is driven by repayments on and issuances of notes due in less than 90 days. Refer to Note 16 - Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on short-term borrowings.
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| | • | Long-term debt, net, varies due to debt issuances and redemptions each year. Refer to debt issuances and redemptions tables below for more information.
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| | • | Changes in intercompany money pool are driven by short-term borrowing needs. Refer to more information regarding the intercompany money pool below.
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| | • | Exelon issued common stock in 2017 to fund the PHI merger. Refer to Note 19 - Shareholders' Equity of the Combined Notes to Consolidated Financial statements for additional information on common stock issuances.
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| | • | 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 18 - Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information on dividend restrictions. See below for quarterly dividends declared.
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Significant financing cash flow impacts for the Registrants for 2021 and 2020 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 17 - 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 debt issuances and redemptions tables below for additional information. •Changes inintercompany 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 19 - Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements 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. •Other financing activities primarily consists of debt issuance costs. See debt issuances table below for additional information on the Registrants’ debt issuances.
| | • | The change in sale of controlling interest from 2017 to 2018 was primarily related to cash received in 2017 for the sale of a 49% interest in EGRP. Refer to Note 22 - Variable Interest Entities of the Combined Notes to Consolidated Financial Statements for additional information on sale of controlling interest.
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Debt Issuances and Redemptions See Note 1617 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of the Registrants’ debt issuances and retirements.long-term debt. Debt activity for 2019, 20182021 and 20172020 by Registrant was as follows: During 2019,2021, the following long-term debt was issued: | | Company | | Type | | Interest Rate | | Maturity | | Amount | | Use of Proceeds | | Generation | | Energy Efficiency Project Financing(a) | | 3.95 | % | | August 31, 2020 | | $ | 4 |
| | Funding to install energy conservation measures for the Fort Meade project. | | Generation | | Energy Efficiency Project Financing(a) | | 3.46 | % | | May 1, 2020 | | $ | 39 |
| | Funding to install energy conservation measures for the Marine Corps. Logistics Project. | | Generation | | Energy Efficiency Project Financing(a)
| | 2.53 | % | | April 30, 2021 | | $ | 2 |
| | Funding to install energy conservation measures for the Fort AP Hill project. | | Company/Subsidiary | | Company/Subsidiary | | Type | | Interest Rate | | Maturity | | Amount | | Use of Proceeds | Exelon(a) | | Exelon(a) | | Long-Term Software License Agreements | | 3.62 | % | | December 1, 2025 | | $ | 4 | | | Procurement of software licenses. | ComEd | | First Mortgage Bonds, Series 126 | | 4.00 | % | | March 1, 2049 | | $ | 400 |
| | Repay a portion of ComEd’s outstanding commercial paper obligations and fund other general corporate purposes. | 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 127 | | 3.20 | % | | November 15, 2049 | | $ | 300 |
| | Repay a portion of ComEd’s outstanding commercial paper obligations and 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 | | PECO | | First and Refunding Mortgage Bonds | | 3.05 | % | | March 15, 2051 | | 375 | | Funding for general corporate purposes. | PECO | | First and Refunding Mortgage Bonds | | 3.00 | % | | September 15, 2049 | | $ | 325 |
| | Repay short-term borrowings and 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 | | 3.20 | % | | September 15, 2049 | | $ | 400 |
| | Repay commercial paper obligations 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 | | 3.45 | % | | June 13, 2029 | | $ | 150 |
| | Repay existing indebtedness and for general corporate purposes. | Pepco | | First Mortgage Bonds | | 2.32 | % | | March 30, 2031 | | 150 | | Repay existing indebtedness and for general corporate purposes. | Pepco | | Unsecured Tax-Exempt Bonds | | 1.70 | % | | September 1, 2022 | | $ | 110 |
| | Refinance existing indebtedness. | Pepco | | First Mortgage Bonds | | 3.29 | % | | September 28, 2051 | | 125 | | Repay existing indebtedness and for general corporate purposes. | DPL | | First Mortgage Bonds | | 4.14 | % | | December 12, 2049 | | $ | 75 |
| | Repay existing indebtedness and for general corporate purposes. | | DPL(b) | | DPL(b) | | First Mortgage Bonds | | 3.24 | % | | March 30, 2051 | | 125 | | Repay existing indebtedness and for general corporate purposes. | ACE | | First Mortgage Bonds | | 3.50 | % | | May 21, 2029 | | $ | 100 |
| | Repay existing indebtedness and for general corporate purposes. | ACE | | First Mortgage Bonds | | 2.30 | % | | March 15, 2031 | | 350 | | Refinance existing indebtedness, repay outstanding commercial paper obligations, and for general corporate purposes. | ACE | | First Mortgage Bonds | | 4.14 | % | | May 21, 2049 | | $ | 50 |
| | Repay existing indebtedness and for general corporate purposes. | | ACE(c) | | ACE(c) | | First Mortgage Bonds | | 2.27 | % | | February 15, 2032 | | 75 | | Repay existing indebtedness and for general corporate purposes. | Generation | | Generation | | West Medway II Nonrecourse Debt(d) | | LIBOR + 3%(e) | | March 31, 2026 | | 150 | | Funding for general corporate purposes. | Generation | | Generation | | Energy Efficiency Project Financing(f) | | 2.53% - 4.24% | | January 31, 2022 - February 28, 2022 | | 2 | | Funding to install energy conservation measures. | |
__________ | | (a) | For Energy Efficiency Project Financing, the maturity dates represent the expected date of project completion, upon which the respective customer assumes the outstanding debt. |
(a)In connection with the separation, Exelon Corporate entered into three 18-month term loan agreements. On January 21, 2022, two of the loan agreements were issued for $300 million each with an expiration date of July 21, 2023. On January 24, 2022, the third loan agreement was issued for $250 million with an expiration date of July 24, 2023. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to SOFR plus 0.65%.
(b)On November 16, 2021, DPL entered into a purchase agreement of First Mortgage Bonds of $125 million at 3.06% due on February 15, 2052. The closing date of the issuance occurred on February 15, 2022. (c)On November 16, 2021, ACE entered into a purchase agreement of First Mortgage Bonds of $25 million and $150 million at 2.27% and 3.06% due on February 15, 2032 and February 15, 2052, respectively. The closing date of the issuance occurred on February 15, 2022. (d)See Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on nonrecourse debt. (e)The nonrecourse debt has an average blended interest rate.
(f)For Energy Efficiency Project Financing, the maturity dates represent the expected date of project completion, upon which the respective customer assumes the outstanding debt.
During 2018,2020, the following long termlong-term debt was issued: | | Company | | Type | | Interest Rate | | Maturity | | Amount | | Use of Proceeds | | Generation | | Energy Efficiency Project Financing(a) | | 3.72 | % | | March 31, 2019 | | $ | 4 |
| | Funding to install energy conservation measures for the Smithsonian Zoo project. | | Generation | | Energy Efficiency Project Financing(a) | | 3.17 | % | | January 31, 2019 | | $ | 1 |
| | Funding to install energy conservation measures in Brooklyn, NY. | | Generation | | Energy Efficiency Project Financing(a) | | 2.61 | % | | September 30, 2018 | | $ | 5 |
| | Funding to install energy conservation measures for the Pensacola project. | | Generation | | Energy Efficiency Project Financing(a) | | 4.17 | % | | January 31, 2019 | | $ | 1 |
| | Funding to install energy conservation measures for the General Services Administration Philadelphia project. | | Generation | | Energy Efficiency Project Financing(a) | | 4.26 | % | | May 31, 2019 | | $ | 3 |
| | Funding to install energy conservation measures for the National Institutes of Health Multi-Buildings Phase II project. | | Company/Subsidiary | | Company/Subsidiary | | Type | | Interest Rate | | Maturity | | Amount | | Use of Proceeds | Exelon | | Exelon | | Notes | | 4.05 | % | | April 15, 2030 | | $ | 1,250 | | | Repay existing indebtedness and for general corporate purposes. | Exelon | | Exelon | | Notes | | 4.70 | % | | April 15, 2050 | | 750 | | Repay existing indebtedness and for general corporate purposes. | ComEd | | First Mortgage Bonds, Series 124 | | 4.00 | % | | March 1, 2048 | | $ | 800 |
| | Refinance one series of maturing first mortgage bonds, to repay a portion of ComEd’s outstanding commercial paper obligations and to fund general corporate purposes. | ComEd | | First Mortgage Bonds, Series 128 | | 2.20 | % | | March 1, 2030 | | 350 | | Repay a portion of outstanding commercial paper obligations and fund other general corporate purposes. | ComEd | | First Mortgage Bonds, Series 125 | | 3.70 | % | | August 15, 2028 | | $ | 550 |
| | Repay a portion of ComEd’s outstanding commercial paper obligations and for general corporate purposes. | ComEd | | First Mortgage Bonds, Series 129 | | 3.00 | % | | March 1, 2050 | | 650 | | Repay a portion of outstanding commercial paper obligations and fund other general corporate purposes. | PECO | | First and Refunding Mortgage Bonds | | 3.90 | % | | March 1, 2048 | | $ | 325 |
| | Refinance a portion of maturing mortgage bonds. | | PECO | | Loan Agreement | | 2.00 | % | | June 20, 2023 | | $ | 50 |
| | Funding to implement Electric Long-term Infrastructure Improvement Plan. | | PECO | | First and Refunding Mortgage Bonds | | 3.90 | % | | March 1, 2048 | | $ | 325 |
| | Satisfy short-term borrowings from the Exelon intercompany money pool and for general corporate purposes. | PECO | | First and Refunding Mortgage Bonds | | 2.80 | % | | June 15, 2050 | | 350 | | Funding for general corporate purposes. | BGE | | Senior Notes | | 4.25 | % | | September 15, 2048 | | $ | 300 |
| | Repay commercial paper obligations and for general corporate purposes. | BGE | | Senior Notes | | 2.90 | % | | June 15, 2050 | | 400 | | Repay commercial paper obligations and for general corporate purposes. | Pepco | | First Mortgage Bonds | | 4.27 | % | | June 15, 2048 | | $ | 100 |
| | Repay outstanding commercial paper and for general corporate purposes. | Pepco | | First Mortgage Bonds | | 2.53 | % | | February 25, 2030 | | 150 | | Repay existing indebtedness and for general corporate purposes. | Pepco | | First Mortgage Bonds | | 4.31 | % | | November 1, 2048 | | $ | 100 |
| | Repay outstanding commercial paper and for general corporate purposes. | Pepco | | First Mortgage Bonds | | 3.28 | % | | September 23, 2050 | | 150 | | Repay existing indebtedness and for general corporate purposes. | DPL | | First Mortgage Bonds | | 4.27 | % | | June 15, 2048 | | $ | 200 |
| | Repay outstanding commercial paper and for general corporate purposes. | DPL | | First Mortgage Bonds | | 2.53 | % | | June 9, 2030 | | 100 | | Repay existing indebtedness and for general corporate purposes. | DPL | | DPL | | Tax-Exempt Bonds(a) | | 1.05 | % | | January 1, 2031 | | 78 | | Refinance existing indebtedness. | ACE | | First Mortgage Bonds | | 4.00 | % | | October 15, 2028 | | $ | 350 |
| | Refinance ACE’s 7.75% First Mortgage Bonds due November 15, 2018, reduce short-term borrowings and for general corporate purposes. | ACE | | Tax-Exempt First Mortgage Bonds | | 2.25 | % | | June 1, 2029 | | 23 | | Refinance existing indebtedness. | ACE | | ACE | | First Mortgage Bonds | | 3.24 | % | | June 9, 2050 | | 100 | | Repay existing indebtedness and for general corporate purposes. | Generation | | Generation | | Senior Notes | | 3.25 | % | | June 1, 2025 | | 900 | | Repay existing indebtedness and for general corporate purposes. | Generation | | Generation | | Constellation Renewables Nonrecourse Debt(b) | | LIBOR + 2.75% | | December 15, 2027 | | 750 | | Repay existing indebtedness and for general corporate purposes. | Generation | | Generation | | Energy Efficiency Project Financing(c) | | 2.53% - 3.95% | | February 28, 2021 - March 31, 2021 | | 6 | | Funding to install energy conservation measures. |
__________ | | (a) | For Energy Efficiency Project Financing, the maturity dates represent the expected date of project completion, upon which the respective customer assumes the outstanding debt. |
(a)The bonds have a 1.05% interest rate through July 2025.
(b)See Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on nonrecourse debt.
(c)For Energy Efficiency Project Financing, the maturity dates represent the expected date of project completion, upon which the respective customer assumes the outstanding debt.
During 2017, the following long term-debt was issued: | | | | | | | | | | | | | | | Company | | Type | | Interest Rate | | Maturity | | Amount | | Use of Proceeds | Exelon Corporate | | Junior Subordinated Notes | | 3.50 | % | | June 1, 2022 | | $ | 1,150 |
| | Refinance Exelon's Junior Subordinated Notes issued in June 2014. | Generation | | Albany Green Energy Project Financing(a) | | LIBOR + 1.25% |
| | November 17, 2017 | | $ | 14 |
| | Albany Green Energy biomass generation development. | Generation | | Energy Efficiency Project Financing(a) | | 3.90 | % | | February 1, 2018 | | $ | 19 |
| | Funding to install energy conservation measures for the Naval Station Great Lakes project. | Generation | | Energy Efficiency Project Financing(a) | | 3.72 | % | | May 1, 2018 | | $ | 5 |
| | Funding to install energy conservation measures for the Smithsonian Zoo project. | Generation | | Energy Efficiency Project Financing(a) | | 2.61 | % | | September 30, 2018 | | $ | 13 |
| | Funding to install energy conservation measures for the Pensacola project. | Generation | | Energy Efficiency Project Financing(a) | | 3.53 | % | | April 1, 2019 | | $ | 8 |
| | Funding to install energy conservation measures for the State Department project. | Generation | | Senior Notes | | 2.95 | % | | January 15, 2020 | | $ | 250 |
| | Repay outstanding commercial paper obligations and for general corporate purposes. | Generation | | Senior Notes | | 3.40 | % | | March 15, 2020 | | $ | 500 |
| | Repay outstanding commercial paper obligations and for general corporate purposes. | Generation | | ExGen Texas Power Nonrecourse Debt(b)(c) | | LIBOR + 4.75% |
| | September 18, 2021 | | $ | 6 |
| | General corporate purposes. | Generation | | ExGen Renewables IV, Nonrecourse Debt(b) | | LIBOR + 3.00% |
| | November 30, 2024 | | $ | 850 |
| | General corporate purposes. | ComEd | | First Mortgage Bonds, Series 122 | | 2.95 | % | | August 15, 2027 | | $ | 350 |
| | Refinance maturing mortgage bonds, repay a portion of ComEd’s outstanding commercial paper obligations and for general corporate purposes. | ComEd | | First Mortgage Bonds, Series 123 | | 3.75 | % | | August 15, 2047 | | $ | 650 |
| | Refinance maturing mortgage bonds, repay a portion of ComEd’s outstanding commercial paper obligations and for general corporate purposes. | PECO | | First and Refunding Mortgage Bonds | | 3.70 | % | | September 15, 2047 | | $ | 325 |
| | General corporate purposes. | BGE | | Senior Notes | | 3.75 | % | | August 15, 2047 | | $ | 300 |
| | Redeem $250 million in principal amount of the 6.20% Deferrable Interest Subordinated Debentures due October 15, 2043 issued by BGE's affiliate BGE Capital Trust II, repay commercial paper obligations and for general corporate purposes. | Pepco | | Energy Efficiency Project Financing(a) | | 3.30 | % | | December 15, 2017 | | $ | 2 |
| | Funding to install energy conservation measures for the DOE Germantown project. | Pepco | | First Mortgage Bonds | | 4.15 | % | | March 15, 2043 | | $ | 200 |
| | Funding to repay outstanding commercial paper and for general corporate purposes. |
__________
| | (a) | For Energy Efficiency Project Financing, the maturity dates represent the expected date of project completion, upon which the respective customer assumes the outstanding debt. |
| | (b) | See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of nonrecourse debt. |
| | (c) | As a result of the bankruptcy filing for EGTP on November 7, 2017, the nonrecourse debt was deconsolidated from Exelon's and Generation's consolidated financial statements. See Note 2 — Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information. |
During 2019,2021, the following long-term debt was retired and/or redeemed:
| | Company(a) | | Type | | Interest Rate | | Maturity | | Amount | | Company/Subsidiary | | Company/Subsidiary | | Type | | Interest Rate | | Maturity | | Amount | Exelon | | Long-Term Software License Agreement | | 3.95% | | May 1, 2024 | | $ | 18 |
| Exelon | | Senior Notes(a) | | 2.45% | | April 15, 2021 | | $ | 300 | | Exelon | | Exelon | | Long-Term Software License Agreements | | 3.95% | | May 1, 2024 | | 24 | Exelon | | Exelon | | Long-Term Software License Agreements | | 3.62% | | December 1, 2025 | | 1 | | ComEd | | ComEd | | First Mortgage Bonds | | 3.40% | | September 1, 2021 | | 350 | PECO | | PECO | | First Mortgage Bonds | | 1.70% | | September 15, 2021 | | 300 | BGE | | BGE | | Senior Notes | | 3.50% | | November 15, 2021 | | 300 | ACE | | ACE | | First Mortgage Bonds | | 4.35% | | April 1, 2021 | | 200 | ACE | | ACE | | Tax-Exempt First Mortgage Bonds | | 6.80% | | March 1, 2021 | | 39 | ACE | | ACE | | Transition Bonds | | 5.55% | | October 20, 2021 | | 21 | Generation | | Antelope Valley DOE Nonrecourse Debt(b) | | 2.33% - 3.56% | | January 5, 2037 | | $ | 23 |
| Generation | | Continental Wind Nonrecourse Debt(b) | | 6.00% | | February 28, 2033 | | 35 | Generation | | Kennett Square Capital Lease | | 7.83% | | September 20, 2020 | | $ | 5 |
| Generation | | CR Nonrecourse Debt(b) | | 3-month LIBOR + 2.50%(c) | | December 15, 2027 | | 17 | Generation | | Continental Wind Nonrecourse Debt(b) | | 6.00% | | February 28, 2033 | | $ | 32 |
| Generation | | SolGen Nonrecourse Debt(b) | | 3.93% | | September 30, 2036 | | 7 | Generation | | Pollution control notes | | 2.50% | | March 1, 2019 | | $ | 23 |
| Generation | | Antelope Valley DOE Nonrecourse Debt(b) | | 2.29% - 3.56% | | January 5, 2037 | | 24 | Generation | | Renewable Power Generation Nonrecourse Debt(b) | | 4.11% | | March 31, 2035 | | $ | 10 |
| Generation | | West Medway II Nonrecourse Debt(b) | | LIBOR + 3%(d) | | March 31, 2026 | | 13 | Generation | | Energy Efficiency Project Financing | | 3.46% | | April 30, 2019 | | $ | 39 |
| Generation | | RPG Nonrecourse Debt(b) | | 4.11% | | March 31, 2035 | | 9 | Generation | | ExGen Renewables IV Nonrecourse debt(b) | | 3mL +3% | | November 30, 2024 | | $ | 38 |
| | Generation | | Hannie Mae, LLC Defense Financing | | 4.12% | | November 30, 2019 | | $ | 1 |
| | Generation | | Energy Efficiency Project Financing | | 3.72% | | July 31, 2019 | | $ | 25 |
| | Generation | | NUKEM | | 3.15% | | September 30, 2020 | | $ | 36 |
| | Generation | | SolGen Nonrecourse Debt(b) | | 3.93% | | September 30, 2036 | | $ | 6 |
| | Generation | | Energy Efficiency Project Financing | | 4.17% | | October 31, 2019 | | $ | 1 |
| | Generation | | Energy Efficiency Project Financing | | 3.53% | | March 31, 2020 | | $ | 1 |
| | Generation | | Energy Efficiency Project Financing | | 4.26% | | September 30, 2019 | | $ | 1 |
| | Generation | | Senior Notes | | 5.20% | | October 1, 2019 | | $ | 600 |
| | Generation | | Dominion Federal Corp | | 3.17% | | October 31, 2019 | | $ | 18 |
| | Generation | | Fort Detrick Project Financing | | 3.55% | | October 31, 2019 | | $ | 1 |
| | ComEd | | First Mortgage Bonds | | 2.15% | | January 15, 2019 | | $ | 300 |
| | Pepco | | Secured Tax-Exempt Bonds | | 6.20% - 7.49% | | 2021 - 2022 | | $ | 110 |
| | DPL | | Medium Term Notes, Unsecured | | 7.61% | | December 2, 2019 | | $ | 12 |
| | ACE | | Transition Bonds | | 5.55% | | October 20, 2023 | | $ | 18 |
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__________ | | (a) | On January 15, 2020, Generation redeemed $1 billion of 2.95% Senior Notes at maturity. |
| | (b) | See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of nonrecourse debt. |
(a)As part of the 2012 Constellation merger, Exelon entered intercompany loan agreements that mirrored the terms and amounts of the third-party debt obligations. In connection with the separation, on January 31, 2022, Exelon Corporate received cash from Generation of $258 million to settle the intercompany loan. See Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the mirror debt.
(b)See Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements 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.
During 2018,2020, the following long-term debt was retired and/or redeemed: | | Company | | Type | | Interest Rate | | Maturity | | Amount | | Exelon Corporate | | Long-Term Software License Agreement | | 3.95% | | May 1, 2024 | | $ | 6 |
| | Company/Subsidiary | | Company/Subsidiary | | Type | | Interest Rate | | Maturity | | Amount | Exelon | | Exelon | | Notes | | 2.85% | | June 15, 2020 | | $ | 900 | | Exelon | | Exelon | | Long-Term Software License Agreements | | 3.95% | | May 1, 2024 | | 24 | ComEd | | ComEd | | First Mortgage Bonds | | 4.00% | | August 1, 2020 | | 500 | DPL | | DPL | | Tax-Exempt Bonds | | 5.40% | | February 1, 2031 | | 78 | ACE | | ACE | | Tax-Exempt First Mortgage Bonds | | 4.88% | | June 1, 2029 | | 23 | ACE | | ACE | | Transition Bonds | | 5.55% | | October 20, 2023 | | 20 | Generation | | Naval Station Great Lakes Project Financing | | 3.90% | | June 30, 2018 | | $ | 41 |
| Generation | | Senior Notes | | 2.95% | | January 15, 2020 | | 1,000 | Generation | | Smithsonian Zoo Project Financing | | 3.72% | | March 31, 2019 | | $ | 1 |
| Generation | | Senior Notes | | 4.00% | | October 1, 2020 | | 550 | Generation | | Pensacola Project Financing | | 2.61% | | September 30, 2018 | | $ | 21 |
| Generation | | Senior Notes(a) | | 5.15% | | December 1, 2020 | | 550 | Generation | | Fort Detrick Project Financing | | 3.55% | | June 30, 2019 | | $ | 19 |
| Generation | | Tax-Exempt Bonds | | 2.50% - 2.70% | | December 1, 2025 - June 1, 2036 | | 412 | Generation | | Holyoke Nonrecourse Debt(a) | | 5.25% | | December 31, 2031 | | $ | 1 |
| Generation | | CR Nonrecourse Debt(b) | | 3-month LIBOR + 3.00% | | November 30, 2024 | | 796 | Generation | | SolGen Nonrecourse Debt(a) | | 3.93% | | September 30, 2036 | | $ | 10 |
| Generation | | Continental Wind Nonrecourse Debt(b) | | 6.00% | | February 28, 2033 | | 33 | Generation | | Antelope Valley DOE Nonrecourse Debt(a) | | 2.29% - 3.56% | | January 5, 2037 | | $ | 22 |
| Generation | | Antelope Valley DOE Nonrecourse Debt(b) | | 2.29% - 3.56% | | January 5, 2037 | | 23 | Generation | | Continental Wind Nonrecourse Debt(a) | | 6.00% | | February 28, 2033 | | $ | 33 |
| Generation | | RPG Nonrecourse Debt(b) | | 4.11% | | March 31, 2035 | | 9 | Generation | | Renewable Power Generation Nonrecourse Debt(a) | | 4.11% | | March 31, 2035 | | $ | 11 |
| Generation | | Energy Efficiency Project Financing | | 3.71% | | December 31, 2020 | | 4 | Generation | | Kennett Square Capital Lease | | 7.83% | | September 20, 2020 | | $ | 4 |
| Generation | | NUKEM | | 3.15% | | September 30, 2020 | | 3 | Generation | | ExGen Renewables IV Nonrecourse Debt(a) | | 3mL+300 bps | | November 30, 2024 | | $ | 16 |
| Generation | | SolGen Nonrecourse Debt | | 3.93% | | September 30, 2036 | | 3 | Generation | | NUKEM | | 3.15% - 3.35% | | 2018 - 2020 | | $ | 43 |
| Generation | | Energy Efficiency Project Financing | | 4.12% | | November 30, 2020 | | 1 | ComEd | | First Mortgage Bonds | | 5.80% | | March 15, 2018 | | $ | 700 |
| | ComEd | | Notes | | 6.95% | | July 15, 2018 | | $ | 140 |
| | PECO | | First Mortgage Bonds | | 5.35% | | March 1, 2018 | | $ | 500 |
| | DPL | | Medium Term Notes, Unsecured | | 6.81% | | January 9, 2018 | | $ | 4 |
| | Pepco | | Notes | | 3.30% | | August 31, 2018 | | $ | 5 |
| | Pepco | | Third Party Financing | | 7.28-7.99% | | 2021 - 2023 | | $ | 1 |
| | ACE | | First Mortgage Bonds | | 7.75% | | November 15, 2018 | | $ | 250 |
| | ACE | | Transition Bonds | | 5.05% - 5.55% | | 2020 - 2023 | | $ | 31 |
| | |
__________ | | (a) | See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of nonrecourse debt. |
(a)The senior notes are legacy Constellation mirror debt that were previously held at Exelon. As part of the 2012 Constellation merger, Exelon assumed intercompany loan agreements that mirrored the terms and amounts of external obligations held by Exelon. See Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.
During 2017,(b)See Note 17 — Debt and Credit Agreements of the following long-term debt was retired and/or redeemed:Combined Notes to Consolidated Financial Statements for additional information of nonrecourse debt.
| | | | | | | | | | | | Company | | Type | | Interest Rate | | Maturity | | Amount | Exelon Corporate | | Long-Term Software License Agreement | | 3.95% | | May 1, 2024 | | $ | 24 |
| Exelon Corporate | | Senior Notes | | 1.55% | | June 9, 2017 | | $ | 550 |
| Generation | | Senior Notes - Exelon Wind | | 2.00% | | July 31, 2017 | | $ | 1 |
| Generation | | CEU Upstream Nonrecourse Debt(a) | | LIBOR + 2.25% | | January 14, 2019 | | $ | 6 |
| Generation | | SolGen Nonrecourse Debt(a) | | 3.93% | | September 30, 2036 | | $ | 2 |
| Generation | | Antelope Valley DOE Nonrecourse Debt(a) | | 2.29% - 3.56% | | January 5, 2037 | | $ | 22 |
| Generation | | Kennett Square Capital Lease | | 7.83% | | September 20, 2020 | | $ | 2 |
| Generation | | Continental Wind Nonrecourse Debt(a) | | 6.00% | | February 28, 2033 | | $ | 31 |
| Generation | | PES - PGOV Notes Payable | | 6.70-7.60% | | 2017 - 2018 | | $ | 1 |
| Generation | | ExGen Texas Power Nonrecourse Debt (a)(b) | | LIBOR + 4.75% | | September 18, 2021 | | $ | 665 |
| Generation | | Renewable Power Generation Nonrecourse Debt(a) | | 4.11% | | March 31, 2035 | | $ | 14 |
| Generation | | NUKEM | | 3.25% - 3.35% | | June 30, 2018 | | $ | 23 |
| Generation | | ExGen Renewables I, Nonrecourse Debt(a) | | LIBOR + 4.25% | | February 6, 2021 | | $ | 233 |
| Generation | | Senior Notes | | 6.20% | | October 1, 2017 | | $ | 700 |
| Generation | | Albany Green Energy Project Financing | | LIBOR + 1.25% | | November 17, 2017 | | $ | 212 |
| ComEd | | First Mortgage Bonds | | 6.15% | | September 15, 2017 | | $ | 425 |
| BGE | | Rate Stabilization Bonds | | 5.82% | | April 1, 2017 | | $ | 41 |
| BGE | | Capital Trust Preferred Securities | | 6.20% | | October 15, 2043 | | $ | 258 |
| PHI | | Senior Notes | | 6.13% | | June 1, 2017 | | $ | 81 |
| DPL | | Medium Term Notes, Unsecured | | 7.56% - 7.58% | | February 1, 2017 | | $ | 14 |
| DPL | | Variable Rate Demand Bonds | | Variable | | October 1, 2017 | | $ | 26 |
| Pepco | | Third Party Financing | | 6.97% - 7.99% | | 2018 - 2022 | | $ | 1 |
| ACE | | Transition Bonds | | 5.05% - 5.55% | | 2020 - 2023 | | $ | 35 |
|
__________
| | (a) | See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of nonrecourse debt. |
| | (b) | As a result of the bankruptcy filing for EGTP on November 7, 2017, the nonrecourse debt was deconsolidated from Exelon's and Generation's consolidated financial statements. See Note 2 — Mergers, Acquisitions and Dispositions for additional information. |
From time to time and as market conditions warrant, the Registrants may engage in long-term debt retirements via tender offers, open market repurchases or other viable options to reduce debt on their respective balance sheets.
Dividends Quarterly dividends declared by the Exelon Board of Directors during the year ended December 31, 20192021 and for the first quarter of 20202022 were as follows: | | | | | | | | | | | | Period | | Declaration Date | | Shareholder of Record Date | | Dividend Payable Date | | Cash per Share(a) | First Quarter 2019 | | February 5, 2019 | | February 20, 2019 | | March 8, 2019 | | $ | 0.3625 |
| Second Quarter 2019 | | April 30, 2019 | | May 15, 2019 | | June 10, 2019 | | $ | 0.3625 |
| Third Quarter 2019 | | July 30, 2019 | | August 15, 2019 | | September 10, 2019 | | $ | 0.3625 |
| Fourth Quarter 2019 | | November 1, 2019 | | November 15, 2019 | | December 10, 2019 | | $ | 0.3625 |
| First Quarter 2020 | | January 28, 2020 | | February 20, 2020 | | March 10, 2020 | | $ | 0.3825 |
|
___________
| | | | | | | | | | | | | | | | | | | | | | | | | | | (a)Period | Exelon's Board | Declaration Date | | Shareholder of Directors approved an updated dividend policy providing an increase of 5% each year for the period covering 2018 through 2020, beginning with the Record Date | | Dividend Payable Date | | Cash per Share(a) | First Quarter 2021 | | February 21, 2021 | | March 2018 dividend.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 | | First Quarter 2022 | | February 8, 2022 | | February 25, 2022 | | March 10, 2022 | | $ | 0.3375 | |
Other
For the year ended December 31, 2019, other financing activities primarily consists___________
(a)Exelon's Board of debt issuance costs. See Note 16 — Debt and Credit AgreementsDirectors approved an updated dividend policy for 2022. The 2022 quarterly dividend will be $0.3375 per share.
Credit Matters Market Conditions and Cash Requirements (All Registrants)
The Registrants fund liquidity needs for capital investment,expenditures, 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 $10.6$10.3 billion in aggregate total commitments of which $7.4$6.5 billion was available to support additional commercial paper as of December 31, 2019,2021, and of which no financial institution has more than 7% of the aggregate commitments for the Registrants. 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 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. The Registrants had access to the commercial paper marketmarkets and had availability under their revolving credit facilities during 20192021 to fund their short-term liquidity needs, when necessary. Exelon and Generation used their available credit facilities to manage short-term liquidity needs as a result of the impacts of the February 2021 extreme cold weather event. 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.I, ITEM 1A. RISK FACTORS 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 asliquidity to support the estimated future cash requirements discussed below. Pursuant to the Separation Agreement between Exelon and Constellation Energy Corporation, Exelon made a cash payment of December 31, 2019, it would have been required to provide incremental collateral of $1.5$1.75 billion to meet collateral obligations for derivatives, non-derivatives, normal purchases and normal sales contracts and applicable payables and receivables, netGeneration on January 31, 2022. See Note 26 — Separation of the contractual right of offset under master netting agreements, which is well withinCombined Notes to Consolidated Financial Statements for additional information on the $4.2 billion of available credit capacity of its revolver.
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 December 31, 20192021 and available credit facility capacity prior to any incremental collateral at December 31, 2019:2021: | | | PJM Credit Policy Collateral | | Other Incremental Collateral Required(a) | | Available Credit Facility Capacity Prior to Any Incremental Collateral | | PJM Credit Policy Collateral | | Other Incremental Collateral Required(a) | | Available Credit Facility Capacity Prior to Any Incremental Collateral | ComEd | $ | 11 |
| | $ | — |
| | $ | 868 |
| ComEd | $ | 28 | | | $ | — | | | $ | 998 | | PECO | — |
| | 44 |
| | 600 |
| PECO | 1 | | | 37 | | | 600 | | BGE | 11 |
| | 50 |
| | 524 |
| BGE | 4 | | | 78 | | | 470 | | Pepco | 11 |
| | — |
| | 218 |
| Pepco | 3 | | | — | | | 125 | | DPL | 4 |
| | 11 |
| | 244 |
| DPL | 4 | | | 14 | | | 151 | | ACE | — |
| | — |
| | 230 |
| ACE | 1 | | | — | | | 155 | |
__________ (a)Represents incremental collateral related to natural gas procurement contracts.
Capital Expenditures As of December 31, 2021, estimates of capital expenditures for plant additions and improvements are as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (in millions) | 2022 Transmission | | 2022 Distribution | | 2022 Gas | | Total 2022(b) | | Beyond 2022(b)(c) | Exelon(a) | N/A | | N/A | | N/A | | $ | 8,600 | | | $ | 24,950 | | | | | | | | | | | | ComEd | 450 | | | 2,025 | | | N/A | | 2,475 | | | 7,775 | | PECO | 175 | | | 850 | | | 325 | | | 1,325 | | | 4,500 | | BGE | 275 | | | 500 | | | 475 | | | 1,225 | | | 4,100 | | PHI | 600 | | | 1,175 | | | 100 | | | 1,850 | | | 5,650 | | Pepco | 275 | | | 625 | | | N/A | | 900 | | | 2,750 | | DPL | 150 | | | 250 | | | 100 | | | 475 | | | 1,550 | | ACE | 175 | | | 300 | | | N/A | | 475 | | | 1,375 | |
___________ (a)Exelon's estimated capital expenditures include estimated capital expenditures for Generation. (b)Numbers rounded to the nearest $25M and may not sum due to rounding. (c)Includes estimated capital expenditures for the Utility Registrants from 2023 and 2025 and includes estimated capital expenditures for Generation from 2023 to 2024. Projected capital expenditures and other investments are subject to periodic review and revision to reflect changes in economic conditions and other factors. Projected capital expenditures at the Utility Registrants are for continuing projects to maintain and improve operations, including enhancing reliability and adding capacity to the transmission and distribution systems. The Utility Registrants anticipate that they will fund their capital expenditures with a combination of internally generated funds and borrowings and additional capital contributions from parent. Pension and Other Postretirement Benefits Management 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 pension obligation, and regulatory implications. The Act requires the attainment of certain funding levels to avoid benefit restrictions (such as an inability to pay lump sums or to accrue benefits prospectively), and at-risk status (which triggers higher minimum contribution requirements and participant notification). The projected contributions below 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. Based on this funding strategy and current market conditions, which are subject to change, Exelon’s estimated annual qualified pension contributions will be approximately $500 million in 2022. Exelon's estimated contributions include contributions related to Generation's qualified pension plans. In connection with the separation, an additional qualified pension contribution of $207 million was completed on February 1, 2022. 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 plans. For Exelon's funded OPEB plans, contributions generally equal accounting costs, however, Exelon’s management has historically considered several factors in determining the level of contributions to its OPEB plans, including liabilities management, levels of benefit claims paid, and regulatory implications (amounts deemed prudent to meet regulatory expectations and best assure continued rate recovery). The amounts below include benefit payments related to unfunded plans.
The following table provides all Registrants' planned contributions to the qualified pension plans, planned benefit payments to non-qualified pension plans, and planned contributions to OPEB plans in 2022: | | | | | | | | | | | | | | | | | | | Qualified Pension Plans | | Non-Qualified Pension Plans | | OPEB | Exelon(a) | $ | 505 | | | $ | 32 | | | $ | 50 | | | | | | | | ComEd | 173 | | | 2 | | | 12 | | PECO | 12 | | | 1 | | | 2 | | BGE | 48 | | | 2 | | | 16 | | | | | | | | PHI | 60 | | | 10 | | | 7 | | Pepco | 2 | | | 1 | | | 6 | | DPL | 1 | | | 1 | | | — | | ACE | 7 | | | — | | | — | | | | | | | | _________(a)Exelon's estimated contributions include contributions related to Generation's qualified pension plans. These payments are based on the combined plans, as of December 31, 2021 and do not reflect the impacts of the separation. To the extent interest rates decline significantly or the pension and OPEB plans earn less than the expected asset returns, annual pension contribution requirements in future years could increase. Conversely, to the extent interest rates increase significantly or the pension and OPEB plans earn greater than the expected asset returns, annual pension and OPEB contribution requirements in future years could decrease. Additionally, expected contributions could change if Exelon changes its pension or OPEB funding strategy. See Note 15 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information on pension and OPEB contributions. Cash Requirements for Other Financial Commitments The following tables summarize the Registrants' future estimated cash payments as of December 31, 2021 under existing financial commitments:
Exelon | | | | | | | | | | | | | | | | | | | | | | | | | 2022(a) | | Beyond 2022(a) | | Total(a) | | Time Period | Long-term debt(b) | $ | 3,357 | | | $ | 35,300 | | | $ | 38,657 | | | 2022 - 2053 | Interest payments on long-term debt(c) | 1,509 | | | 23,670 | | | 25,179 | | | 2022 - 2051 | Operating leases(d) | 99 | | | 937 | | | 1,036 | | | 2022 - 2106 | Purchase power obligations(e) | 620 | | | 1,109 | | | 1,729 | | | 2022 - 2036 | Fuel purchase agreements(f) | 1,303 | | | 5,446 | | | 6,749 | | | 2022 - 2054 | Electric supply procurement | 2,122 | | | 1,254 | | | 3,376 | | | 2022 - 2025 | Long-term renewable energy and REC commitments | 302 | | | 1,691 | | | 1,993 | | | 2022 - 2033 | Other purchase obligations(g) | 5,247 | | | 5,806 | | | 11,053 | | | 2022 - 2046 | DC PLUG obligation | 33 | | | 37 | | | 70 | | | 2022 - 2024 | SNF obligation | — | | | 1,210 | | | 1,210 | | | 2022 - 2035 | | | | | | | | | Pension contributions(h) | 505 | | | 190 | | | 695 | | | 2022 - 2027 | Total cash requirements | $ | 15,097 | | | $ | 76,650 | | | $ | 91,747 | | | |
__________ (a)Exelon's future estimated cash payments include future estimated cash payments for Generation. (b)Includes amounts from ComEd and PECO financing trusts. (c)Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2021 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2021. Includes estimated interest payments due to ComEd and PECO financing trusts. (d)Capacity payments associated with contracted generation lease agreements are net of sublease and capacity offsets of $57 million and $315 million for 2022 and beyond 2022, respectively, and $372 million in total. (e)Purchase power obligations primarily include expected payments for REC purchases and payments associated with contracted generation agreements, which may be reduced based on plant availability. Expected payments exclude payments on renewable generation contracts that are contingent in nature. (f)Represents commitments to purchase nuclear fuel, natural gas and related transportation, storage capacity, and services. (g)Represents the future estimated value at December 31, 2021 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between the Registrants or subsidiary and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period. (h)These amounts represent Exelon’s expected contributions to its qualified pension plans. Qualified pension contributions for years after 2027 are not included.
ComEd | | | | | | | | | | | | | | | | | | | | | | | | | 2022 | | Beyond 2022 | | Total | | Time Period | Long-term debt(a) | $ | — | | | $ | 10,084 | | | $ | 10,084 | | | 2022 - 2053 | Interest payments on long-term debt(b) | 394 | | | 7,467 | | | 7,861 | | | 2022 - 2051 | Operating leases | 2 | | | 3 | | | 5 | | | 2022 - 2025 | Electric supply procurement | 474 | | | 260 | | | 734 | | | 2022 - 2024 | Long-term renewable energy and REC commitments | 271 | | | 1,438 | | | 1,709 | | | 2022 - 2033 | Other purchase obligations(c) | 858 | | | 764 | | | 1,622 | | | 2022 - 2031 | ZEC commitments | 160 | | | 706 | | | 866 | | | 2022 - 2027 | Total cash requirements | $ | 2,159 | | | $ | 20,722 | | | $ | 22,881 | | | |
__________ (a)Includes amounts from ComEd financing trust. (b)Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2021 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. Includes estimated interest payments due to the ComEd financing trust. (c)Represents the future estimated value at December 31, 2021 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between ComEd and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period. PECO | | | | | | | | | | | | | | | | | | | | | | | | | 2022 | | Beyond 2022 | | Total | | Time Period | Long-term debt(a) | $ | 350 | | | $ | 4,084 | | | $ | 4,434 | | | 2022 - 2051 | Interest payments on long-term debt(b) | 166 | | | 3,213 | | | 3,379 | | | 2022 - 2051 | Operating leases | — | | | 1 | | | 1 | | | 2022 - 2034 | Fuel purchase agreements(c) | 140 | | | 271 | | | 411 | | | 2022 - 2029 | Electric supply procurement | 490 | | | 2 | | | 492 | | | 2022 - 2023 | Other purchase obligations(d) | 846 | | | 690 | | | 1,536 | | | 2022 - 2030 | Total cash requirements | $ | 1,992 | | | $ | 8,261 | | | $ | 10,253 | | | |
__________ (a)Includes amounts from PECO financing trusts. (b)Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2021 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. Includes estimated interest payments due to the PECO financing trusts. (c)Represents commitments to purchase natural gas and related transportation, storage capacity, and services. (d)Represents the future estimated value at December 31, 2021 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between PECO and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.
BGE | | | | | | | | | | | | | | | | | | | | | | | | | 2022 | | Beyond 2022 | | Total | | Time Period | Long-term debt | $ | 250 | | | $ | 3,750 | | | $ | 4,000 | | | 2022 - 2050 | Interest payments on long-term debt(a) | 138 | | | 2,312 | | | 2,450 | | | 2022 - 2050 | Operating leases | 16 | | | 19 | | | 35 | | | 2022 - 2106 | Fuel purchase agreements(b) | 112 | | | 481 | | | 593 | | | 2022 - 2038 | Electric supply procurement | 764 | | | 498 | | | 1,262 | | | 2022 - 2024 | Other purchase obligations(c) | 692 | | | 607 | | | 1,299 | | | 2022 - 2040 | Total cash requirements | $ | 1,972 | | | $ | 7,667 | | | $ | 9,639 | | | |
__________ (a)Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2021 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. (b)Represents commitments to purchase natural gas and related transportation, storage capacity, and services. (c)Represents the future estimated value at December 31, 2021 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between BGE and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period. PHI | | | | | | | | | | | | | | | | | | | | | | | | | 2022 | | Beyond 2022 | | Total | | Time Period | Long-term debt | $ | 387 | | | $ | 6,618 | | | $ | 7,005 | | | 2022 - 2051 | Interest payments on long-term debt(a) | 282 | | | 3,953 | | | 4,235 | | | 2022 - 2051 | Finance leases | 12 | | | 67 | | | 79 | | | 2022 - 2029 | Operating leases | 38 | | | 230 | | | 268 | | | 2022 - 2032 | Fuel purchase agreements(b) | 31 | | | 242 | | | 273 | | | 2022 - 2030 | Electric supply procurement | 1,097 | | | 754 | | | 1,851 | | | 2022 - 2025 | Long-term renewable energy and REC commitments | 31 | | | 253 | | | 284 | | | 2022 - 2032 | Other purchase obligations(c) | 1,016 | | | 1,031 | | | 2,047 | | | 2022 - 2029 | DC PLUG obligation | 33 | | | 37 | | | 70 | | | 2022 - 2024 | Total cash requirements | $ | 2,927 | | | $ | 13,185 | | | $ | 16,112 | | | |
__________ (a)Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2021 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2021. (b)Represents commitments to purchase natural gas and related transportation, storage capacity, and services. (c)Represents the future estimated value at December 31, 2021 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between Pepco, DPL, ACE, and PHISCO and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.
Pepco | | | | | | | | | | | | | | | | | | | | | | | | | 2022 | | Beyond 2022 | | Total | | Time Period | Long-term debt | $ | 309 | | | $ | 3,150 | | | $ | 3,459 | | | 2022 - 2051 | Interest payments on long-term debt(a) | 149 | | | 2,287 | | | 2,436 | | | 2022 - 2051 | Finance leases | 4 | | | 23 | | | 27 | | | 2022 - 2029 | Operating leases | 8 | | | 47 | | | 55 | | | 2022 - 2032 | Electric supply procurement | 498 | | | 384 | | | 882 | | | 2022 - 2025 | Other purchase obligations(b) | 603 | | | 551 | | | 1,154 | | | 2022 - 2026 | DC PLUG obligation | 33 | | | 37 | | | 70 | | | 2022 - 2024 | Total cash requirements | $ | 1,604 | | | $ | 6,479 | | | $ | 8,083 | | | |
__________ (a)Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2021 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. (b)Represents the future estimated value at December 31, 2021 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between Pepco and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period. DPL | | | | | | | | | | | | | | | | | | | | | | | | | 2022 | | Beyond 2022 | | Total | | Time Period | Long-term debt | $ | 78 | | | $ | 1,711 | | | $ | 1,789 | | | 2022 - 2051 | Interest payments on long-term debt(a) | 63 | | | 1,013 | | | 1,076 | | | 2022 - 2051 | Finance leases | 5 | | | 27 | | | 32 | | | 2022 - 2029 | Operating leases | 10 | | | 60 | | | 70 | | | 2022 - 2027 | Fuel purchase agreements(b) | 31 | | | 242 | | | 273 | | | 2022 - 2030 | Electric supply procurement | 298 | | | 187 | | | 485 | | | 2022 - 2024 | Long-term renewable energy and REC commitments | 31 | | | 253 | | | 284 | | | 2022 - 2032 | Other purchase obligations(c) | 214 | | | 192 | | | 406 | | | 2022 - 2028 | Total cash requirements | $ | 730 | | | $ | 3,685 | | | $ | 4,415 | | | |
__________ (a)Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2021 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2021. (b)Represents commitments to purchase natural gas and related transportation, storage capacity, and services. (c)Represents the future estimated value at December 31, 2021 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between DPL and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.
ACE | | | | | | | | | | | | | | | | | | | | | | | | | 2022 | | Beyond 2022 | | Total | | Time Period | Long-term debt | $ | — | | | $ | 1,572 | | | $ | 1,572 | | | 2022 - 2050 | Interest payments on long-term debt(a) | 56 | | | 519 | | | 575 | | | 2022 - 2050 | Finance leases | 3 | | | 17 | | | 20 | | | 2022 - 2029 | Operating leases | 4 | | | 9 | | | 13 | | | 2022 - 2027 | Electric supply procurement | 301 | | | 183 | | | 484 | | | 2022 - 2024 | Other purchase obligations(b) | 158 | | | 240 | | | 398 | | | 2022 - 2027 | Total cash requirements | $ | 522 | | | $ | 2,540 | | | $ | 3,062 | | | |
__________ (a)Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2021 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. (b)Represents the future estimated value at December 31, 2021 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between ACE and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period. See Note 19 — Commitments and Contingencies and Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information of the Registrants’ other commitments potentially triggered by future events. Additionally, see below for where to find additional information regarding the financial commitments in the tables above in the Combined Notes to the Consolidated Financial Statements: | | | | | | (a)Item | Represents incremental collateral relatedLocation within Notes to natural gas procurement contracts.the Consolidated Financial Statements | Long-term debt | Note 17 — Debt and Credit Agreements | Interest payments on long-term debt | Note 17 — Debt and Credit Agreements | Finance leases | Note 11 — Leases | Operating leases | Note 11 — Leases | SNF obligation | Note 19 — Commitments and Contingencies | REC commitments | Note 3 — Regulatory Matters | ZEC commitments | Note 3 — Regulatory Matters | DC PLUG obligation | Note 3 — Regulatory Matters | Pension contributions | Note 15 — Retirement Benefits |
Exelon 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 1617 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information ofon the Registrants’ credit facilities and short term borrowing activity.
Capital Structure.Structure At December 31, 2019,2021, the capital structures of the Registrants consisted of the following: | |
| Exelon |
| Generation |
| ComEd |
| PECO |
| BGE | | PHI | | Pepco | | DPL | | ACE | | Exelon | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Long-term debt | 50 | % | | 31 | % | | 44 | % | | 44 | % | | 47 | % | | 40 | % | | 49 | % | | 49 | % | | 50 | % | Long-term debt | 50 | % | | | 44 | % | | 44 | % | | 45 | % | | 40 | % | | 49 | % | | 48 | % | | 48 | % | Long-term debt to affiliates(a) | 1 | % | | 4 | % | | — | % | | 2 | % | | — | % | | — | % | | — | % | | — | % | | — | % | Long-term debt to affiliates(a) | 1 | % | | | 1 | % | | 2 | % | | — | % | | — | % | | — | % | | — | % | | — | % | Common equity | 47 | % | | — | % | | 55 | % | | 54 | % | | 52 | % | | — |
| | 50 | % | | 49 | % | | 47 | % | Common equity | 45 | % | | | 55 | % | | 54 | % | | 53 | % | | — | % | | 49 | % | | 48 | % | | 48 | % | Member’s equity | — | % | | 64 | % | | — | % | | — | % | | — | % | | 59 | % | | — |
| | — |
| | — |
| Member’s equity | — | % | | | — | % | | — | % | | — | % | | 57 | % | | — | % | | — | % | | — | % | | Commercial paper and notes payable | 2 | % | | 1 | % | | 1 |
| | — | % | | 1 | % | | 1 | % | | 1 | % | | 2 | % | | 3 | % | Commercial paper and notes payable | 4 | % | | | — | % | | — | % | | 2 | % | | 3 | % | | 2 | % | | 4 | % | | 4 | % |
__________ | | (a) | Includes approximately $390 million, $205 million and $184 million owed to unconsolidated affiliates of Exelon, ComEd, and PECO respectively. These special purpose entities were created for the sole purposes of issuing mandatorily redeemable trust preferred securities of ComEd and PECO. See Note 22 — Variable Interest Entities of the Combined Notes to Consolidated Financial Statements for additional information regarding the authoritative guidance for VIEs. |
(a)Includes approximately $390 million, $205 million, and $184 million owed to unconsolidated affiliates of Exelon, ComEd, and PECO respectively. These special purpose entities were created for the sole purposes of issuing mandatory redeemable trust preferred securities of ComEd and PECO. See Note 23 — Variable Interest Entities of the Combined Notes to Consolidated Financial Statements for additional information regarding the authoritative guidance for VIEs. 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 additional collateral. See Note 1516 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on collateral provisions. The credit ratings for Exelon Corporate and the Utility Registrants did not change for the year ended December 31, 2021. On January 14, 2022, Fitch lowered Exelon Corporate's long-term rating 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+ and upgraded Pepco and ACE's senior secured rating from A- to 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 December 31, 2019,2021, are presented in the following tables:tables. ACE did not have any intercompany money pool activity as of December 31, 2021. | | | | | | | | | | | | | | | | | | | For the Year Ended December 31, 2021 | | As of December 31, 2021 | Exelon Intercompany Money Pool | Maximum Contributed | | Maximum Borrowed | | Contributed (Borrowed) | Exelon Corporate | $ | 735 | | | $ | — | | | $ | 217 | | Generation | — | | | (426) | | | — | | PECO | 303 | | | (100) | | | — | | BSC | — | | | (435) | | | (260) | | PHI Corporate | — | | | (40) | | | (7) | | PCI | 60 | | | — | | | 50 | |
| | | | | | | | | | | | | Exelon Intercompany Money Pool | For the Year Ended December 31, 2019 | | As of December 31, 2019 | Contributed (borrowed) | Maximum Contributed | | Maximum Borrowed | | Contributed (Borrowed) | Exelon Corporate | $ | 467 |
| | $ | — |
| | $ | 121 |
| Generation | 212 |
| | (235 | ) | | — |
| PECO | 164 |
| | (85 | ) | | 68 |
| BSC | 18 |
| | (383 | ) | | (232 | ) | PHI Corporate | — |
| | (12 | ) | | (12 | ) | PCI | 60 |
| | — |
| | 55 |
|
| | | | | | | | | | | | | | | | | | | For the Year Ended December 31, 2021 | | As of December 31, 2021 | PHI Intercompany Money Pool | Maximum Contributed | | Maximum Borrowed | | Contributed (Borrowed) | | | | | | | Pepco | $ | — | | | $ | (30) | | | $ | — | | DPL | 30 | | | — | | | — | | | | | | | | | | | | | |
| | | | | | | | | | | | | PHI Intercompany Money Pool | For the Year Ended December 31, 2019 | | As of December 31, 2019 | Contributed (borrowed) | Maximum Contributed | | Maximum Borrowed | | Contributed (Borrowed) | Pepco | $ | 63 |
| | $ | — |
| | $ | — |
| DPL | 3 |
| | (45 | ) | | — |
| ACE | — |
| | (29 | ) | | — |
|
Shelf Registration Statements. Statements (All Registrants) Exelon Generation, ComEd, PECO, BGE, Pepco, DPL and ACEthe 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. ComEd, PECO, BGE, Pepco, DPL and ACEAuthorizations (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 December 31, 2021 | | | Short-term Financing Authority(a) | | Remaining Long-term Financing Authority | Commission | | Expiration Date | | Amount | Commission | | Expiration Date | | Amount | ComEd(b) | | FERC | | December 31, 2023 | | $ | 2,500 | | | ICC | | January 1, 2025 | | $ | 2,093 | | PECO(c) | | FERC | | December 31, 2023 | | 1,500 | | | PAPUC | | December 31, 2024 | | 1,900 | | BGE | | FERC | | December 31, 2023 | | 700 | | | MDPSC | | N/A | | 500 | | Pepco | | FERC | | December 31, 2023 | | 500 | | | MDPSC / DCPSC | | December 31, 2022 | | 625 | | DPL | | FERC | | December 31, 2023 | | 500 | | | MDPSC / DEPSC | | December 31, 2022 | | 172 | | ACE(d) | | NJBPU | | December 31, 2023 | | 350 | | | NJBPU | | December 31, 2022 | | 175 | |
__________ (a)On October 15, 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 received approval on December 16, 2021, PECO and BGE received approval on December 23, 2021, Pepco and DPL received approval on December 28, 2021, and ACE received approval on December 1, 2021. (b)On November 18, 2021, ComEd had an additional $2 billion in new money long-term debt financing authority from the ICC with an effective date of January 1, 2022 and an expiration date of January 1, 2025. (c)On December 2, 2021, PECO received approval from the PAPUC for $2.5 billion in new long-term debt financing authority with an effective date of January 1, 2022.
| | | | | | | | | | | | | | | | | | | | Short-term Financing Authority(a)(b) | | Long-term Financing Authority(a) | Commission | | Expiration Date | | Amount | Commission | | Expiration Date | | Amount (c) | ComEd(c) | | FERC | | December 31, 2021 | | $ | 2,500 |
| | ICC | | 2021 & 2023 | | $ | 1,893 |
| PECO | | FERC | | December 31, 2021 | | 1,500 |
| | PAPUC | | December 31, 2021 | | 1,575 |
| BGE | | FERC | | December 31, 2021 | | 700 |
| | MDPSC | | N/A | | — |
| Pepco | | FERC | | December 31, 2021 | | 500 |
| | MDPSC / DCPSC | | December 31, 2022 | | 1,200 |
| DPL | | FERC | | December 31, 2021 | | 500 |
| | MDPSC / DPSC | | December 31, 2022 | | 475 |
| ACE | | NJBPU | | December 31, 2021 | | 350 |
| | NJBPU | | December 31, 2020 | | 200 |
|
(d)ACE is currently in the process of renewing its long-term financing authority with the NJBPU and expects approval by August 1, 2022.__________
| | | | | | (a) | Generation currently has blanket financing authority it received from FERC in connection with its market-based rate authority. |
| | (b) | On October 15, 2019, ComEd, BGE, Pepco and DPL filed applications with FERC and on September 12, 2019, ACE filed an application with NJBPU for renewal of their short-term financing authority through December 31, 2021. ComEd, BGE, Pepco and DPL received approval on December 13, 2019 and ACE received approval on December 6, 2019. |
| | (c) | As of December 31, 2019, ComEd had $393 million in new money long-term debt financing authority from the ICC with an expiration date of August 1, 2021. On January 22, 2020, ComEd had an additional $1.5 billion available in new money long-term debt financing authority from the ICC with an effective date of February 1, 2020 and an expiration date of February 1, 2023.
|
Contractual Obligations and Off-Balance Sheet Arrangements
The following tables summarize the Registrants’ future estimated cash payments as of December 31, 2019 under existing contractual obligations, including payments due by period.
Exelon
| | | | | | | | | | | | | | | | | | | | | | | | Payment due within | | Total | | 2020 |
| 2021 - 2022 |
| 2023 - 2024 |
| 2025 and beyond | Long-term debt(a) | $ | 35,910 |
| | $ | 4,704 |
| | $ | 4,594 |
| | $ | 2,442 |
| | $ | 24,170 |
| Interest payments on long-term debt(b) | 22,608 |
| | 1,356 |
| | 2,586 |
| | 2,357 |
| | 16,309 |
| Finance leases | 40 |
| | 6 |
| | 11 |
| | 9 |
| | 14 |
| Operating leases(c) | 1,361 |
| | 144 |
| | 267 |
| | 197 |
| | 753 |
| Purchase power obligations(d) | 1,201 |
| | 312 |
| | 672 |
| | 198 |
| | 19 |
| Fuel purchase agreements(e) | 6,217 |
| | 1,209 |
| | 1,852 |
| | 1,380 |
| | 1,776 |
| Electric supply procurement | 2,049 |
| | 1,310 |
| | 731 |
| | 8 |
| | — |
| Long-term renewable energy and REC commitments | 2,284 |
| | 254 |
| | 534 |
| | 448 |
| | 1,048 |
| Other purchase obligations(f) | 8,308 |
| | 6,189 |
| | 1,139 |
| | 274 |
| | 706 |
| DC PLUG obligation | 130 |
| | 30 |
| | 60 |
| | 40 |
| | — |
| SNF obligation | 1,199 |
| | — |
| | — |
| | — |
| | 1,199 |
| ZEC commitments | 1,313 |
| | 164 |
| | 328 |
| | 328 |
| | 493 |
| Pension contributions(g) | 3,030 |
| | 505 |
| | 1,010 |
| | 1,010 |
| | 505 |
| Total contractual obligations | $ | 85,650 |
| | $ | 16,183 |
|
| $ | 13,784 |
|
| $ | 8,691 |
|
| $ | 46,992 |
|
__________
| | (a) | Includes amounts from ComEd and PECO financing trusts. |
| | (b) | Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2019 and do not reflect anticipated future refinancing, early redemptions or debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2019. Includes estimated interest payments due to ComEd and PECO financing trusts. |
| | (c) | Capacity payments associated with contracted generation lease agreements are net of sublease and capacity offsets of $143 million, $98 million, $55 million, $44 million, $44 million and $223 million for 2020, 2021, 2022, 2023, 2024 and thereafter, respectively and $607 million in total. |
| | (d) | Purchase power obligations primarily include expected payments for REC purchases and payments associated with contracted generation agreements, which may be reduced based on plant availability. Expected payments exclude payments on renewable generation contracts that are contingent in nature. |
| | (e) | Represents commitments to purchase nuclear fuel, natural gas and related transportation, storage capacity and services. |
| | (f) | Represents the future estimated value at December 31, 2019 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between the Registrants and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period. |
| | (g) | These amounts represent Exelon’s expected contributions to its qualified pension plans. Qualified pension contributions for years after 2025 are not included. |
Generation
| | | | | | | | | | | | | | | | | | | | | | | | Payment due within | | Total | | 2020 | | 2021 - 2022 | | 2023 - 2024 | | 2025 and beyond | Long-term debt | $ | 7,938 |
| | $ | 3,180 |
| | $ | 1,024 |
| | $ | 792 |
| | $ | 2,942 |
| Interest payments on long-term debt(a) | 3,575 |
| | 253 |
| | 480 |
| | 424 |
| | 2,418 |
| Finance leases | 5 |
| | 2 |
| | 2 |
| | 1 |
| | — |
| Operating leases(b) | 809 |
| | 60 |
| | 122 |
| | 109 |
| | 518 |
| Purchase power obligations(c) | 1,201 |
| | 312 |
| | 672 |
| | 198 |
| | 19 |
| Fuel purchase agreements(d) | 5,056 |
| | 999 |
| | 1,536 |
| | 1,189 |
| | 1,332 |
| Other purchase obligations(e) | 2,536 |
| | 1,516 |
| | 230 |
| | 126 |
| | 664 |
| SNF obligation | 1,199 |
| | — |
| | — |
| | — |
| | 1,199 |
| Total contractual obligations | $ | 22,319 |
| | $ | 6,322 |
|
| $ | 4,066 |
|
| $ | 2,839 |
|
| $ | 9,092 |
|
__________
| | (a) | Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2019 and do not reflect anticipated future refinancing, early redemptions or debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2019. |
| | (b) | Capacity payments associated with contracted generation lease agreements are net of sublease and capacity offsets of $143 million, $98 million, $55 million, $44 million, $44 million and $223 million for 2020, 2021, 2022, 2023, 2024 and thereafter, respectively and $607 million in total. |
| | (c) | Purchase power obligations primarily include expected payments for REC purchases and capacity payments associated with contracted generation agreements, which may be reduced based on plant availability. Expected payments exclude payments on renewable generation contracts that are contingent in nature. |
| | (d) | Primarily represents commitments to purchase fuel supplies for nuclear and fossil generation, including those related to CENG. |
| | (e) | Represents the future estimated value at December 31, 2019 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between Generation and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period. |
ComEd
| | | | | | | | | | | | | | | | | | | | | | | | Payment due within | | Total | | 2020 | | 2021 - 2022 | | 2023 - 2024 | | 2025 and beyond | Long-term debt(a) | $ | 8,783 |
| | $ | 500 |
| | $ | 350 |
| | $ | 250 |
| | $ | 7,683 |
| Interest payments on long-term debt(b) | 6,918 |
| | 345 |
| | 674 |
| | 665 |
| | 5,234 |
| Finance leases | 8 |
| | — |
| | — |
| | — |
| | 8 |
| Operating leases | 12 |
| | 3 |
| | 6 |
| | 2 |
| | 1 |
| Electric supply procurement | 617 |
| | 403 |
| | 214 |
| | — |
| | — |
| Long-term renewable energy and REC commitments | 1,986 |
| | 222 |
| | 470 |
| | 384 |
| | 910 |
| Other purchase obligations(c) | 1,262 |
| | 1,219 |
| | 36 |
| | 5 |
| | 2 |
| ZEC commitments | 1,313 |
| | 164 |
| | 328 |
| | 328 |
| | 493 |
| Total contractual obligations | $ | 20,899 |
| | $ | 2,856 |
|
| $ | 2,078 |
|
| $ | 1,634 |
|
| $ | 14,331 |
|
__________
| | (a) | Includes amounts from ComEd financing trust. |
| | (b) | Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2019 and do not reflect anticipated future refinancing, early redemptions or debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2019. Includes estimated interest payments due to the ComEd financing trust. |
| | (c) | Represents the future estimated value at December 31, 2019 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between ComEd and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period. |
PECO
| | | | | | | | | | | | | | | | | | | | | | | | Payment due within | | Total | | 2020 | | 2021 - 2022 | | 2023 - 2024 | | 2025 and beyond | Long-term debt(a) | $ | 3,634 |
| | $ | — |
| | $ | 650 |
| | $ | 50 |
| | $ | 2,934 |
| Interest payments on long-term debt(b) | 2,721 |
| | 141 |
| | 274 |
| | 254 |
| | 2,052 |
| Operating leases | 1 |
| | — |
| | 1 |
| | — |
| | — |
| Fuel purchase agreements(c) | 335 |
| | 116 |
| | 154 |
| | 31 |
| | 34 |
| Electric supply procurement | 552 |
| | 441 |
| | 111 |
| | — |
| | — |
| Other purchase obligations(d) | 834 |
| | 727 |
| | 107 |
| | — |
| | — |
| Total contractual obligations | $ | 8,077 |
| | $ | 1,425 |
|
| $ | 1,297 |
|
| $ | 335 |
|
| $ | 5,020 |
|
__________
| | (a) | Includes amounts from PECO financing trusts. |
| | (b) | Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2019 and do not reflect anticipated future refinancing, early redemptions or debt issuances. Includes estimated interest payments due to the PECO financing trust. |
| | (c) | Represents commitments to purchase natural gas and related transportation, storage capacity and services. |
| | (d) | Represents the future estimated value at December 31, 2019 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between PECO and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period. |
BGE
| | | | | | | | | | | | | | | | | | | | | | | | Payment due within | | Total | | 2020 | | 2021 - 2022 | | 2023 - 2024 | | 2025 and beyond | Long-term debt | $ | 3,300 |
| | $ | — |
| | $ | 550 |
| | $ | 300 |
| | $ | 2,450 |
| Interest payments on long-term debt(a) | 2,241 |
| | 126 |
| | 238 |
| | 203 |
| | 1,674 |
| Operating leases | 100 |
| | 34 |
| | 47 |
| | 1 |
| | 18 |
| Fuel purchase agreements(b) | 522 |
| | 60 |
| | 94 |
| | 92 |
| | 276 |
| Electric supply procurement | 1,050 |
| | 631 |
| | 419 |
| | — |
| | — |
| Other purchase obligations(c) | 1,014 |
| | 868 |
| | 141 |
| | 3 |
| | 2 |
| Total contractual obligations | $ | 8,227 |
| | $ | 1,719 |
|
| $ | 1,489 |
|
| $ | 599 |
|
| $ | 4,420 |
|
__________
| | (a) | Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2019 and do not reflect anticipated future refinancing, early redemptions or debt issuances. |
| | (b) | Represents commitments to purchase natural gas and related transportation, storage capacity and services. |
| | (c) | Represents the future estimated value at December 31, 2019 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between BGE and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period. |
PHI
| | | | | | | | | | | | | | | | | | | | | | | | Payment due within | | Total | | 2020 | | 2021 - 2022 | | 2023 - 2024 | | 2025 and beyond | Long-term debt | $ | 5,967 |
| | $ | 98 |
| | $ | 571 |
| | $ | 1,049 |
| | $ | 4,249 |
| Interest payments on long-term debt(a) | 4,150 |
| | 269 |
| | 512 |
| | 463 |
| | 2,906 |
| Finance leases | 28 |
| | 5 |
| | 8 |
| | 8 |
| | 7 |
| Operating leases | 346 |
| | 42 |
| | 79 |
| | 72 |
| | 153 |
| Fuel purchase agreements(b) | 304 |
| | 34 |
| | 68 |
| | 68 |
| | 134 |
| Long-term renewable energy and REC commitments | 298 |
| | 32 |
| | 64 |
| | 64 |
| | 138 |
| Electric supply procurement | 1,787 |
| | 1,040 |
| | 730 |
| | 17 |
| | — |
| Other purchase obligations(c) | 1,181 |
| | 959 |
| | 184 |
| | 6 |
| | 32 |
| DC PLUG obligation | 130 |
| | 30 |
| | 60 |
| | 40 |
| | — |
| Total contractual obligations | $ | 14,219 |
| | $ | 2,514 |
| | $ | 2,284 |
| | $ | 1,795 |
| | $ | 7,626 |
|
__________
| | (a) | Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2019 and do not reflect anticipated future refinancing, early redemptions or debt issuances. |
| | (b) | Represents commitments to purchase natural gas and related transportation, storage capacity and services. |
| | (c) | Represents the future estimated value at December 31, 2019 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between PHI and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period. |
Pepco
| | | | | | | | | | | | | | | | | | | | | | | | Payment due within | | Total | | 2020 | | 2021 - 2022 | | 2023 - 2024 | | 2025 and beyond | Long-term debt | $ | 2,886 |
| | $ | 1 |
| | $ | 311 |
| | $ | 399 |
| | $ | 2,175 |
| Interest payments on long-term debt(a) | 2,385 |
| | 138 |
| | 271 |
| | 249 |
| | 1,727 |
| Finance leases | 11 |
| | 1 |
| | 2 |
| | 3 |
| | 5 |
| Operating leases | 70 |
| | 8 |
| | 16 |
| | 12 |
| | 34 |
| Electric supply procurement | 803 |
| | 445 |
| | 341 |
| | 17 |
| | — |
| Other purchase obligations(b) | 663 |
| | 489 |
| | 145 |
| | 4 |
| | 25 |
| DC PLUG obligation | 130 |
| | 30 |
| | 60 |
| | 40 |
| | — |
| Total contractual obligations | $ | 6,959 |
| | $ | 1,113 |
| | $ | 1,148 |
| | $ | 727 |
| | $ | 3,971 |
|
__________
| | (a) | Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2019 and do not reflect anticipated future refinancing, early redemptions or debt issuances. |
| | (b) | Represents the future estimated value at December 31, 2019 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between Pepco and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period. |
DPL
| | | | | | | | | | | | | | | | | | | | | | | | Payment due within | | Total | | 2020 | | 2021 - 2022 | | 2023 - 2024 | | 2025 and beyond | Long-term debt | $ | 1,568 |
| | $ | 78 |
| | $ | — |
| | $ | 500 |
| | $ | 990 |
| Interest payments on long-term debt(a) | 1,087 |
| | 60 |
| | 120 |
| | 99 |
| | 808 |
| Finance leases | 10 |
| | 2 |
| | 4 |
| | 3 |
| | 1 |
| Operating leases | 91 |
| | 11 |
| | 21 |
| | 18 |
| | 41 |
| Fuel purchase agreements(b) | 304 |
| | 34 |
| | 68 |
| | 68 |
| | 134 |
| Long-term renewable energy and associated REC commitments | 298 |
| | 32 |
| | 64 |
| | 64 |
| | 138 |
| Electric supply procurement | 458 |
| | 288 |
| | 170 |
| | — |
| | — |
| Other purchase obligations(c) | 280 |
| | 262 |
| | 18 |
| | — |
| | — |
| Total contractual obligations | $ | 4,096 |
| | $ | 767 |
| | $ | 465 |
| | $ | 752 |
| | $ | 2,112 |
|
__________
| | (a) | Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2019 and do not reflect anticipated future refinancing, early redemptions or debt issuances. |
| | (b) | Represents commitments to purchase natural gas and related transportation, storage capacity and services. |
| | (c) | Represents the future estimated value at December 31, 2019 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between DPL and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period. |
ACE
| | | | | | | | | | | | | | | | | | | | | | | | Payment due within | | Total | | 2020 | | 2021 - 2022 | | 2023 - 2024 | | 2025 and beyond | Long-term debt | $ | 1,327 |
| | $ | 19 |
| | $ | 260 |
| | $ | 150 |
| | $ | 898 |
| Interest payments on long-term debt (a) | 503 |
| | 57 |
| | 93 |
| | 87 |
| | 266 |
| Finance leases | 8 |
| | 1 |
| | 2 |
| | 2 |
| | 3 |
| Operating leases | 20 |
| | 5 |
| | 8 |
| | 5 |
| | 2 |
| Electric supply procurement | 526 |
| | 307 |
| | 219 |
| | — |
| | — |
| Other purchase obligations(b) | 200 |
| | 185 |
| | 15 |
| | — |
| | — |
| Total contractual obligations | $ | 2,584 |
| | $ | 574 |
| | $ | 597 |
| | $ | 244 |
| | $ | 1,169 |
|
__________
| | (a) | Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2019 and do not reflect anticipated future refinancing, early redemptions or debt issuances. |
| | (b) | Represents the future estimated value at December 31, 2019 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between ACE and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period. |
See Note 18 — Commitments and Contingencies and Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information of the Registrants’ other commitments potentially triggered by future events. Additionally, see below for where to find additional information regarding certain contractual obligations in the Combined Notes to the Consolidated Financial Statements:
| | | Item | Location within Notes to the Consolidated Financial Statements | Finance Leases | Note 10 — Leases | Operating Leases | Note 10 — Leases | DC PLUG obligation | Note 3 — Regulatory Matters | ZEC Commitments | Note 3 — Regulatory Matters | REC Commitments | Note 3 — Regulatory Matters & Note 15 — Derivative Financial Instruments | Long-term debt | Note 16 — Debt and Credit Agreements | Interest payments on long-term debt | Note 16 — Debt and Credit Agreements | Pension contributions | Note 14 — Retirement Benefits | SNF obligation | Note 18 — Commitments and Contingencies |
| | | ITEM 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
The Registrants are exposed to market risks associated with adverse changes in commodity prices, counterparty credit, interest rates, and equity prices. Exelon’s RMC approvesExelon 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 byHistorically, reporting on risk management issues has been to Exelon’s Risk Management Committee, the chief executive officerRisk Management Committees of each Utility Registrant, and includes the chiefRisk Committee of Exelon’s Board of Directors. After separation, reporting on risk officer, chief strategy officer, chief executive officermanagement issues will be to Exelon’s Executive Committee, the Risk Management Committees of Exelon Utilities, chief commercial officer, chief financial officereach Utility Registrant, 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.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. Generation Electricity available from Generation’s owned or contracted generation supply in excess of Generation’s obligations to customers, including portions of the Utility Registrants' retail load, is sold into the wholesale markets. To reduce commodity 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 expectsWe expect the settlement of the majority of itsour economic hedges will occur during 20202022 through 2022.2024. In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on Generation’s owned and contracted generation positions which have not been hedged. Exelon'sFor merchant revenues not already hedged via comprehensive state programs, such as the CMC in Illinois, we utilize a three-year ratable sales plan to align our hedging program involves thestrategy with our financial objectives. The prompt three-year merchant revenues are hedged on an approximate rolling 90%/60%/30% basis. We may also enter transactions that are outside of this ratable hedging of commodity price risk for Exelon's expected generation, typically on a ratable basis over three-year periods. Asprogram.As of December 31, 2019,2021, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York, and ERCOT reportable segments is 91%-94%92%-95% and61%-64% 73%-76% for 20202022 and2021, 2023, respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation. Expected generation is the volume of energy that best represents our commodity position in energy markets from owned or contracted generation based upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products and options. Equivalent sales represent all hedging products, which include economic hedges, CMC payments, and certain non-derivative contracts, including Generation’s sales to ComEd, PECO and BGE to serve their retail load.contracts. A portion of Generation’s hedging strategy may be accomplished with fuel products based on assumed correlations between power and fuel prices, which routinely change in the market. Market price risk exposure is the risk of a change in the value of unhedged positions. The forecasted market price risk exposure for Generation’s entire economic hedge portfolio associated with a $5$5/MWh reduction in the annual average around-the-clock energy price based on December 31, 20192021 market conditions and hedged position would be decreasesa decrease in pre-tax net income of approximately $25$20 million and $331$243 million respectively, for 20202022 and 2021.2023, respectively. Power price sensitivities are derived by adjusting power price assumptions while keeping all other price inputs constant. Generation actively manages its portfolio to mitigate market price risk exposure for its unhedged position. Actual results could differ depending on the specific timing of, and markets affected by, price changes, as well as future changes in Generation’s portfolio. See Note 1516 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information. Fuel ProcurementLiquidity and Capital Resources
Generation procures natural gasAll 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, 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 short-term contracts,where such recovery takes place over an extended period of time. A broad spectrum of financing alternatives beyond the core financing options can be used to meet its needs 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,fund growth including monetizing assets in the portfolio via project financing, asset sales, and contracted fuel fabrication services. The supplythe use of other financing structures (e.g., joint ventures, minority partners, etc.). 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 for uranium concentrates and certain nuclear fuel services are subject to price fluctuations and availability restrictions. Supply market conditions may make Generation’s procurement contracts subjectat reasonable terms, the Registrants have access to credit risk relatedfacilities with aggregate bank commitments of $10.3 billion, as of December 31, 2021. 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 potential non-performance“Credit Matters” section below for additional information. The Registrants expect cash flows to be sufficient to meet operating expenses, financing costs, and capital expenditure requirements. See Note 17 — Debt and Credit Agreements of counterpartiesthe Combined Notes to deliverConsolidated Financial Statements for additional information on the contracted commodity or service at the contracted prices. Approximately 60%Registrants’ debt and credit agreements.
Utility Registrants
ComEd 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. BGE, Pepco, DPL and ACE have certain full requirements contracts,
Cash Flows from Operating Activities (All Registrants)
which are considered derivativesThe Utility Registrants' cash flows from operating activities primarily result from the transmission and qualify for NPNS,distribution of electricity and, as a result are accounted for on an accrual basisin the case of accounting. Other full requirements contracts are not derivatives.
PECO, BGE, and DPL, also have executed derivative natural gas contracts, which either qualify for NPNSdistribution 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 have no mark-to-market balances becauseoperations, and their ability to achieve operating cost reductions. Generation's cash flows from operating activities primarily result from the derivatives are index priced,sale of electric energy and energy-related products and services to hedge their long-term price risk in the natural gas market. The hedging programs for natural gas procurement have no direct impact on their financial statements. PECO, BGE, Pepco, DPL and ACE do not execute derivatives for speculative or proprietary trading purposes.customers. For additional information on these contracts, seeSee Note 3 — Regulatory Matters and Note 1519 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements 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 years ended December 31, 2021 and 2020 by Registrant: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (Decrease) increase in cash flows from operating activities | Exelon | | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Net income | $ | (125) | | | | | $ | 304 | | | $ | 57 | | | $ | 59 | | | $ | 66 | | | $ | 30 | | | $ | 3 | | | $ | 34 | | Adjustments to reconcile net income to cash: | | | | | | | | | | | | | | | | | | Non-cash operating activities | (332) | | | | | 12 | | | 11 | | | (35) | | | 45 | | | 35 | | | 23 | | | (15) | | Option premiums paid, net | (199) | | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Collateral (posted) received, net | (568) | | | | | (14) | | | — | | | — | | | — | | | — | | | — | | | — | | Income taxes | 187 | | | | | (8) | | | (26) | | | (40) | | | 42 | | | 12 | | | 38 | | | 1 | | Pension and non-pension postretirement benefit contributions | (64) | | | | | (48) | | | — | | | (3) | | | (9) | | | — | | | (1) | | | (1) | | Changes in working capital and other noncurrent assets and liabilities | (122) | | | | | 25 | | | (46) | | | (136) | | | 11 | | | (116) | | | 50 | | | 77 | | (Decrease) increase in cash flows from operating activities | $ | (1,223) | | | | | $ | 271 | | | $ | (4) | | | $ | (155) | | | $ | 155 | | | $ | (39) | | | $ | 113 | | | $ | 96 | |
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, significant operating cash flow impacts for the Registrants for 2021 and 2020 were as follows: •See Note 24 —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. •Option premiums paid relate to options contracts that Generation purchases and sells as part of its established policies and procedures to manage risks associated with market fluctuations in commodity prices. See Note 16 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements.Statements for additional information on derivative contracts. Trading•Depending upon whether Exelon is in a net mark-to-market liability or asset position, collateral may be required to be posted with or collected from its counterparties. In addition, the collateral posting and Non-Trading Marketing Activities
The following table detailing Exelon’s, Generation’s and ComEd’s trading and non-trading marketing activitiescollection requirements differ depending on whether the transactions are included to address the recommended disclosures by the energy industry’s Committee of Chief Risk Officers (CCRO).
The following table provides detail on changes in Exelon’s, Generation’s and ComEd’s commodity mark-to-market net assetan exchange or liability balance sheet position from December 31, 2017 to December 31, 2019. 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.over-the-counter markets. See Note 1516 — 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 December 31, 2019 and 2018.Registrants’ collateral.
| | | | | | | | | | | | | | Exelon | | Generation | | ComEd | Total mark-to-market energy contract net assets (liabilities) at December 31, 2017(a) | $ | 667 |
|
| $ | 923 |
| | $ | (256 | ) | Total change in fair value during 2018 of contracts recorded in result of operations | 270 |
| | 270 |
| | — |
| Reclassification to realized at settlement of contracts recorded in results of operations | (570 | ) | | (570 | ) | | — |
| Contracts received at acquisition date(d) | (19 | ) | | (19 | ) | | — |
| Changes in fair value—recorded through regulatory assets and liabilities(b) | 8 |
| | — |
| | 7 |
| Changes in allocated collateral | (110 | ) | | (109 | ) | | — |
| Net option premium received | 43 |
| | 43 |
| | — |
| Option premium amortization | (10 | ) | | (10 | ) | | — |
| Upfront payments and amortizations(c) | 20 |
| | 20 |
| | — |
| Total mark-to-market energy contract net assets (liabilities) at December 31, 2018(a) | 299 |
| | 548 |
| | (249 | ) | Total change in fair value during 2019 of contracts recorded in result of operations | (427 | ) | | (427 | ) | | — |
| Reclassification to realized at settlement of contracts recorded in results of operations | 226 |
| | 226 |
| | — |
| Changes in fair value—recorded through regulatory assets and liabilities(b) | (52 | ) | | — |
| | (52 | ) | Changes in allocated collateral | 572 |
| | 572 |
| | — |
| Net option premium paid | 29 |
| | 29 |
| | — |
| Option premium amortization | (22 | ) | | (22 | ) | | — |
| Upfront payments and amortizations(c) | (58 | ) | | (58 | ) | | — |
| Total mark-to-market energy contract net assets (liabilities) at December 31, 2019(a) | $ | 567 |
| | $ | 868 |
| | $ | (301 | ) |
__________
| | (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 or liabilities. As of December 31, 2018 and 2019, ComEd recorded a regulatory liability of $249 million and $301 million, respectively, related to its mark-to-market derivative liabilities with Generation and unaffiliated suppliers. ComEd recorded $24 million of decreases in fair value and an increase for realized losses due to settlements of $17 million in purchased power expense associated with floating-to-fixed energy swap suppliers for the year ended December 31, 2018. ComEd recorded $78 million of decreases in fair value and an increase for realized losses due to settlements of $26 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the year ended December 31, 2019. |
| | (c) | Includes derivative contracts acquired or sold by Generation through upfront payments or receipts of cash, excluding option premiums, and the associated amortizations. |
| | (d) | Includes fair value from contracts received at acquisition of the Everett Marine Terminal. |
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 provide two fundamental pieces of information. First, the tables provide the source of fair value used in determining the carrying amount of the Registrants’ total mark-to-market net assets (liabilities), net of allocated collateral. Second, the tables show the maturity, by year, of the Registrants’ commodity contract net assets (liabilities) net of allocated collateral, giving an indication of when these mark-to-market amounts will settle and either generate or require cash. •See Note 17 — Fair Value of Financial Assets and Liabilities14 —Income Taxes of the Combined Notes to Consolidated Financial Statements and the Registrants' Consolidated Statements of Cash Flows for additional information regarding fair value measurementson income taxes.
•Changes in working capital and other noncurrent assets and liabilities include a decrease in Accounts receivable at Exelon resulting from the fair value hierarchy. impact of cash received 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 at Exelon resulting from the impact of certain penalties for natural gas delivery associated with the February 2021 extreme cold weather event at
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Maturities Within | | Total Fair Value | | 2020 | | 2021 | | 2022 | | 2023 | | 2024 | | 2025 and Beyond | | Normal Operations, Commodity derivative contracts(a)(b): | | | | | | | | | | | | | | Actively quoted prices (Level 1) | $ | (102 | ) | | $ | (33 | ) | | $ | (18 | ) | | $ | 5 |
| | $ | 8 |
| | $ | — |
| | $ | (140 | ) | Prices provided by external sources (Level 2) | 161 |
| | 39 |
| | (9 | ) | | — |
| | — |
| | — |
| | 191 |
| Prices based on model or other valuation methods (Level 3)(c) | 383 |
| | 194 |
| | 85 |
| | 3 |
| | (18 | ) | | (131 | ) | | 516 |
| Total | $ | 442 |
| | $ | 200 |
| | $ | 58 |
| | $ | 8 |
| | $ | (10 | ) | | $ | (131 | ) | | $ | 567 |
|
__________
| | (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 to and received from counterparties (and offset against mark-to-market assets and liabilities) of $929 million at December 31, 2019. |
| | (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 | | 2020 | | 2021 | | 2022 | | 2023 | | 2024 | | 2025 and Beyond | | Normal Operations, Commodity derivative contracts(a)(b): | | | | | | | | | | | | | | Actively quoted prices (Level 1) | $ | (102 | ) | | $ | (33 | ) | | $ | (18 | ) | | $ | 5 |
| | $ | 8 |
| | $ | — |
| | $ | (140 | ) | Prices provided by external sources (Level 2) | 161 |
| | 39 |
| | (9 | ) | | — |
| | — |
| | — |
| | 191 |
| Prices based on model or other valuation methods (Level 3) | 415 |
| | 223 |
| | 113 |
| | 30 |
| | 10 |
| | 26 |
| | 817 |
| Total | $ | 474 |
| | $ | 229 |
| | $ | 86 |
| | $ | 35 |
| | $ | 18 |
| | $ | 26 |
| | $ | 868 |
|
__________
| | (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 to and received from counterparties (and offset against mark-to-market assets and liabilities) of $929 million at December 31, 2019. |
ComEd
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Maturities Within | | Fair Value | Commodity derivative contracts (a) | 2020 | | 2021 | | 2022 | | 2023 | | 2024 | | 2025 and Beyond | | Prices based on model or other valuation methods (Level 3)(a) | $ | (32 | ) | | $ | (29 | ) | | $ | (28 | ) | | $ | (27 | ) | | $ | (28 | ) | | $ | (157 | ) | | $ | (301 | ) |
__________
| | (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 and increases 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 contractsnatural gas prices at the reporting date.Generation. See Note 15—Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for a detailed discussion of credit risk.
Generation
The following tables provide information on Generation’s credit exposure for all derivative instruments, normal purchases6 — Accounts Receivable and normal sales agreements, and payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of December 31, 2019. 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 figures in the table 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 December 31, 2019 | 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 | $ | 877 |
| | $ | 20 |
| | $ | 857 |
| | — |
| | $ | — |
| Non-investment grade | 79 |
| | 63 |
| | 16 |
| | — |
| | — |
| No external ratings | | | | | | | | | | Internally rated—investment grade | 218 |
| | — |
| | 218 |
| | — |
| | — |
| Internally rated—non-investment grade | 139 |
| | 23 |
| | 116 |
| | — |
| | — |
| Total | $ | 1,313 |
| | $ | 106 |
| | $ | 1,207 |
| | — |
| | $ | — |
|
| | | | | | | | | | | | | | | | | | Maturity of Credit Risk Exposure | Rating as of December 31, 2019 | Less than 2 Years | | 2-5 Years | | Exposure Greater than 5 Years | | Total Exposure Before Credit Collateral | Investment grade | $ | 834 |
| | $ | 40 |
| | $ | 3 |
| | $ | 877 |
| Non-investment grade | 78 |
| | 1 |
| | — |
| | 79 |
| No external ratings | | | | | | | | Internally rated—investment grade | 162 |
| | 30 |
| | 26 |
| | 218 |
| Internally rated—non-investment grade | 123 |
| | 10 |
| | 6 |
| | 139 |
| Total | $ | 1,197 |
| | $ | 81 |
| | $ | 35 |
| | $ | 1,313 |
|
| | | | | Net Credit Exposure by Type of Counterparty | As of December 31, 2019 | Financial institutions | $ | 9 |
| Investor-owned utilities, marketers, power producers | 930 |
| Energy cooperatives and municipalities | 235 |
| Other | 33 |
| Total | $ | 1,207 |
|
__________
| | (a) | As of December 31, 2019, credit collateral held from counterparties where Generation had credit exposure included $25 million of cash and $81 million of letters of credit. |
The Utility Registrants
Credit risk for the Utility Registrants is governed by credit and collection policies, which are aligned with state regulatory requirements. The Utility Registrants are currently obligated to provide service to all electric customers within their franchised territories. The Utility Registrants record a provision for uncollectible accounts, based upon historical experience, to provide for the potential loss from nonpayment by these customers. The Utility Registrants will monitor nonpayment from customers and will make any necessary adjustments to the provision for uncollectible accounts. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for the allowance for uncollectible accounts policy. The Utility Registrants did not have any customers representing over 10% of their revenues as of December 31, 2019. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.information on the sales of customer accounts receivable and on the February 2021 extreme cold weather event, respectively.
AsCash Flows from Investing Activities (All Registrants)
The following table provides a summary of the change in cash flows from investing activities for the years ended December 31, 2019, ComEd, PECO, BGE, Pepco, DPL2021 and ACE's net credit exposure2020 by Registrant: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Increase (decrease) in cash flows from investing activities | Exelon | | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Capital expenditures | $ | 67 | | | | | $ | (170) | | | $ | (93) | | | $ | 21 | | | $ | (116) | | | $ | (70) | | | $ | (5) | | | $ | (44) | | Investment in NDT fund sales, net | (18) | | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | | | | | | | | | | | | | | | | | | Collection of DPP | 131 | | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Proceeds from sales of assets and businesses | 831 | | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Changes in intercompany money pool | — | | | | | — | | | (68) | | | — | | | — | | | — | | | — | | | — | | Other investing activities | 8 | | | | | 24 | | | 2 | | | 16 | | | (5) | | | (1) | | | 7 | | | (5) | | Increase (decrease) in cash flows from investing activities | $ | 1,019 | | | | | $ | (146) | | | $ | (159) | | | $ | 37 | | | $ | (121) | | | $ | (71) | | | $ | 2 | | | $ | (49) | |
Significant investing cash flow impacts for the Registrants for 2021 and 2020 were as follows: •Variances in capital expenditures are primarily due to suppliers was immaterial. the timing of cash expenditures for capital projects. See the "Credit Matters" section below for additional information on projected capital expenditure spending. •See Note 156 — Derivative Financial InstrumentsAccounts Receivable of the Combined Notes to Consolidated Financial Statements.Statements for additional information on the Collection of DPP. Credit-Risk-Related Contingent Features•Proceeds from sales of assets and businesses increased primarily due to the sale of a significant portion of Exelon's solar business and a biomass facility and proceeds received on sales of equity investments. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information on the sale of Exelon's solar business and biomass facility.
•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 (All Registrants) The following table provides a summary of the change in cash flows from financing activities for the years ended December 31, 2021 and 2020 by Registrant: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Increase (decrease) in cash flows from financing activities | Exelon | | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Changes in short-term borrowings, net | $ | 638 | | | | | $ | (516) | | | $ | — | | | $ | 206 | | | $ | (60) | | | $ | 187 | | | $ | (87) | | | $ | (160) | | Long-term debt, net | 774 | | | | | 300 | | | 100 | | | (100) | | | 91 | | | (22) | | | 27 | | | 86 | | Changes in intercompany money pool | — | | | | | — | | | (80) | | | — | | | (23) | | | — | | | — | | | — | | | | | | | | | | | | | | | | | | | | Dividends paid on common stock | (5) | | | | | (8) | | | 1 | | | (46) | | | — | | | (36) | | | (6) | | | (174) | | Acquisition of noncontrolling interest | (885) | | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Distributions to member | — | | | | | — | | | — | | | — | | | (150) | | | — | | | — | | | — | | Contributions from/(to) parent/member | — | | | | | 79 | | | 166 | | | (154) | | | 189 | | | (18) | | | 8 | | | 202 | | | | | | | | | | | | | | | | | | | | Other financing activities | 91 | | | | | (3) | | | (5) | | | 2 | | | (7) | | | — | | | (3) | | | (4) | | Increase (decrease) in cash flows from financing activities | $ | 613 | | | | | $ | (148) | | | $ | 182 | | | $ | (92) | | | $ | 40 | | | $ | 111 | | | $ | (61) | | | $ | (50) | |
Significant financing cash flow impacts for the Registrants for 2021 and 2020 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 17 - 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 debt issuances and redemptions tables below for additional information. •Changes inintercompany 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 19 - Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements 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. •Other financing activities primarily consists of debt issuance costs. See debt issuances table below for additional information on the Registrants’ debt issuances.
Debt Issuances and Redemptions See Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of the Registrants’ long-term debt. Debt activity for 2021 and 2020 by Registrant was as follows: During 2021, the following long-term debt was issued: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Company/Subsidiary | | Type | | Interest Rate | | Maturity | | Amount | | Use of Proceeds | Exelon(a) | | Long-Term Software License Agreements | | 3.62 | % | | December 1, 2025 | | $ | 4 | | | Procurement of software licenses. | 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(b) | | First Mortgage Bonds | | 3.24 | % | | March 30, 2051 | | 125 | | Repay existing indebtedness and for general corporate purposes. | ACE | | First Mortgage Bonds | | 2.30 | % | | March 15, 2031 | | 350 | | Refinance existing indebtedness, repay outstanding commercial paper obligations, and for general corporate purposes. | ACE(c) | | First Mortgage Bonds | | 2.27 | % | | February 15, 2032 | | 75 | | Repay existing indebtedness and for general corporate purposes. | Generation | | West Medway II Nonrecourse Debt(d) | | LIBOR + 3%(e) | | March 31, 2026 | | 150 | | Funding for general corporate purposes. | Generation | | Energy Efficiency Project Financing(f) | | 2.53% - 4.24% | | January 31, 2022 - February 28, 2022 | | 2 | | Funding to install energy conservation measures. | | | | | | | | | | | |
__________ (a)In connection with the separation, Exelon Corporate entered into three 18-month term loan agreements. On January 21, 2022, two of the loan agreements were issued for $300 million each with an expiration date of July 21, 2023. On January 24, 2022, the third loan agreement was issued for $250 million with an expiration date of July 24, 2023. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to SOFR plus 0.65%. (b)On November 16, 2021, DPL entered into a purchase agreement of First Mortgage Bonds of $125 million at 3.06% due on February 15, 2052. The closing date of the issuance occurred on February 15, 2022. (c)On November 16, 2021, ACE entered into a purchase agreement of First Mortgage Bonds of $25 million and $150 million at 2.27% and 3.06% due on February 15, 2032 and February 15, 2052, respectively. The closing date of the issuance occurred on February 15, 2022. (d)See Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on nonrecourse debt. (e)The nonrecourse debt has an average blended interest rate.
(f)For Energy Efficiency Project Financing, the maturity dates represent the expected date of project completion, upon which the respective customer assumes the outstanding debt.
During 2020, the following long-term debt was issued: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Company/Subsidiary | | Type | | Interest Rate | | Maturity | | Amount | | Use of Proceeds | Exelon | | Notes | | 4.05 | % | | April 15, 2030 | | $ | 1,250 | | | Repay existing indebtedness and for general corporate purposes. | Exelon | | Notes | | 4.70 | % | | April 15, 2050 | | 750 | | Repay existing indebtedness and for general corporate purposes. | ComEd | | First Mortgage Bonds, Series 128 | | 2.20 | % | | March 1, 2030 | | 350 | | Repay a portion of outstanding commercial paper obligations and fund other general corporate purposes. | ComEd | | First Mortgage Bonds, Series 129 | | 3.00 | % | | March 1, 2050 | | 650 | | Repay a portion of outstanding commercial paper obligations and fund other general corporate purposes. | PECO | | First and Refunding Mortgage Bonds | | 2.80 | % | | June 15, 2050 | | 350 | | Funding for general corporate purposes. | BGE | | Senior Notes | | 2.90 | % | | June 15, 2050 | | 400 | | Repay commercial paper obligations and for general corporate purposes. | Pepco | | First Mortgage Bonds | | 2.53 | % | | February 25, 2030 | | 150 | | Repay existing indebtedness and for general corporate purposes. | Pepco | | First Mortgage Bonds | | 3.28 | % | | September 23, 2050 | | 150 | | Repay existing indebtedness and for general corporate purposes. | DPL | | First Mortgage Bonds | | 2.53 | % | | June 9, 2030 | | 100 | | Repay existing indebtedness and for general corporate purposes. | DPL | | Tax-Exempt Bonds(a) | | 1.05 | % | | January 1, 2031 | | 78 | | Refinance existing indebtedness. | ACE | | Tax-Exempt First Mortgage Bonds | | 2.25 | % | | June 1, 2029 | | 23 | | Refinance existing indebtedness. | ACE | | First Mortgage Bonds | | 3.24 | % | | June 9, 2050 | | 100 | | Repay existing indebtedness and for general corporate purposes. | Generation | | Senior Notes | | 3.25 | % | | June 1, 2025 | | 900 | | Repay existing indebtedness and for general corporate purposes. | Generation | | Constellation Renewables Nonrecourse Debt(b) | | LIBOR + 2.75% | | December 15, 2027 | | 750 | | Repay existing indebtedness and for general corporate purposes. | Generation | | Energy Efficiency Project Financing(c) | | 2.53% - 3.95% | | February 28, 2021 - March 31, 2021 | | 6 | | Funding to install energy conservation measures. |
__________ (a)The bonds have a 1.05% interest rate through July 2025. (b)See Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on nonrecourse debt. (c)For Energy Efficiency Project Financing, the maturity dates represent the expected date of project completion, upon which the respective customer assumes the outstanding debt.
During 2021, the following long-term debt was retired and/or redeemed: | | | | | | | | | | | | | | | | | | | | | | | | | | | Company/Subsidiary | | Type | | Interest Rate | | Maturity | | Amount | Exelon | | Senior Notes(a) | | 2.45% | | April 15, 2021 | | $ | 300 | | Exelon | | Long-Term Software License Agreements | | 3.95% | | May 1, 2024 | | 24 | Exelon | | Long-Term Software License Agreements | | 3.62% | | December 1, 2025 | | 1 | | 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 | | 21 | Generation | | Continental Wind Nonrecourse Debt(b) | | 6.00% | | February 28, 2033 | | 35 | Generation | | CR 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 | | 24 | Generation | | West Medway II Nonrecourse Debt(b) | | LIBOR + 3%(d) | | March 31, 2026 | | 13 | Generation | | RPG Nonrecourse Debt(b) | | 4.11% | | March 31, 2035 | | 9 | | | | | | | | | | | | | | | | | | | | | | | | | | | |
__________ (a)As part of the 2012 Constellation merger, Exelon entered intercompany loan agreements that mirrored the terms and amounts of the third-party debt obligations. In connection with the separation, on January 31, 2022, Exelon Corporate received cash from Generation of $258 million to settle the intercompany loan. See Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the mirror debt. (b)See Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements 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.
During 2020, the following long-term debt was retired and/or redeemed: | | | | | | | | | | | | | | | | | | | | | | | | | | | Company/Subsidiary | | Type | | Interest Rate | | Maturity | | Amount | Exelon | | Notes | | 2.85% | | June 15, 2020 | | $ | 900 | | Exelon | | Long-Term Software License Agreements | | 3.95% | | May 1, 2024 | | 24 | ComEd | | First Mortgage Bonds | | 4.00% | | August 1, 2020 | | 500 | DPL | | Tax-Exempt Bonds | | 5.40% | | February 1, 2031 | | 78 | ACE | | Tax-Exempt First Mortgage Bonds | | 4.88% | | June 1, 2029 | | 23 | ACE | | Transition Bonds | | 5.55% | | October 20, 2023 | | 20 | Generation | | Senior Notes | | 2.95% | | January 15, 2020 | | 1,000 | Generation | | Senior Notes | | 4.00% | | October 1, 2020 | | 550 | Generation | | Senior Notes(a) | | 5.15% | | December 1, 2020 | | 550 | Generation | | Tax-Exempt Bonds | | 2.50% - 2.70% | | December 1, 2025 - June 1, 2036 | | 412 | Generation | | CR Nonrecourse Debt(b) | | 3-month LIBOR + 3.00% | | November 30, 2024 | | 796 | Generation | | Continental Wind Nonrecourse Debt(b) | | 6.00% | | February 28, 2033 | | 33 | Generation | | Antelope Valley DOE Nonrecourse Debt(b) | | 2.29% - 3.56% | | January 5, 2037 | | 23 | Generation | | RPG Nonrecourse Debt(b) | | 4.11% | | March 31, 2035 | | 9 | Generation | | Energy Efficiency Project Financing | | 3.71% | | December 31, 2020 | | 4 | Generation | | NUKEM | | 3.15% | | September 30, 2020 | | 3 | Generation | | SolGen Nonrecourse Debt | | 3.93% | | September 30, 2036 | | 3 | Generation | | Energy Efficiency Project Financing | | 4.12% | | November 30, 2020 | | 1 | | | | | | | | | | | | | | | | | | | | | | | | | | | |
__________ (a)The senior notes are legacy Constellation mirror debt that were previously held at Exelon. As part of the 2012 Constellation merger, Exelon assumed intercompany loan agreements that mirrored the terms and amounts of external obligations held by Exelon. See Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. (b)See Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of nonrecourse debt. From time to time and as market conditions warrant, the Registrants may engage in long-term debt retirements via tender offers, open market repurchases or other viable options to reduce debt on their respective balance sheets. Dividends Quarterly dividends declared by the Exelon Board of Directors during the year ended December 31, 2021 and for the first quarter of 2022 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 | | First Quarter 2022 | | February 8, 2022 | | February 25, 2022 | | March 10, 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 (All Registrants) The Registrants fund liquidity needs for capital expenditures, 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 $6.5 billion was available to support additional commercial paper as of December 31, 2021, and of which no financial institution has more than 7% of the aggregate commitments for the Registrants. 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 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. The Registrants had access to the commercial paper markets and had availability under their revolving credit facilities during 2021 to fund their short-term liquidity needs, when necessary. Exelon and Generation used their available credit facilities to manage short-term liquidity needs as a result of the impacts of the February 2021 extreme cold weather event. 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 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 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 to support the estimated future cash requirements discussed below. Pursuant to the Separation Agreement between Exelon and Constellation Energy Corporation, Exelon made a cash payment of $1.75 billion to Generation on January 31, 2022. See Note 26 — Separation 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 December 31, 2021 and available credit facility capacity prior to any incremental collateral at December 31, 2021: | | | | | | | | | | | | | | | | | | | PJM Credit Policy Collateral | | Other Incremental Collateral Required(a) | | Available Credit Facility Capacity Prior to Any Incremental Collateral | ComEd | $ | 28 | | | $ | — | | | $ | 998 | | PECO | 1 | | | 37 | | | 600 | | BGE | 4 | | | 78 | | | 470 | | Pepco | 3 | | | — | | | 125 | | DPL | 4 | | | 14 | | | 151 | | ACE | 1 | | | — | | | 155 | |
__________ (a)Represents incremental collateral related to natural gas procurement contracts.
Capital Expenditures As of December 31, 2021, estimates of capital expenditures for plant additions and improvements are as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (in millions) | 2022 Transmission | | 2022 Distribution | | 2022 Gas | | Total 2022(b) | | Beyond 2022(b)(c) | Exelon(a) | N/A | | N/A | | N/A | | $ | 8,600 | | | $ | 24,950 | | | | | | | | | | | | ComEd | 450 | | | 2,025 | | | N/A | | 2,475 | | | 7,775 | | PECO | 175 | | | 850 | | | 325 | | | 1,325 | | | 4,500 | | BGE | 275 | | | 500 | | | 475 | | | 1,225 | | | 4,100 | | PHI | 600 | | | 1,175 | | | 100 | | | 1,850 | | | 5,650 | | Pepco | 275 | | | 625 | | | N/A | | 900 | | | 2,750 | | DPL | 150 | | | 250 | | | 100 | | | 475 | | | 1,550 | | ACE | 175 | | | 300 | | | N/A | | 475 | | | 1,375 | |
___________ (a)Exelon's estimated capital expenditures include estimated capital expenditures for Generation. (b)Numbers rounded to the nearest $25M and may not sum due to rounding. (c)Includes estimated capital expenditures for the Utility Registrants from 2023 and 2025 and includes estimated capital expenditures for Generation from 2023 to 2024. Projected capital expenditures and other investments are subject to periodic review and revision to reflect changes in economic conditions and other factors. Projected capital expenditures at the Utility Registrants are for continuing projects to maintain and improve operations, including enhancing reliability and adding capacity to the transmission and distribution systems. The Utility Registrants anticipate that they will fund their capital expenditures with a combination of internally generated funds and borrowings and additional capital contributions from parent. Pension and Other Postretirement Benefits Management 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 pension obligation, and regulatory implications. The Act requires the attainment of certain funding levels to avoid benefit restrictions (such as an inability to pay lump sums or to accrue benefits prospectively), and at-risk status (which triggers higher minimum contribution requirements and participant notification). The projected contributions below 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. Based on this funding strategy and current market conditions, which are subject to change, Exelon’s estimated annual qualified pension contributions will be approximately $500 million in 2022. Exelon's estimated contributions include contributions related to Generation's qualified pension plans. In connection with the separation, an additional qualified pension contribution of $207 million was completed on February 1, 2022. 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 plans. For Exelon's funded OPEB plans, contributions generally equal accounting costs, however, Exelon’s management has historically considered several factors in determining the level of contributions to its OPEB plans, including liabilities management, levels of benefit claims paid, and regulatory implications (amounts deemed prudent to meet regulatory expectations and best assure continued rate recovery). The amounts below include benefit payments related to unfunded plans.
The following table provides all Registrants' planned contributions to the qualified pension plans, planned benefit payments to non-qualified pension plans, and planned contributions to OPEB plans in 2022: | | | | | | | | | | | | | | | | | | | Qualified Pension Plans | | Non-Qualified Pension Plans | | OPEB | Exelon(a) | $ | 505 | | | $ | 32 | | | $ | 50 | | | | | | | | ComEd | 173 | | | 2 | | | 12 | | PECO | 12 | | | 1 | | | 2 | | BGE | 48 | | | 2 | | | 16 | | | | | | | | PHI | 60 | | | 10 | | | 7 | | Pepco | 2 | | | 1 | | | 6 | | DPL | 1 | | | 1 | | | — | | ACE | 7 | | | — | | | — | | | | | | | | _________(a)Exelon's estimated contributions include contributions related to Generation's qualified pension plans. These payments are based on the combined plans, as of December 31, 2021 and do not reflect the impacts of the separation. To the extent interest rates decline significantly or the pension and OPEB plans earn less than the expected asset returns, annual pension contribution requirements in future years could increase. Conversely, to the extent interest rates increase significantly or the pension and OPEB plans earn greater than the expected asset returns, annual pension and OPEB contribution requirements in future years could decrease. Additionally, expected contributions could change if Exelon changes its pension or OPEB funding strategy. See Note 15 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information on pension and OPEB contributions. Cash Requirements for Other Financial Commitments The following tables summarize the Registrants' future estimated cash payments as of December 31, 2021 under existing financial commitments:
Exelon | | | | | | | | | | | | | | | | | | | | | | | | | 2022(a) | | Beyond 2022(a) | | Total(a) | | Time Period | Long-term debt(b) | $ | 3,357 | | | $ | 35,300 | | | $ | 38,657 | | | 2022 - 2053 | Interest payments on long-term debt(c) | 1,509 | | | 23,670 | | | 25,179 | | | 2022 - 2051 | Operating leases(d) | 99 | | | 937 | | | 1,036 | | | 2022 - 2106 | Purchase power obligations(e) | 620 | | | 1,109 | | | 1,729 | | | 2022 - 2036 | Fuel purchase agreements(f) | 1,303 | | | 5,446 | | | 6,749 | | | 2022 - 2054 | Electric supply procurement | 2,122 | | | 1,254 | | | 3,376 | | | 2022 - 2025 | Long-term renewable energy and REC commitments | 302 | | | 1,691 | | | 1,993 | | | 2022 - 2033 | Other purchase obligations(g) | 5,247 | | | 5,806 | | | 11,053 | | | 2022 - 2046 | DC PLUG obligation | 33 | | | 37 | | | 70 | | | 2022 - 2024 | SNF obligation | — | | | 1,210 | | | 1,210 | | | 2022 - 2035 | | | | | | | | | Pension contributions(h) | 505 | | | 190 | | | 695 | | | 2022 - 2027 | Total cash requirements | $ | 15,097 | | | $ | 76,650 | | | $ | 91,747 | | | |
__________ (a)Exelon's future estimated cash payments include future estimated cash payments for Generation. (b)Includes amounts from ComEd and PECO financing trusts. (c)Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2021 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2021. Includes estimated interest payments due to ComEd and PECO financing trusts. (d)Capacity payments associated with contracted generation lease agreements are net of sublease and capacity offsets of $57 million and $315 million for 2022 and beyond 2022, respectively, and $372 million in total. (e)Purchase power obligations primarily include expected payments for REC purchases and payments associated with contracted generation agreements, which may be reduced based on plant availability. Expected payments exclude payments on renewable generation contracts that are contingent in nature. (f)Represents commitments to purchase nuclear fuel, natural gas and related transportation, storage capacity, and services. (g)Represents the future estimated value at December 31, 2021 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between the Registrants or subsidiary and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period. (h)These amounts represent Exelon’s expected contributions to its qualified pension plans. Qualified pension contributions for years after 2027 are not included.
ComEd | | | | | | | | | | | | | | | | | | | | | | | | | 2022 | | Beyond 2022 | | Total | | Time Period | Long-term debt(a) | $ | — | | | $ | 10,084 | | | $ | 10,084 | | | 2022 - 2053 | Interest payments on long-term debt(b) | 394 | | | 7,467 | | | 7,861 | | | 2022 - 2051 | Operating leases | 2 | | | 3 | | | 5 | | | 2022 - 2025 | Electric supply procurement | 474 | | | 260 | | | 734 | | | 2022 - 2024 | Long-term renewable energy and REC commitments | 271 | | | 1,438 | | | 1,709 | | | 2022 - 2033 | Other purchase obligations(c) | 858 | | | 764 | | | 1,622 | | | 2022 - 2031 | ZEC commitments | 160 | | | 706 | | | 866 | | | 2022 - 2027 | Total cash requirements | $ | 2,159 | | | $ | 20,722 | | | $ | 22,881 | | | |
__________ (a)Includes amounts from ComEd financing trust. (b)Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2021 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. Includes estimated interest payments due to the ComEd financing trust. (c)Represents the future estimated value at December 31, 2021 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between ComEd and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period. PECO | | | | | | | | | | | | | | | | | | | | | | | | | 2022 | | Beyond 2022 | | Total | | Time Period | Long-term debt(a) | $ | 350 | | | $ | 4,084 | | | $ | 4,434 | | | 2022 - 2051 | Interest payments on long-term debt(b) | 166 | | | 3,213 | | | 3,379 | | | 2022 - 2051 | Operating leases | — | | | 1 | | | 1 | | | 2022 - 2034 | Fuel purchase agreements(c) | 140 | | | 271 | | | 411 | | | 2022 - 2029 | Electric supply procurement | 490 | | | 2 | | | 492 | | | 2022 - 2023 | Other purchase obligations(d) | 846 | | | 690 | | | 1,536 | | | 2022 - 2030 | Total cash requirements | $ | 1,992 | | | $ | 8,261 | | | $ | 10,253 | | | |
__________ (a)Includes amounts from PECO financing trusts. (b)Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2021 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. Includes estimated interest payments due to the PECO financing trusts. (c)Represents commitments to purchase natural gas and related transportation, storage capacity, and services. (d)Represents the future estimated value at December 31, 2021 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between PECO and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.
BGE | | | | | | | | | | | | | | | | | | | | | | | | | 2022 | | Beyond 2022 | | Total | | Time Period | Long-term debt | $ | 250 | | | $ | 3,750 | | | $ | 4,000 | | | 2022 - 2050 | Interest payments on long-term debt(a) | 138 | | | 2,312 | | | 2,450 | | | 2022 - 2050 | Operating leases | 16 | | | 19 | | | 35 | | | 2022 - 2106 | Fuel purchase agreements(b) | 112 | | | 481 | | | 593 | | | 2022 - 2038 | Electric supply procurement | 764 | | | 498 | | | 1,262 | | | 2022 - 2024 | Other purchase obligations(c) | 692 | | | 607 | | | 1,299 | | | 2022 - 2040 | Total cash requirements | $ | 1,972 | | | $ | 7,667 | | | $ | 9,639 | | | |
__________ (a)Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2021 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. (b)Represents commitments to purchase natural gas and related transportation, storage capacity, and services. (c)Represents the future estimated value at December 31, 2021 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between BGE and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period. PHI | | | | | | | | | | | | | | | | | | | | | | | | | 2022 | | Beyond 2022 | | Total | | Time Period | Long-term debt | $ | 387 | | | $ | 6,618 | | | $ | 7,005 | | | 2022 - 2051 | Interest payments on long-term debt(a) | 282 | | | 3,953 | | | 4,235 | | | 2022 - 2051 | Finance leases | 12 | | | 67 | | | 79 | | | 2022 - 2029 | Operating leases | 38 | | | 230 | | | 268 | | | 2022 - 2032 | Fuel purchase agreements(b) | 31 | | | 242 | | | 273 | | | 2022 - 2030 | Electric supply procurement | 1,097 | | | 754 | | | 1,851 | | | 2022 - 2025 | Long-term renewable energy and REC commitments | 31 | | | 253 | | | 284 | | | 2022 - 2032 | Other purchase obligations(c) | 1,016 | | | 1,031 | | | 2,047 | | | 2022 - 2029 | DC PLUG obligation | 33 | | | 37 | | | 70 | | | 2022 - 2024 | Total cash requirements | $ | 2,927 | | | $ | 13,185 | | | $ | 16,112 | | | |
__________ (a)Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2021 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2021. (b)Represents commitments to purchase natural gas and related transportation, storage capacity, and services. (c)Represents the future estimated value at December 31, 2021 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between Pepco, DPL, ACE, and PHISCO and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.
Pepco | | | | | | | | | | | | | | | | | | | | | | | | | 2022 | | Beyond 2022 | | Total | | Time Period | Long-term debt | $ | 309 | | | $ | 3,150 | | | $ | 3,459 | | | 2022 - 2051 | Interest payments on long-term debt(a) | 149 | | | 2,287 | | | 2,436 | | | 2022 - 2051 | Finance leases | 4 | | | 23 | | | 27 | | | 2022 - 2029 | Operating leases | 8 | | | 47 | | | 55 | | | 2022 - 2032 | Electric supply procurement | 498 | | | 384 | | | 882 | | | 2022 - 2025 | Other purchase obligations(b) | 603 | | | 551 | | | 1,154 | | | 2022 - 2026 | DC PLUG obligation | 33 | | | 37 | | | 70 | | | 2022 - 2024 | Total cash requirements | $ | 1,604 | | | $ | 6,479 | | | $ | 8,083 | | | |
__________ (a)Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2021 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. (b)Represents the future estimated value at December 31, 2021 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between Pepco and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period. DPL | | | | | | | | | | | | | | | | | | | | | | | | | 2022 | | Beyond 2022 | | Total | | Time Period | Long-term debt | $ | 78 | | | $ | 1,711 | | | $ | 1,789 | | | 2022 - 2051 | Interest payments on long-term debt(a) | 63 | | | 1,013 | | | 1,076 | | | 2022 - 2051 | Finance leases | 5 | | | 27 | | | 32 | | | 2022 - 2029 | Operating leases | 10 | | | 60 | | | 70 | | | 2022 - 2027 | Fuel purchase agreements(b) | 31 | | | 242 | | | 273 | | | 2022 - 2030 | Electric supply procurement | 298 | | | 187 | | | 485 | | | 2022 - 2024 | Long-term renewable energy and REC commitments | 31 | | | 253 | | | 284 | | | 2022 - 2032 | Other purchase obligations(c) | 214 | | | 192 | | | 406 | | | 2022 - 2028 | Total cash requirements | $ | 730 | | | $ | 3,685 | | | $ | 4,415 | | | |
__________ (a)Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2021 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2021. (b)Represents commitments to purchase natural gas and related transportation, storage capacity, and services. (c)Represents the future estimated value at December 31, 2021 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between DPL and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.
ACE | | | | | | | | | | | | | | | | | | | | | | | | | 2022 | | Beyond 2022 | | Total | | Time Period | Long-term debt | $ | — | | | $ | 1,572 | | | $ | 1,572 | | | 2022 - 2050 | Interest payments on long-term debt(a) | 56 | | | 519 | | | 575 | | | 2022 - 2050 | Finance leases | 3 | | | 17 | | | 20 | | | 2022 - 2029 | Operating leases | 4 | | | 9 | | | 13 | | | 2022 - 2027 | Electric supply procurement | 301 | | | 183 | | | 484 | | | 2022 - 2024 | Other purchase obligations(b) | 158 | | | 240 | | | 398 | | | 2022 - 2027 | Total cash requirements | $ | 522 | | | $ | 2,540 | | | $ | 3,062 | | | |
__________ (a)Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2021 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. (b)Represents the future estimated value at December 31, 2021 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between ACE and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period. See Note 19 — Commitments and Contingencies and Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information of the Registrants’ other commitments potentially triggered by future events. Additionally, see below for where to find additional information regarding the financial commitments in the tables above in the Combined Notes to the Consolidated Financial Statements: | | | | | | Item | Location within Notes to the Consolidated Financial Statements | Long-term debt | Note 17 — Debt and Credit Agreements | Interest payments on long-term debt | Note 17 — Debt and Credit Agreements | Finance leases | Note 11 — Leases | Operating leases | Note 11 — Leases | SNF obligation | Note 19 — Commitments and Contingencies | REC commitments | Note 3 — Regulatory Matters | ZEC commitments | Note 3 — Regulatory Matters | DC PLUG obligation | Note 3 — Regulatory Matters | Pension contributions | Note 15 — Retirement Benefits |
Credit Facilities (All Registrants) Exelon Corporate, ComEd, and BGE meet their short-term liquidity requirements primarily through the issuance of commercial paper. PECO meets 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 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ credit facilities and short term borrowing activity.
Capital Structure At December 31, 2021, the capital structures of the Registrants consisted of the following: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exelon | | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Long-term debt | 50 | % | | | | 44 | % | | 44 | % | | 45 | % | | 40 | % | | 49 | % | | 48 | % | | 48 | % | Long-term debt to affiliates(a) | 1 | % | | | | 1 | % | | 2 | % | | — | % | | — | % | | — | % | | — | % | | — | % | Common equity | 45 | % | | | | 55 | % | | 54 | % | | 53 | % | | — | % | | 49 | % | | 48 | % | | 48 | % | Member’s equity | — | % | | | | — | % | | — | % | | — | % | | 57 | % | | — | % | | — | % | | — | % | | | | | | | | | | | | | | | | | | | Commercial paper and notes payable | 4 | % | | | | — | % | | — | % | | 2 | % | | 3 | % | | 2 | % | | 4 | % | | 4 | % |
__________ (a)Includes approximately $390 million, $205 million, and $184 million owed to unconsolidated affiliates of Exelon, ComEd, and PECO respectively. These special purpose entities were created for the sole purposes of issuing mandatory redeemable trust preferred securities of ComEd and PECO. See Note 23 — Variable Interest Entities of the Combined Notes to Consolidated Financial Statements for additional information regarding the authoritative guidance for VIEs. 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, Generation routinely entersthe Registrants enter into physicalcontracts that contain express provisions or financial contractsotherwise permit the Registrants and their counterparties to demand adequate assurance of future performance when there are reasonable grounds for the sale and purchase of electricity, natural gas and other commodities.doing so. In accordance with the contracts and applicable contracts law, if Generation isthe Registrants are 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 demandperformance, which could be forinclude the posting of additional 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 1516 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regardingon collateral requirements. See Note 18 — Commitmentsprovisions. The credit ratings for Exelon Corporate and Contingenciesthe Utility Registrants did not change for the year ended December 31, 2021. On January 14, 2022, Fitch lowered Exelon Corporate's long-term rating 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+ and upgraded Pepco and ACE's senior secured rating from A- to 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 December 31, 2021, are presented in the following tables. ACE did not have any intercompany money pool activity as of December 31, 2021. | | | | | | | | | | | | | | | | | | | For the Year Ended December 31, 2021 | | As of December 31, 2021 | Exelon Intercompany Money Pool | Maximum Contributed | | Maximum Borrowed | | Contributed (Borrowed) | Exelon Corporate | $ | 735 | | | $ | — | | | $ | 217 | | Generation | — | | | (426) | | | — | | PECO | 303 | | | (100) | | | — | | BSC | — | | | (435) | | | (260) | | PHI Corporate | — | | | (40) | | | (7) | | PCI | 60 | | | — | | | 50 | |
| | | | | | | | | | | | | | | | | | | For the Year Ended December 31, 2021 | | As of December 31, 2021 | PHI Intercompany Money Pool | Maximum Contributed | | Maximum Borrowed | | Contributed (Borrowed) | | | | | | | Pepco | $ | — | | | $ | (30) | | | $ | — | | DPL | 30 | | | — | | | — | | | | | | | | | | | | | |
Shelf Registration Statements (All Registrants) Exelon 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 Combined Notes to Consolidated Financial Statements for additional information regardingproposed sale, including other required regulatory approvals, as applicable, the letterscurrent financial condition of credit supporting the cash collateral.Registrant, its securities ratings and market conditions. Generation transacts output through bilateral contracts. Regulatory Authorizations (All Registrants)
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, counterpartiesUtility Registrants are required to post collateralobtain short-term and long-term financing authority from Federal and State Commissions as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | As of December 31, 2021 | | | Short-term Financing Authority(a) | | Remaining Long-term Financing Authority | Commission | | Expiration Date | | Amount | Commission | | Expiration Date | | Amount | ComEd(b) | | FERC | | December 31, 2023 | | $ | 2,500 | | | ICC | | January 1, 2025 | | $ | 2,093 | | PECO(c) | | FERC | | December 31, 2023 | | 1,500 | | | PAPUC | | December 31, 2024 | | 1,900 | | BGE | | FERC | | December 31, 2023 | | 700 | | | MDPSC | | N/A | | 500 | | Pepco | | FERC | | December 31, 2023 | | 500 | | | MDPSC / DCPSC | | December 31, 2022 | | 625 | | DPL | | FERC | | December 31, 2023 | | 500 | | | MDPSC / DEPSC | | December 31, 2022 | | 172 | | ACE(d) | | NJBPU | | December 31, 2023 | | 350 | | | NJBPU | | December 31, 2022 | | 175 | |
__________ (a)On October 15, 2021, ComEd, PECO, BGE, Pepco, and DPL filed applications with Generation. To post collateral, Generation dependsFERC and on access to bank credit facilities, which serve as liquidity sources to fund collateral requirements. See ITEM 7. LiquidityJuly 21, 2021, ACE filed an application with NJBPU for renewal of their short-term financing authority through December 31, 2023. ComEd received approval on December 16, 2021, PECO and Capital Resources — Credit Matters — Exelon Credit FacilitiesBGE received approval on December 23, 2021, Pepco and DPL received approval on December 28, 2021, and ACE received approval on December 1, 2021. (b)On November 18, 2021, ComEd had an additional $2 billion in new money long-term debt financing authority from the ICC with an effective date of January 1, 2022 and an expiration date of January 1, 2025. (c)On December 2, 2021, PECO received approval from the PAPUC for additional information.$2.5 billion in new long-term debt financing authority with an effective date of January 1, 2022.
(d)ACE is currently in the process of renewing its long-term financing authority with the NJBPU and expects approval by August 1, 2022. | | | | | | ITEM 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
The Registrants are exposed to market risks associated with adverse changes in commodity prices, counterparty credit, interest rates, and equity prices. 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. Historically, reporting on risk management issues has been to Exelon’s Risk Management Committee, the Risk Management Committees of each Utility RegistrantsRegistrant, and the Risk Committee of Exelon’s Board of Directors. After separation, reporting on risk management issues will be to Exelon’s Executive Committee, the Risk Management Committees of each Utility Registrant, and the Audit and Risk Committee of Exelon’s Board of Directors. AsCommodity 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. Generation Electricity available from Generation’s owned or contracted generation supply in excess of Generation’s obligations to customers, including portions of the Utility Registrants' retail load, is sold into the wholesale markets. To reduce commodity 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. We expect the settlement of the majority of our economic hedges will occur during 2022 through 2024. In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on Generation’s owned and contracted generation positions which have not been hedged. For merchant revenues not already hedged via comprehensive state programs, such as the CMC in Illinois, we utilize a three-year ratable sales plan to align our hedging strategy with our financial objectives. The prompt three-year merchant revenues are hedged on an approximate rolling 90%/60%/30% basis. We may also enter transactions that are outside of this ratable hedging program.As of December 31, 2019,2021, the Utility Registrants were not requiredpercentage of expected generation hedged for the Mid-Atlantic, Midwest, New York, and ERCOT reportable segments is 92%-95% and 73%-76% for 2022 and 2023, respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation. Expected generation is the volume of energy that best represents our commodity position in energy markets from owned or contracted generation based upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to post collateral under theirmarket quotes for power, fuel, load following products and options. Equivalent sales represent all hedging products, which include economic hedges, CMC payments, and certain non-derivative contracts. A portion of Generation’s hedging strategy may be accomplished with fuel products based on assumed correlations between power and fuel prices, which routinely change in the market. Market price risk exposure is the risk of a change in the value of unhedged positions. The forecasted market price risk exposure for Generation’s entire economic hedge portfolio associated with a $5/MWh reduction in the annual average around-the-clock energy and/or natural gas procurement contracts.price based on December 31, 2021 market conditions and hedged position would be a decrease in pre-tax net income of approximately $20 million and $243 million for 2022 and 2023, respectively. Power price sensitivities are derived by adjusting power price assumptions while keeping all other price inputs constant. Generation actively manages its portfolio to mitigate market price risk exposure for its unhedged position. Actual results could differ depending on the specific timing of, and markets affected by, price changes, as well as future changes in Generation’s portfolio. See Note 3 — Regulatory Matters and Note 1516 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information. RTOs and ISOs (All Registrants)
All Registrants participate in all, or some, of the established, wholesale spot energy markets that are administered by PJM, ISO-NE, NYISO, CAISO, MISO, SPP, AESO, OIESO and ERCOT. ERCOT is not subject to regulation by FERC but performs a similar function in Texas to that performed by RTOs in markets regulated by FERC. In these areas, power is traded through bilateral agreements between buyers and sellers and on the spot energy markets that are administered by the RTOs or ISOs, as applicable. In areas where there is no spot energy market, electricity is purchased and sold solely through bilateral agreements. For sales into the spot markets administered by an RTO or ISO, the RTO or ISO maintains financial assurance policies that are established and enforced by those administrators. The credit policies of the RTOs and ISOs 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.
Non-performance or non-payment by a major counterparty could result in a material adverse impact on the Registrants’ financial statements.
Exchange Traded Transactions (Exelon, Generation, PHI and DPL)
Generation enters into commodity transactions on NYMEX, ICE, NASDAQ, NGX and the Nodal exchange ("the Exchanges"). DPL enters into commodity transactions on ICE. The Exchange clearinghouses act as the counterparty to each trade. Transactions on the Exchanges must adhere to comprehensive collateral and margining requirements. As a result, transactions on Exchanges are significantly collateralized and have limited counterparty credit risk.
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 $5 million decrease in Exelon pre-tax income for the year ended December 31, 2019. 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 15—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 December 31, 2019, 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 10% increase in interest rates and decrease in equity prices would result in a $610 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. See Liquidity and Capital Resources section of ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS for additional information of equity price risk as a result of the current capital and credit market conditions.
| | | ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
Generation
General
Generation’s integrated business consists of the generation, physical delivery and marketing of power across multiple geographical regions through its customer-facing business, Constellation, which sells electricity and natural gas to both wholesale and retail customers. Generation also sells renewable energy and other energy-related products and services. Generation has five reportable segments consisting of the Mid-Atlantic, Midwest, New York, ERCOT and Other Power Regions. These segments are discussed in further detail in ITEM 1. BUSINESS — Exelon Generation Company, LLC of this Form 10-K.
Executive Overview
A discussion of items pertinent to Generation’s executive overview is set forth under ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Exelon Corporation — Executive Overview of this Form 10-K.
Results of Operations
Year Ended December 31, 2019 Compared to Year Ended December 31, 2018
A discussion of Generation’s results of operations for 2019 compared to 2018 is set forth under Results of Operations—Generation in EXELON CORPORATION — Results of Operations of this Form 10-K.
Liquidity and Capital Resources
Generation’s business is capital intensive and requires considerable capital resources. Generation’s capital resources are primarily provided by internally generated cash flows from operations and, to the extent necessary, external financing, including the issuance of long-term debt, commercial paper, participation in the intercompany money pool or capital contributions from Exelon. Generation’s access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of the utility industry in general. If these conditions deteriorate to where Generation no longer has access to the capital markets at reasonable terms, Generation has credit facilities in the aggregate of $5.3 billion that currently support its commercial paper program and issuances of letters of credit.
See EXELON CORPORATION — Liquidity and Capital Resources and Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements of this Form 10-K for additional information.
Capital resources are used primarily to fund Generation’s capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and other postretirement benefit obligations and invest in new and existing ventures. Generation spends a significant amount of cash on capital improvements and construction projects that have a long-term return on investment.
Cash Flows from Operating Activities
A discussion of items pertinent to Generation’s cash flows from operating activities is set forth under Cash Flows from Operating Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Cash Flows from Investing Activities
A discussion of items pertinent to Generation’s cash flows from investing activities is set forth under Cash Flows from Investing Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Cash Flows from Financing Activities
A discussion of items pertinent to Generation’s cash flows from financing activities is set forth under Cash Flows from Financing Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Credit Matters
A discussion of credit matters pertinent to Generation is set forth under Credit Matters in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Contractual Obligations and Off-Balance Sheet Arrangements
A discussion of Generation’s contractual obligations, commercial commitments and off-balance sheet arrangements is set forth under Contractual Obligations and Off-Balance Sheet Arrangements in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Critical Accounting Policies and Estimates
See All Registrants — Critical Accounting Policies and Estimates above for a discussion of Generation’s critical accounting policies and estimates.
New Accounting Pronouncements
See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for information regarding new accounting pronouncements.
| | | ITEM 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
Generation
Generation is exposed to market risks associated with credit, interest rates and equity price. These risks are described above under Quantitative and Qualitative Disclosures about Market Risk — Exelon.
| | | ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
ComEd
General
ComEd operates in a single business segment and its operations consist of the purchase and regulated retail sale of electricity and the provision of distribution and transmission services to retail customers in northern Illinois, including the City of Chicago. This segment is discussed in further detail in ITEM 1. BUSINESS—ComEd of this Form 10-K.
Executive Overview
A discussion of items pertinent to ComEd’s executive overview is set forth under EXELON CORPORATION—Executive Overview of this Form 10-K.
Results of Operations
Year Ended December 31, 2019 Compared to Year Ended December 31, 2018
A discussion of ComEd’s results of operations for 2019 compared to 2018 is set forth under Results of Operations—ComEd in EXELON CORPORATION — Results of Operations of this Form 10-K.
Liquidity and Capital Resources
ComEd’s business is capital intensive and requires considerable capital resources. ComEd’s capital resources are primarily provided by internally generated cash flows from operations and, to the extent necessary, external financing, including the issuance of long-term debt, commercial paper or credit facility borrowings. ComEd’s access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of the utility industry in general. At December 31, 2019, ComEd had access to a revolving credit facility with aggregate bank commitments of $1 billion.
See EXELON CORPORATION — Liquidity and Capital Resources and Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements of this Form 10-K for additional information.
Capital resources are used primarily to fund ComEd’s capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and other postretirement benefit obligations and invest in new and existing ventures. ComEd spends a significant amount of cash on capital improvements and construction projects that have a long-term return on investment. Additionally, ComEd operates in rate-regulated environments in which the amount of new investment recovery may be limited and where such recovery takes place over an extended period of time.
Cash Flows from Operating Activities
A discussion of items pertinent to ComEd’s cash flows from operating activities is set forth under Cash Flows from Operating Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Cash Flows from Investing Activities
A discussion of items pertinent to ComEd’s cash flows from investing activities is set forth under Cash Flows from Investing Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Cash Flows from Financing Activities
A discussion of items pertinent to ComEd’s cash flows from financing activities is set forth under Cash Flows from Financing Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Credit Matters
A discussion of credit matters pertinent to ComEd is set forth under Credit Matters in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Contractual Obligations and Off-Balance Sheet Arrangements
A discussion of ComEd’s contractual obligations, commercial commitments and off-balance sheet arrangements is set forth under Contractual Obligations and Off-Balance Sheet Arrangements in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Critical Accounting Policies and Estimates
See All Registrants — Critical Accounting Policies and Estimates above for a discussion of ComEd’s critical accounting policies and estimates.
New Accounting Pronouncements
See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for information regarding new accounting pronouncements.
| | | ITEM 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
ComEd
ComEd is exposed to market risks associated with commodity price and credit. These risks are described above under Quantitative and Qualitative Disclosures about Market Risk— Exelon.
| | | ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
PECO
General
PECO operates in a single business segment and its operations consist of the purchase and regulated retail sale of electricity and the provision of distribution and transmission services in southeastern Pennsylvania including the City of Philadelphia, and the purchase and regulated retail sale of natural gas and the provision of distribution service in Pennsylvania in the counties surrounding the City of Philadelphia. This segment is discussed in further detail in ITEM 1. BUSINESS—PECO of this Form 10-K.
Executive Overview
A discussion of items pertinent to PECO’s executive overview is set forth under EXELON CORPORATION—Executive Overview of this Form 10-K.
Results of Operations
Year Ended December 31, 2019 Compared to Year Ended December 31, 2018
A discussion of PECO’s results of operations for 2019 compared to 2018 is set forth under Results of Operations—PECO in EXELON CORPORATION — Results of Operations of this Form 10-K.
Liquidity and Capital Resources
PECO’s business is capital intensive and requires considerable capital resources. PECO’s capital resources are primarily provided by internally generated cash flows from operations and, to the extent necessary, external financing, including the issuance of long-term debt, commercial paper or participation in the intercompany money pool. PECO’s access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of the utility industry in general. If these conditions deteriorate to where PECO no longer has access to the capital markets at reasonable terms, PECO has access to a revolving credit facility. At December 31, 2019, PECO had access to a revolving credit facility with aggregate bank commitments of $600 million.
See EXELON CORPORATION — Liquidity and Capital Resources and Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements of this Form 10-K for additional information.
Capital resources are used primarily to fund PECO’s capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and other postretirement benefit obligations and invest in new and existing ventures. PECO spends a significant amount of cash on capital improvements and construction projects that have a long-term return on investment. Additionally, PECO operates in a rate-regulated environment in which the amount of new investment recovery may be limited and where such recovery takes place over an extended period of time.
Cash Flows from Operating Activities
A discussion of items pertinent to PECO’s cash flows from operating activities is set forth under Cash Flows from Operating Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Cash Flows from Investing Activities
A discussion of items pertinent to PECO’s cash flows from investing activities is set forth under Cash Flows from Investing Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Cash Flows from Financing Activities
A discussion of items pertinent to PECO’s cash flows from financing activities is set forth under Cash Flows from Financing Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Credit Matters
A discussion of credit matters pertinent to PECO is set forth under Credit Matters in “EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Contractual Obligations and Off-Balance Sheet Arrangements
A discussion of PECO’s contractual obligations, commercial commitments and off-balance sheet arrangements is set forth under Contractual Obligations and Off-Balance Sheet Arrangements in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Critical Accounting Policies and Estimates
See All Registrants — Critical Accounting Policies and Estimates above for a discussion of PECO’s critical accounting policies and estimates.
New Accounting Pronouncements
See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for information regarding new accounting pronouncements.
| | | ITEM 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
PECO
PECO is exposed to market risks associated with credit and interest rates. These risks are described above under Quantitative and Qualitative Disclosures about Market Risk—Exelon.
| | | ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
BGE
General
BGE operates in a single business segment and its operations consist of the purchase and regulated retail sale of electricity and the provision of distribution and transmission services in central Maryland, including the City of Baltimore, and the purchase and regulated retail sale of natural gas and the provision of distribution service in central Maryland, including the City of Baltimore. This segment is discussed in further detail in ITEM 1. BUSINESS—BGE of this Form 10-K.
Executive Overview
A discussion of items pertinent to BGE’s executive overview is set forth under EXELON CORPORATION — Executive Overview of this Form 10-K.
Results of Operations
Year Ended December 31, 2019 Compared to Year Ended December 31, 2018
A discussion of BGE’s results of operations for 2019 compared to 2018 is set forth under Results of Operations—BGE in EXELON CORPORATION — Results of Operations of this Form 10-K.
Liquidity and Capital Resources BGE’s business is capital intensiveAll results included throughout the liquidity and requires considerable capital resources. BGE’s capital resources section are primarilypresented on a GAAP basis.
The Registrants’ operating and capital expenditures requirements are provided by internally generated cash flows from operations, and, to the extent necessary, external financing, including the issuancesale of long-term debt or commercial paper. BGE’s access to external financing at reasonable terms is dependent on its credit ratings and general business conditions,certain receivables, as well as that of the utility industryfunds from external sources in general. If these conditions deteriorate to where BGE no longer has access to the capital markets at reasonable terms, BGE has access to a revolving credit facility. At December 31, 2019, BGE had access to a revolving credit facility with aggregateand through bank commitments of $600 million. See EXELON CORPORATION — Liquidityborrowings. The Registrants’ businesses are capital intensive and Capital Resources and Note 16 — Debt and Credit Agreementsrequire considerable capital resources. Each of the Combined NotesRegistrants annually evaluates its financing plan, dividend practices, and credit line sizing, focusing on maintaining its investment grade ratings while meeting its cash needs to Consolidated Financial Statements of this Form 10-K for additional information.
Capital resources are used primarily to fund BGE’s capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and other postretirement benefitOPEB obligations, and invest in new and existing ventures. BGE spendsThe Registrants spend a significant amount of cash on capital improvements and construction projects that have a long-term return on investment. Additionally, BGE operatesthe Utility Registrants operate in a rate-regulated environmentenvironments 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. A broad spectrum 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.). 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 billion, as of December 31, 2021. 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” section below for additional information. The Registrants expect cash flows to be sufficient to meet operating expenses, financing costs, and capital expenditure requirements. See Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ debt and credit agreements.
Cash Flows from Operating Activities (All Registrants) A discussion of items pertinent to BGE’sThe Utility Registrants' cash flows from operating activities is set forth underprimarily 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. Generation's cash flows from operating activities primarily result from the sale of electric energy and energy-related products and services to customers.
See Note 3 — Regulatory Matters and Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements 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 years ended December 31, 2021 and 2020 by Registrant: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (Decrease) increase in cash flows from operating activities | Exelon | | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Net income | $ | (125) | | | | | $ | 304 | | | $ | 57 | | | $ | 59 | | | $ | 66 | | | $ | 30 | | | $ | 3 | | | $ | 34 | | Adjustments to reconcile net income to cash: | | | | | | | | | | | | | | | | | | Non-cash operating activities | (332) | | | | | 12 | | | 11 | | | (35) | | | 45 | | | 35 | | | 23 | | | (15) | | Option premiums paid, net | (199) | | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Collateral (posted) received, net | (568) | | | | | (14) | | | — | | | — | | | — | | | — | | | — | | | — | | Income taxes | 187 | | | | | (8) | | | (26) | | | (40) | | | 42 | | | 12 | | | 38 | | | 1 | | Pension and non-pension postretirement benefit contributions | (64) | | | | | (48) | | | — | | | (3) | | | (9) | | | — | | | (1) | | | (1) | | Changes in working capital and other noncurrent assets and liabilities | (122) | | | | | 25 | | | (46) | | | (136) | | | 11 | | | (116) | | | 50 | | | 77 | | (Decrease) increase in cash flows from operating activities | $ | (1,223) | | | | | $ | 271 | | | $ | (4) | | | $ | (155) | | | $ | 155 | | | $ | (39) | | | $ | 113 | | | $ | 96 | |
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, significant operating cash flow impacts for the Registrants for 2021 and 2020 were as follows: •See Note 24 —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. •Option premiums paid relate to options contracts that Generation purchases and sells as part of its established policies and procedures to manage risks associated with market fluctuations in commodity prices. See Note 16 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on derivative contracts. •Depending upon whether Exelon is in a net mark-to-market liability or asset position, collateral may be required to be posted with or collected from Operating Activitiesits counterparties. In addition, the collateral posting and collection requirements differ depending on whether the transactions are on an exchange or in EXELON CORPORATIONthe over-the-counter markets. See Note 16 — LiquidityDerivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ collateral. •See Note 14 —Income Taxes of the Combined Notes to Consolidated Financial Statements and Capital Resourcesthe Registrants' Consolidated Statements of this Form 10-K.Cash Flows for additional information on income taxes. •Changes in working capital and other noncurrent assets and liabilities include a decrease in Accounts receivable at Exelon resulting from the impact of cash received 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 at Exelon resulting from the impact of certain penalties for natural gas delivery associated with the February 2021 extreme cold weather event at
Generation and increases in natural gas prices at 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 receivable and on the February 2021 extreme cold weather event, respectively. Cash Flows from Investing Activities (All Registrants) A discussionThe following table provides a summary of items pertinent to BGE’sthe change in cash flows from investing activities is set forth under “Cash Flowsfor the years ended December 31, 2021 and 2020 by Registrant:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Increase (decrease) in cash flows from investing activities | Exelon | | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Capital expenditures | $ | 67 | | | | | $ | (170) | | | $ | (93) | | | $ | 21 | | | $ | (116) | | | $ | (70) | | | $ | (5) | | | $ | (44) | | Investment in NDT fund sales, net | (18) | | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | | | | | | | | | | | | | | | | | | Collection of DPP | 131 | | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Proceeds from sales of assets and businesses | 831 | | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Changes in intercompany money pool | — | | | | | — | | | (68) | | | — | | | — | | | — | | | — | | | — | | Other investing activities | 8 | | | | | 24 | | | 2 | | | 16 | | | (5) | | | (1) | | | 7 | | | (5) | | Increase (decrease) in cash flows from investing activities | $ | 1,019 | | | | | $ | (146) | | | $ | (159) | | | $ | 37 | | | $ | (121) | | | $ | (71) | | | $ | 2 | | | $ | (49) | |
Significant investing cash flow impacts for the Registrants for 2021 and 2020 were as follows: •Variances in capital expenditures are primarily due to the timing of cash expenditures for capital projects. See the "Credit Matters" section below for additional information on projected capital expenditure spending. •See Note 6 — Accounts Receivable of the Combined Notes to Consolidated Financial Statements for additional information on the Collection of DPP. •Proceeds from Investing Activities”sales of assets and businesses increased primarily due to the sale of a significant portion of Exelon's solar business and a biomass facility and proceeds received on sales of equity investments. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information on the sale of Exelon's solar business and biomass facility. •Changes in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.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 (All Registrants) A discussionThe following table provides a summary of items pertinent to BGE’sthe change in cash flows from financing activities for the years ended December 31, 2021 and 2020 by Registrant:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Increase (decrease) in cash flows from financing activities | Exelon | | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Changes in short-term borrowings, net | $ | 638 | | | | | $ | (516) | | | $ | — | | | $ | 206 | | | $ | (60) | | | $ | 187 | | | $ | (87) | | | $ | (160) | | Long-term debt, net | 774 | | | | | 300 | | | 100 | | | (100) | | | 91 | | | (22) | | | 27 | | | 86 | | Changes in intercompany money pool | — | | | | | — | | | (80) | | | — | | | (23) | | | — | | | — | | | — | | | | | | | | | | | | | | | | | | | | Dividends paid on common stock | (5) | | | | | (8) | | | 1 | | | (46) | | | — | | | (36) | | | (6) | | | (174) | | Acquisition of noncontrolling interest | (885) | | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Distributions to member | — | | | | | — | | | — | | | — | | | (150) | | | — | | | — | | | — | | Contributions from/(to) parent/member | — | | | | | 79 | | | 166 | | | (154) | | | 189 | | | (18) | | | 8 | | | 202 | | | | | | | | | | | | | | | | | | | | Other financing activities | 91 | | | | | (3) | | | (5) | | | 2 | | | (7) | | | — | | | (3) | | | (4) | | Increase (decrease) in cash flows from financing activities | $ | 613 | | | | | $ | (148) | | | $ | 182 | | | $ | (92) | | | $ | 40 | | | $ | 111 | | | $ | (61) | | | $ | (50) | |
Significant financing cash flow impacts for the Registrants for 2021 and 2020 were as follows: •Changes in short-term borrowings, net, is set forthdriven by repayments on and issuances of notes due in less than 365 days. Refer to Note 17 - 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 debt issuances and redemptions tables below for additional information. •Changes inintercompany 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 19 - Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements 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. •Other financing activities primarily consists of debt issuance costs. See debt issuances table below for additional information on the Registrants’ debt issuances.
Debt Issuances and Redemptions See Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of the Registrants’ long-term debt. Debt activity for 2021 and 2020 by Registrant was as follows: During 2021, the following long-term debt was issued: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Company/Subsidiary | | Type | | Interest Rate | | Maturity | | Amount | | Use of Proceeds | Exelon(a) | | Long-Term Software License Agreements | | 3.62 | % | | December 1, 2025 | | $ | 4 | | | Procurement of software licenses. | 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(b) | | First Mortgage Bonds | | 3.24 | % | | March 30, 2051 | | 125 | | Repay existing indebtedness and for general corporate purposes. | ACE | | First Mortgage Bonds | | 2.30 | % | | March 15, 2031 | | 350 | | Refinance existing indebtedness, repay outstanding commercial paper obligations, and for general corporate purposes. | ACE(c) | | First Mortgage Bonds | | 2.27 | % | | February 15, 2032 | | 75 | | Repay existing indebtedness and for general corporate purposes. | Generation | | West Medway II Nonrecourse Debt(d) | | LIBOR + 3%(e) | | March 31, 2026 | | 150 | | Funding for general corporate purposes. | Generation | | Energy Efficiency Project Financing(f) | | 2.53% - 4.24% | | January 31, 2022 - February 28, 2022 | | 2 | | Funding to install energy conservation measures. | | | | | | | | | | | |
__________ (a)In connection with the separation, Exelon Corporate entered into three 18-month term loan agreements. On January 21, 2022, two of the loan agreements were issued for $300 million each with an expiration date of July 21, 2023. On January 24, 2022, the third loan agreement was issued for $250 million with an expiration date of July 24, 2023. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to SOFR plus 0.65%. (b)On November 16, 2021, DPL entered into a purchase agreement of First Mortgage Bonds of $125 million at 3.06% due on February 15, 2052. The closing date of the issuance occurred on February 15, 2022. (c)On November 16, 2021, ACE entered into a purchase agreement of First Mortgage Bonds of $25 million and $150 million at 2.27% and 3.06% due on February 15, 2032 and February 15, 2052, respectively. The closing date of the issuance occurred on February 15, 2022. (d)See Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on nonrecourse debt. (e)The nonrecourse debt has an average blended interest rate.
(f)For Energy Efficiency Project Financing, the maturity dates represent the expected date of project completion, upon which the respective customer assumes the outstanding debt.
During 2020, the following long-term debt was issued: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Company/Subsidiary | | Type | | Interest Rate | | Maturity | | Amount | | Use of Proceeds | Exelon | | Notes | | 4.05 | % | | April 15, 2030 | | $ | 1,250 | | | Repay existing indebtedness and for general corporate purposes. | Exelon | | Notes | | 4.70 | % | | April 15, 2050 | | 750 | | Repay existing indebtedness and for general corporate purposes. | ComEd | | First Mortgage Bonds, Series 128 | | 2.20 | % | | March 1, 2030 | | 350 | | Repay a portion of outstanding commercial paper obligations and fund other general corporate purposes. | ComEd | | First Mortgage Bonds, Series 129 | | 3.00 | % | | March 1, 2050 | | 650 | | Repay a portion of outstanding commercial paper obligations and fund other general corporate purposes. | PECO | | First and Refunding Mortgage Bonds | | 2.80 | % | | June 15, 2050 | | 350 | | Funding for general corporate purposes. | BGE | | Senior Notes | | 2.90 | % | | June 15, 2050 | | 400 | | Repay commercial paper obligations and for general corporate purposes. | Pepco | | First Mortgage Bonds | | 2.53 | % | | February 25, 2030 | | 150 | | Repay existing indebtedness and for general corporate purposes. | Pepco | | First Mortgage Bonds | | 3.28 | % | | September 23, 2050 | | 150 | | Repay existing indebtedness and for general corporate purposes. | DPL | | First Mortgage Bonds | | 2.53 | % | | June 9, 2030 | | 100 | | Repay existing indebtedness and for general corporate purposes. | DPL | | Tax-Exempt Bonds(a) | | 1.05 | % | | January 1, 2031 | | 78 | | Refinance existing indebtedness. | ACE | | Tax-Exempt First Mortgage Bonds | | 2.25 | % | | June 1, 2029 | | 23 | | Refinance existing indebtedness. | ACE | | First Mortgage Bonds | | 3.24 | % | | June 9, 2050 | | 100 | | Repay existing indebtedness and for general corporate purposes. | Generation | | Senior Notes | | 3.25 | % | | June 1, 2025 | | 900 | | Repay existing indebtedness and for general corporate purposes. | Generation | | Constellation Renewables Nonrecourse Debt(b) | | LIBOR + 2.75% | | December 15, 2027 | | 750 | | Repay existing indebtedness and for general corporate purposes. | Generation | | Energy Efficiency Project Financing(c) | | 2.53% - 3.95% | | February 28, 2021 - March 31, 2021 | | 6 | | Funding to install energy conservation measures. |
__________ (a)The bonds have a 1.05% interest rate through July 2025. (b)See Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on nonrecourse debt. (c)For Energy Efficiency Project Financing, the maturity dates represent the expected date of project completion, upon which the respective customer assumes the outstanding debt.
During 2021, the following long-term debt was retired and/or redeemed: | | | | | | | | | | | | | | | | | | | | | | | | | | | Company/Subsidiary | | Type | | Interest Rate | | Maturity | | Amount | Exelon | | Senior Notes(a) | | 2.45% | | April 15, 2021 | | $ | 300 | | Exelon | | Long-Term Software License Agreements | | 3.95% | | May 1, 2024 | | 24 | Exelon | | Long-Term Software License Agreements | | 3.62% | | December 1, 2025 | | 1 | | 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 | | 21 | Generation | | Continental Wind Nonrecourse Debt(b) | | 6.00% | | February 28, 2033 | | 35 | Generation | | CR 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 | | 24 | Generation | | West Medway II Nonrecourse Debt(b) | | LIBOR + 3%(d) | | March 31, 2026 | | 13 | Generation | | RPG Nonrecourse Debt(b) | | 4.11% | | March 31, 2035 | | 9 | | | | | | | | | | | | | | | | | | | | | | | | | | | |
__________ (a)As part of the 2012 Constellation merger, Exelon entered intercompany loan agreements that mirrored the terms and amounts of the third-party debt obligations. In connection with the separation, on January 31, 2022, Exelon Corporate received cash from Generation of $258 million to settle the intercompany loan. See Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the mirror debt. (b)See Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements 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.
During 2020, the following long-term debt was retired and/or redeemed: | | | | | | | | | | | | | | | | | | | | | | | | | | | Company/Subsidiary | | Type | | Interest Rate | | Maturity | | Amount | Exelon | | Notes | | 2.85% | | June 15, 2020 | | $ | 900 | | Exelon | | Long-Term Software License Agreements | | 3.95% | | May 1, 2024 | | 24 | ComEd | | First Mortgage Bonds | | 4.00% | | August 1, 2020 | | 500 | DPL | | Tax-Exempt Bonds | | 5.40% | | February 1, 2031 | | 78 | ACE | | Tax-Exempt First Mortgage Bonds | | 4.88% | | June 1, 2029 | | 23 | ACE | | Transition Bonds | | 5.55% | | October 20, 2023 | | 20 | Generation | | Senior Notes | | 2.95% | | January 15, 2020 | | 1,000 | Generation | | Senior Notes | | 4.00% | | October 1, 2020 | | 550 | Generation | | Senior Notes(a) | | 5.15% | | December 1, 2020 | | 550 | Generation | | Tax-Exempt Bonds | | 2.50% - 2.70% | | December 1, 2025 - June 1, 2036 | | 412 | Generation | | CR Nonrecourse Debt(b) | | 3-month LIBOR + 3.00% | | November 30, 2024 | | 796 | Generation | | Continental Wind Nonrecourse Debt(b) | | 6.00% | | February 28, 2033 | | 33 | Generation | | Antelope Valley DOE Nonrecourse Debt(b) | | 2.29% - 3.56% | | January 5, 2037 | | 23 | Generation | | RPG Nonrecourse Debt(b) | | 4.11% | | March 31, 2035 | | 9 | Generation | | Energy Efficiency Project Financing | | 3.71% | | December 31, 2020 | | 4 | Generation | | NUKEM | | 3.15% | | September 30, 2020 | | 3 | Generation | | SolGen Nonrecourse Debt | | 3.93% | | September 30, 2036 | | 3 | Generation | | Energy Efficiency Project Financing | | 4.12% | | November 30, 2020 | | 1 | | | | | | | | | | | | | | | | | | | | | | | | | | | |
__________ (a)The senior notes are legacy Constellation mirror debt that were previously held at Exelon. As part of the 2012 Constellation merger, Exelon assumed intercompany loan agreements that mirrored the terms and amounts of external obligations held by Exelon. See Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. (b)See Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of nonrecourse debt. From time to time and as market conditions warrant, the Registrants may engage in long-term debt retirements via tender offers, open market repurchases or other viable options to reduce debt on their respective balance sheets. Dividends Quarterly dividends declared by the Exelon Board of Directors during the year ended December 31, 2021 and for the first quarter of 2022 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 | | First Quarter 2022 | | February 8, 2022 | | February 25, 2022 | | March 10, 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 (All Registrants) The Registrants fund liquidity needs for capital expenditures, 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 $6.5 billion was available to support additional commercial paper as of December 31, 2021, and of which no financial institution has more than 7% of the aggregate commitments for the Registrants. 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 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. The Registrants had access to the commercial paper markets and had availability under “Cash Flowstheir revolving credit facilities during 2021 to fund their short-term liquidity needs, when necessary. Exelon and Generation used their available credit facilities to manage short-term liquidity needs as a result of the impacts of the February 2021 extreme cold weather event. 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 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 for additional information regarding the effects of uncertainty in the capital and credit markets. The Registrants believe their cash flow from Financing Activities”operating activities, access to credit markets, and their credit facilities provide sufficient liquidity to support the estimated future cash requirements discussed below. Pursuant to the Separation Agreement between Exelon and Constellation Energy Corporation, Exelon made a cash payment of $1.75 billion to Generation on January 31, 2022. See Note 26 — Separation 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 EXELON CORPORATIONthe event each Utility Registrant lost its investment grade credit rating at December 31, 2021 and available credit facility capacity prior to any incremental collateral at December 31, 2021: | | | | | | | | | | | | | | | | | | | PJM Credit Policy Collateral | | Other Incremental Collateral Required(a) | | Available Credit Facility Capacity Prior to Any Incremental Collateral | ComEd | $ | 28 | | | $ | — | | | $ | 998 | | PECO | 1 | | | 37 | | | 600 | | BGE | 4 | | | 78 | | | 470 | | Pepco | 3 | | | — | | | 125 | | DPL | 4 | | | 14 | | | 151 | | ACE | 1 | | | — | | | 155 | |
__________ (a)Represents incremental collateral related to natural gas procurement contracts.
Capital Expenditures As of December 31, 2021, estimates of capital expenditures for plant additions and improvements are as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (in millions) | 2022 Transmission | | 2022 Distribution | | 2022 Gas | | Total 2022(b) | | Beyond 2022(b)(c) | Exelon(a) | N/A | | N/A | | N/A | | $ | 8,600 | | | $ | 24,950 | | | | | | | | | | | | ComEd | 450 | | | 2,025 | | | N/A | | 2,475 | | | 7,775 | | PECO | 175 | | | 850 | | | 325 | | | 1,325 | | | 4,500 | | BGE | 275 | | | 500 | | | 475 | | | 1,225 | | | 4,100 | | PHI | 600 | | | 1,175 | | | 100 | | | 1,850 | | | 5,650 | | Pepco | 275 | | | 625 | | | N/A | | 900 | | | 2,750 | | DPL | 150 | | | 250 | | | 100 | | | 475 | | | 1,550 | | ACE | 175 | | | 300 | | | N/A | | 475 | | | 1,375 | |
___________ (a)Exelon's estimated capital expenditures include estimated capital expenditures for Generation. (b)Numbers rounded to the nearest $25M and may not sum due to rounding. (c)Includes estimated capital expenditures for the Utility Registrants from 2023 and 2025 and includes estimated capital expenditures for Generation from 2023 to 2024. Projected capital expenditures and other investments are subject to periodic review and revision to reflect changes in economic conditions and other factors. Projected capital expenditures at the Utility Registrants are for continuing projects to maintain and improve operations, including enhancing reliability and adding capacity to the transmission and distribution systems. The Utility Registrants anticipate that they will fund their capital expenditures with a combination of internally generated funds and borrowings and additional capital contributions from parent. Pension and Other Postretirement Benefits Management 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 pension obligation, and regulatory implications. The Act requires the attainment of certain funding levels to avoid benefit restrictions (such as an inability to pay lump sums or to accrue benefits prospectively), and at-risk status (which triggers higher minimum contribution requirements and participant notification). The projected contributions below 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. Based on this funding strategy and current market conditions, which are subject to change, Exelon’s estimated annual qualified pension contributions will be approximately $500 million in 2022. Exelon's estimated contributions include contributions related to Generation's qualified pension plans. In connection with the separation, an additional qualified pension contribution of $207 million was completed on February 1, 2022. 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 plans. For Exelon's funded OPEB plans, contributions generally equal accounting costs, however, Exelon’s management has historically considered several factors in determining the level of contributions to its OPEB plans, including liabilities management, levels of benefit claims paid, and regulatory implications (amounts deemed prudent to meet regulatory expectations and best assure continued rate recovery). The amounts below include benefit payments related to unfunded plans.
The following table provides all Registrants' planned contributions to the qualified pension plans, planned benefit payments to non-qualified pension plans, and planned contributions to OPEB plans in 2022: | | | | | | | | | | | | | | | | | | | Qualified Pension Plans | | Non-Qualified Pension Plans | | OPEB | Exelon(a) | $ | 505 | | | $ | 32 | | | $ | 50 | | | | | | | | ComEd | 173 | | | 2 | | | 12 | | PECO | 12 | | | 1 | | | 2 | | BGE | 48 | | | 2 | | | 16 | | | | | | | | PHI | 60 | | | 10 | | | 7 | | Pepco | 2 | | | 1 | | | 6 | | DPL | 1 | | | 1 | | | — | | ACE | 7 | | | — | | | — | | | | | | | | _________(a)Exelon's estimated contributions include contributions related to Generation's qualified pension plans. These payments are based on the combined plans, as of December 31, 2021 and do not reflect the impacts of the separation. To the extent interest rates decline significantly or the pension and OPEB plans earn less than the expected asset returns, annual pension contribution requirements in future years could increase. Conversely, to the extent interest rates increase significantly or the pension and OPEB plans earn greater than the expected asset returns, annual pension and OPEB contribution requirements in future years could decrease. Additionally, expected contributions could change if Exelon changes its pension or OPEB funding strategy. See Note 15 — LiquidityRetirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information on pension and OPEB contributions. Cash Requirements for Other Financial Commitments The following tables summarize the Registrants' future estimated cash payments as of December 31, 2021 under existing financial commitments:
Exelon | | | | | | | | | | | | | | | | | | | | | | | | | 2022(a) | | Beyond 2022(a) | | Total(a) | | Time Period | Long-term debt(b) | $ | 3,357 | | | $ | 35,300 | | | $ | 38,657 | | | 2022 - 2053 | Interest payments on long-term debt(c) | 1,509 | | | 23,670 | | | 25,179 | | | 2022 - 2051 | Operating leases(d) | 99 | | | 937 | | | 1,036 | | | 2022 - 2106 | Purchase power obligations(e) | 620 | | | 1,109 | | | 1,729 | | | 2022 - 2036 | Fuel purchase agreements(f) | 1,303 | | | 5,446 | | | 6,749 | | | 2022 - 2054 | Electric supply procurement | 2,122 | | | 1,254 | | | 3,376 | | | 2022 - 2025 | Long-term renewable energy and REC commitments | 302 | | | 1,691 | | | 1,993 | | | 2022 - 2033 | Other purchase obligations(g) | 5,247 | | | 5,806 | | | 11,053 | | | 2022 - 2046 | DC PLUG obligation | 33 | | | 37 | | | 70 | | | 2022 - 2024 | SNF obligation | — | | | 1,210 | | | 1,210 | | | 2022 - 2035 | | | | | | | | | Pension contributions(h) | 505 | | | 190 | | | 695 | | | 2022 - 2027 | Total cash requirements | $ | 15,097 | | | $ | 76,650 | | | $ | 91,747 | | | |
__________ (a)Exelon's future estimated cash payments include future estimated cash payments for Generation. (b)Includes amounts from ComEd and PECO financing trusts. (c)Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2021 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2021. Includes estimated interest payments due to ComEd and PECO financing trusts. (d)Capacity payments associated with contracted generation lease agreements are net of sublease and capacity offsets of $57 million and $315 million for 2022 and beyond 2022, respectively, and $372 million in total. (e)Purchase power obligations primarily include expected payments for REC purchases and payments associated with contracted generation agreements, which may be reduced based on plant availability. Expected payments exclude payments on renewable generation contracts that are contingent in nature. (f)Represents commitments to purchase nuclear fuel, natural gas and related transportation, storage capacity, and services. (g)Represents the future estimated value at December 31, 2021 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between the Registrants or subsidiary and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period. (h)These amounts represent Exelon’s expected contributions to its qualified pension plans. Qualified pension contributions for years after 2027 are not included.
ComEd | | | | | | | | | | | | | | | | | | | | | | | | | 2022 | | Beyond 2022 | | Total | | Time Period | Long-term debt(a) | $ | — | | | $ | 10,084 | | | $ | 10,084 | | | 2022 - 2053 | Interest payments on long-term debt(b) | 394 | | | 7,467 | | | 7,861 | | | 2022 - 2051 | Operating leases | 2 | | | 3 | | | 5 | | | 2022 - 2025 | Electric supply procurement | 474 | | | 260 | | | 734 | | | 2022 - 2024 | Long-term renewable energy and REC commitments | 271 | | | 1,438 | | | 1,709 | | | 2022 - 2033 | Other purchase obligations(c) | 858 | | | 764 | | | 1,622 | | | 2022 - 2031 | ZEC commitments | 160 | | | 706 | | | 866 | | | 2022 - 2027 | Total cash requirements | $ | 2,159 | | | $ | 20,722 | | | $ | 22,881 | | | |
__________ (a)Includes amounts from ComEd financing trust. (b)Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2021 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. Includes estimated interest payments due to the ComEd financing trust. (c)Represents the future estimated value at December 31, 2021 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between ComEd and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period. PECO | | | | | | | | | | | | | | | | | | | | | | | | | 2022 | | Beyond 2022 | | Total | | Time Period | Long-term debt(a) | $ | 350 | | | $ | 4,084 | | | $ | 4,434 | | | 2022 - 2051 | Interest payments on long-term debt(b) | 166 | | | 3,213 | | | 3,379 | | | 2022 - 2051 | Operating leases | — | | | 1 | | | 1 | | | 2022 - 2034 | Fuel purchase agreements(c) | 140 | | | 271 | | | 411 | | | 2022 - 2029 | Electric supply procurement | 490 | | | 2 | | | 492 | | | 2022 - 2023 | Other purchase obligations(d) | 846 | | | 690 | | | 1,536 | | | 2022 - 2030 | Total cash requirements | $ | 1,992 | | | $ | 8,261 | | | $ | 10,253 | | | |
__________ (a)Includes amounts from PECO financing trusts. (b)Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2021 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. Includes estimated interest payments due to the PECO financing trusts. (c)Represents commitments to purchase natural gas and related transportation, storage capacity, and services. (d)Represents the future estimated value at December 31, 2021 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between PECO and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.
BGE | | | | | | | | | | | | | | | | | | | | | | | | | 2022 | | Beyond 2022 | | Total | | Time Period | Long-term debt | $ | 250 | | | $ | 3,750 | | | $ | 4,000 | | | 2022 - 2050 | Interest payments on long-term debt(a) | 138 | | | 2,312 | | | 2,450 | | | 2022 - 2050 | Operating leases | 16 | | | 19 | | | 35 | | | 2022 - 2106 | Fuel purchase agreements(b) | 112 | | | 481 | | | 593 | | | 2022 - 2038 | Electric supply procurement | 764 | | | 498 | | | 1,262 | | | 2022 - 2024 | Other purchase obligations(c) | 692 | | | 607 | | | 1,299 | | | 2022 - 2040 | Total cash requirements | $ | 1,972 | | | $ | 7,667 | | | $ | 9,639 | | | |
__________ (a)Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2021 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. (b)Represents commitments to purchase natural gas and related transportation, storage capacity, and services. (c)Represents the future estimated value at December 31, 2021 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between BGE and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period. PHI | | | | | | | | | | | | | | | | | | | | | | | | | 2022 | | Beyond 2022 | | Total | | Time Period | Long-term debt | $ | 387 | | | $ | 6,618 | | | $ | 7,005 | | | 2022 - 2051 | Interest payments on long-term debt(a) | 282 | | | 3,953 | | | 4,235 | | | 2022 - 2051 | Finance leases | 12 | | | 67 | | | 79 | | | 2022 - 2029 | Operating leases | 38 | | | 230 | | | 268 | | | 2022 - 2032 | Fuel purchase agreements(b) | 31 | | | 242 | | | 273 | | | 2022 - 2030 | Electric supply procurement | 1,097 | | | 754 | | | 1,851 | | | 2022 - 2025 | Long-term renewable energy and REC commitments | 31 | | | 253 | | | 284 | | | 2022 - 2032 | Other purchase obligations(c) | 1,016 | | | 1,031 | | | 2,047 | | | 2022 - 2029 | DC PLUG obligation | 33 | | | 37 | | | 70 | | | 2022 - 2024 | Total cash requirements | $ | 2,927 | | | $ | 13,185 | | | $ | 16,112 | | | |
__________ (a)Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2021 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2021. (b)Represents commitments to purchase natural gas and related transportation, storage capacity, and services. (c)Represents the future estimated value at December 31, 2021 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between Pepco, DPL, ACE, and PHISCO and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.
Pepco | | | | | | | | | | | | | | | | | | | | | | | | | 2022 | | Beyond 2022 | | Total | | Time Period | Long-term debt | $ | 309 | | | $ | 3,150 | | | $ | 3,459 | | | 2022 - 2051 | Interest payments on long-term debt(a) | 149 | | | 2,287 | | | 2,436 | | | 2022 - 2051 | Finance leases | 4 | | | 23 | | | 27 | | | 2022 - 2029 | Operating leases | 8 | | | 47 | | | 55 | | | 2022 - 2032 | Electric supply procurement | 498 | | | 384 | | | 882 | | | 2022 - 2025 | Other purchase obligations(b) | 603 | | | 551 | | | 1,154 | | | 2022 - 2026 | DC PLUG obligation | 33 | | | 37 | | | 70 | | | 2022 - 2024 | Total cash requirements | $ | 1,604 | | | $ | 6,479 | | | $ | 8,083 | | | |
__________ (a)Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2021 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. (b)Represents the future estimated value at December 31, 2021 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between Pepco and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period. DPL | | | | | | | | | | | | | | | | | | | | | | | | | 2022 | | Beyond 2022 | | Total | | Time Period | Long-term debt | $ | 78 | | | $ | 1,711 | | | $ | 1,789 | | | 2022 - 2051 | Interest payments on long-term debt(a) | 63 | | | 1,013 | | | 1,076 | | | 2022 - 2051 | Finance leases | 5 | | | 27 | | | 32 | | | 2022 - 2029 | Operating leases | 10 | | | 60 | | | 70 | | | 2022 - 2027 | Fuel purchase agreements(b) | 31 | | | 242 | | | 273 | | | 2022 - 2030 | Electric supply procurement | 298 | | | 187 | | | 485 | | | 2022 - 2024 | Long-term renewable energy and REC commitments | 31 | | | 253 | | | 284 | | | 2022 - 2032 | Other purchase obligations(c) | 214 | | | 192 | | | 406 | | | 2022 - 2028 | Total cash requirements | $ | 730 | | | $ | 3,685 | | | $ | 4,415 | | | |
__________ (a)Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2021 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2021. (b)Represents commitments to purchase natural gas and related transportation, storage capacity, and services. (c)Represents the future estimated value at December 31, 2021 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between DPL and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.
ACE | | | | | | | | | | | | | | | | | | | | | | | | | 2022 | | Beyond 2022 | | Total | | Time Period | Long-term debt | $ | — | | | $ | 1,572 | | | $ | 1,572 | | | 2022 - 2050 | Interest payments on long-term debt(a) | 56 | | | 519 | | | 575 | | | 2022 - 2050 | Finance leases | 3 | | | 17 | | | 20 | | | 2022 - 2029 | Operating leases | 4 | | | 9 | | | 13 | | | 2022 - 2027 | Electric supply procurement | 301 | | | 183 | | | 484 | | | 2022 - 2024 | Other purchase obligations(b) | 158 | | | 240 | | | 398 | | | 2022 - 2027 | Total cash requirements | $ | 522 | | | $ | 2,540 | | | $ | 3,062 | | | |
__________ (a)Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2021 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. (b)Represents the future estimated value at December 31, 2021 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between ACE and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period. See Note 19 — Commitments and Contingencies and Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information of the Registrants’ other commitments potentially triggered by future events. Additionally, see below for where to find additional information regarding the financial commitments in the tables above in the Combined Notes to the Consolidated Financial Statements: | | | | | | Item | Location within Notes to the Consolidated Financial Statements | Long-term debt | Note 17 — Debt and Credit Agreements | Interest payments on long-term debt | Note 17 — Debt and Credit Agreements | Finance leases | Note 11 — Leases | Operating leases | Note 11 — Leases | SNF obligation | Note 19 — Commitments and Contingencies | REC commitments | Note 3 — Regulatory Matters | ZEC commitments | Note 3 — Regulatory Matters | DC PLUG obligation | Note 3 — Regulatory Matters | Pension contributions | Note 15 — Retirement Benefits |
Credit Facilities (All Registrants) Exelon Corporate, ComEd, and BGE meet their short-term liquidity requirements primarily through the issuance of commercial paper. PECO meets 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 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ credit facilities and short term borrowing activity.
Capital ResourcesStructure At December 31, 2021, the capital structures of the Registrants consisted of the following: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exelon | | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Long-term debt | 50 | % | | | | 44 | % | | 44 | % | | 45 | % | | 40 | % | | 49 | % | | 48 | % | | 48 | % | Long-term debt to affiliates(a) | 1 | % | | | | 1 | % | | 2 | % | | — | % | | — | % | | — | % | | — | % | | — | % | Common equity | 45 | % | | | | 55 | % | | 54 | % | | 53 | % | | — | % | | 49 | % | | 48 | % | | 48 | % | Member’s equity | — | % | | | | — | % | | — | % | | — | % | | 57 | % | | — | % | | — | % | | — | % | | | | | | | | | | | | | | | | | | | Commercial paper and notes payable | 4 | % | | | | — | % | | — | % | | 2 | % | | 3 | % | | 2 | % | | 4 | % | | 4 | % |
__________ (a)Includes approximately $390 million, $205 million, and $184 million owed to unconsolidated affiliates of Exelon, ComEd, and PECO respectively. These special purpose entities were created for the sole purposes of issuing mandatory redeemable trust preferred securities of ComEd and PECO. See Note 23 — Variable Interest Entities of the Combined Notes to Consolidated Financial Statements for additional information regarding the authoritative guidance for VIEs. 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 additional collateral. See Note 16 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on collateral provisions. The credit ratings for Exelon Corporate and the Utility Registrants did not change for the year ended December 31, 2021. On January 14, 2022, Fitch lowered Exelon Corporate's long-term rating 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+ and upgraded Pepco and ACE's senior secured rating from A- to 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 December 31, 2021, are presented in the following tables. ACE did not have any intercompany money pool activity as of December 31, 2021. | | | | | | | | | | | | | | | | | | | For the Year Ended December 31, 2021 | | As of December 31, 2021 | Exelon Intercompany Money Pool | Maximum Contributed | | Maximum Borrowed | | Contributed (Borrowed) | Exelon Corporate | $ | 735 | | | $ | — | | | $ | 217 | | Generation | — | | | (426) | | | — | | PECO | 303 | | | (100) | | | — | | BSC | — | | | (435) | | | (260) | | PHI Corporate | — | | | (40) | | | (7) | | PCI | 60 | | | — | | | 50 | |
| | | | | | | | | | | | | | | | | | | For the Year Ended December 31, 2021 | | As of December 31, 2021 | PHI Intercompany Money Pool | Maximum Contributed | | Maximum Borrowed | | Contributed (Borrowed) | | | | | | | Pepco | $ | — | | | $ | (30) | | | $ | — | | DPL | 30 | | | — | | | — | | | | | | | | | | | | | |
Shelf Registration Statements (All Registrants) Exelon 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 December 31, 2021 | | | Short-term Financing Authority(a) | | Remaining Long-term Financing Authority | Commission | | Expiration Date | | Amount | Commission | | Expiration Date | | Amount | ComEd(b) | | FERC | | December 31, 2023 | | $ | 2,500 | | | ICC | | January 1, 2025 | | $ | 2,093 | | PECO(c) | | FERC | | December 31, 2023 | | 1,500 | | | PAPUC | | December 31, 2024 | | 1,900 | | BGE | | FERC | | December 31, 2023 | | 700 | | | MDPSC | | N/A | | 500 | | Pepco | | FERC | | December 31, 2023 | | 500 | | | MDPSC / DCPSC | | December 31, 2022 | | 625 | | DPL | | FERC | | December 31, 2023 | | 500 | | | MDPSC / DEPSC | | December 31, 2022 | | 172 | | ACE(d) | | NJBPU | | December 31, 2023 | | 350 | | | NJBPU | | December 31, 2022 | | 175 | |
__________ (a)On October 15, 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 received approval on December 16, 2021, PECO and BGE received approval on December 23, 2021, Pepco and DPL received approval on December 28, 2021, and ACE received approval on December 1, 2021. (b)On November 18, 2021, ComEd had an additional $2 billion in new money long-term debt financing authority from the ICC with an effective date of January 1, 2022 and an expiration date of January 1, 2025. (c)On December 2, 2021, PECO received approval from the PAPUC for $2.5 billion in new long-term debt financing authority with an effective date of January 1, 2022.
(d)ACE is currently in the process of renewing its long-term financing authority with the NJBPU and expects approval by August 1, 2022. | | | | | | ITEM 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
The Registrants are exposed to market risks associated with adverse changes in commodity prices, counterparty credit, interest rates, and equity prices. 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. Historically, reporting on risk management issues has been to Exelon’s Risk Management Committee, the Risk Management Committees of each Utility Registrant, and the Risk Committee of Exelon’s Board of Directors. After separation, reporting on risk management issues will be to Exelon’s Executive Committee, the Risk Management Committees of each Utility Registrant, and the Audit and Risk Committee of Exelon’s Board of 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. Generation Electricity available from Generation’s owned or contracted generation supply in excess of Generation’s obligations to customers, including portions of the Utility Registrants' retail load, is sold into the wholesale markets. To reduce commodity 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. We expect the settlement of the majority of our economic hedges will occur during 2022 through 2024. In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on Generation’s owned and contracted generation positions which have not been hedged. For merchant revenues not already hedged via comprehensive state programs, such as the CMC in Illinois, we utilize a three-year ratable sales plan to align our hedging strategy with our financial objectives. The prompt three-year merchant revenues are hedged on an approximate rolling 90%/60%/30% basis. We may also enter transactions that are outside of this Form 10-K.ratable hedging program.As of December 31, 2021, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York, and ERCOT reportable segments is 92%-95% and 73%-76% for 2022 and 2023, respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation. Expected generation is the volume of energy that best represents our commodity position in energy markets from owned or contracted generation based upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products and options. Equivalent sales represent all hedging products, which include economic hedges, CMC payments, and certain non-derivative contracts. A portion of Generation’s hedging strategy may be accomplished with fuel products based on assumed correlations between power and fuel prices, which routinely change in the market. Market price risk exposure is the risk of a change in the value of unhedged positions. The forecasted market price risk exposure for Generation’s entire economic hedge portfolio associated with a $5/MWh reduction in the annual average around-the-clock energy price based on December 31, 2021 market conditions and hedged position would be a decrease in pre-tax net income of approximately $20 million and $243 million for 2022 and 2023, respectively. Power price sensitivities are derived by adjusting power price assumptions while keeping all other price inputs constant. Generation actively manages its portfolio to mitigate market price risk exposure for its unhedged position. Actual results could differ depending on the specific timing of, and markets affected by, price changes, as well as future changes in Generation’s portfolio. See Note 16 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
Fuel Procurement
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. Supply market conditions may make Generation’s procurement contracts subject to credit risk related to the potential non-performance of counterparties to deliver the contracted commodity or service at the contracted prices. Utility Registrants ComEd 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. 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. PECO, BGE, and DPL also have executed derivative natural gas contracts, which either qualify for NPNS or have no mark-to-market balances because the derivatives are index priced, to hedge their long-term price risk in the natural gas market. The hedging programs for natural gas procurement have no direct impact on their financial statements. PECO, BGE, Pepco, DPL, and ACE do not execute derivatives for speculative purposes. For additional information on these contracts, see Note 3 — Regulatory Matters and Note 16 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements. Trading and Non-Trading Marketing Activities The following table detailing Exelon’s (including Generation's) and ComEd’s trading and non-trading marketing activities is included to address the recommended disclosures by the energy industry’s Committee of Chief Risk Officers (CCRO). The following table provides detail on changes in Exelon’s and ComEd’s commodity mark-to-market net asset or liability balance sheet position from December 31, 2019 to December 31, 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 16 — 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 December 31, 2021 and 2020.
| | | | | | | | | | | | | | | | | | | Exelon | | | | ComEd | | | | | Balance as of December 31, 2019 | $ | 567 | | (a) | | | $ | (301) | | | | | | Total change in fair value during 2020 of contracts recorded in result of operations | (203) | | | | | — | | | | | | Reclassification to realized at settlement of contracts recorded in results of operations | 469 | | | | | — | | | | | | | | | | | | | | | | | | | | | | | | | | Changes in allocated collateral | (513) | | | | | — | | | | | | Net option premium paid | 139 | | | | | — | | | | | | Option premium amortization | (104) | | | | | — | | | | | | Upfront payments and amortizations(c) | 73 | | | | | — | | | | | | | | | | | | | | | | Balance as of December 31, 2020 | 428 | | (a) | | | (301) | | | | | | Total change in fair value during 2021 of contracts recorded in result of operations | 797 | | | | | — | | | | | | Reclassification to realized at settlement of contracts recorded in results of operations | (228) | | | | | — | | | | | | | | | | | | | | | | Changes in fair value—recorded through regulatory assets(b) | 82 | | | | | 82 | | | | | | Changes in allocated collateral | 96 | | | | | — | | | | | | Net option premium paid | 338 | | | | | — | | | | | | Option premium amortization | (125) | | | | | — | | | | | | Upfront payments and amortizations(c) | 15 | | | | | — | | | | | | | | | | | | | | | | Balance as of December 31, 2021 | $ | 1,403 | | (a) | | | $ | (219) | | | | | |
__________ (a)Exelon's balance related to Generation is 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 December 31, 2020 and 2021, ComEd recorded a regulatory asset of $301 million and $219 million, respectively, related to its mark-to-market derivative liabilities with unaffiliated suppliers. ComEd recorded $33 million of decreases in fair value and an increase for realized losses due to settlements of $33 million in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the year ended December 31, 2020. ComEd recorded $62 million of increases in fair value and an increase for realized losses due to settlements of $20 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the year ended December 31, 2021. (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 and ComEd mark-to-market commodity contract net assets (liabilities). The tables provide two fundamental pieces of information. First, the tables provide the source of fair value used in determining the carrying amount of Exelon's and ComEd's total mark-to-market net assets (liabilities), net of allocated collateral. Second, the tables show the maturity, by year, of Exelon's and ComEd's commodity contract net assets (liabilities), net of allocated collateral, giving an indication of when these mark-to-market amounts will settle and either generate or require cash. See Note 18 — 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 | | 2022 | | 2023 | | 2024 | | 2025 | | 2026 | | 2027 and Beyond | | Normal Operations, Commodity derivative contracts(a)(b)(c): | | | | | | | | | | | | | | Actively quoted prices (Level 1) | $ | 711 | | | $ | 66 | | | $ | 53 | | | $ | 43 | | | $ | 24 | | | $ | — | | | $ | 897 | | Prices provided by external sources (Level 2) | 442 | | | 436 | | | (60) | | | 1 | | | — | | | — | | | 819 | | Prices based on model or other valuation methods (Level 3)(d) | 19 | | | (93) | | | 2 | | | (15) | | | (45) | | | (181) | | | (313) | | Total | $ | 1,172 | | | $ | 409 | | | $ | (5) | | | $ | 29 | | | $ | (21) | | | $ | (181) | | | $ | 1,403 | |
__________ (a)Exelon's maturity by year includes maturities related to Generation's mark-to-market contract net assets (liabilities). (b)Mark-to-market gains and losses on other economic hedge and trading derivative contracts that are recorded in results of operations. (c)Amounts are shown net of collateral paid/(received) from counterparties (and offset against mark-to-market assets and liabilities) of $512 million at December 31, 2021. (d)Includes ComEd’s net assets (liabilities) associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers. ComEd | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Maturities Within | | Total Fair Value | | 2022 | | 2023 | | 2024 | | 2025 | | 2026 | | 2027 and Beyond | | Commodity derivative contracts(a): | | | | | | | | | | | | | | Prices based on model or other valuation methods (Level 3)(a) | $ | (18) | | | $ | (19) | | | $ | (21) | | | $ | (20) | | | $ | (21) | | | $ | (120) | | | $ | (219) | |
__________ (a)Represents ComEd’s net liabilities associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers. Credit MattersRisk (All Registrants) AThe 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 16—Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for a detailed discussion of credit matters pertinentrisk.
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 BGEmaster netting agreements, as of December 31, 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 figures in the table 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 December 31, 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 | $ | 715 | | | $ | 176 | | | $ | 539 | | | 1 | | | $ | 106 | | Non-investment grade | 13 | | | — | | | 13 | | | — | | | — | | No external ratings | | | | | | | | | | Internally rated—investment grade | 111 | | | — | | | 111 | | | — | | | — | | Internally rated—non-investment grade | 226 | | | 47 | | | 179 | | | — | | | — | | Total | $ | 1,065 | | | $ | 223 | | | $ | 842 | | | 1 | | | $ | 106 | | __________(a)As of December 31, 2021, credit collateral held from counterparties where Generation had credit exposure included $163 million of cash and $60 million of letters of credit. | | | | | | | | | | | | | | | | | | | | | | | | | Maturity of Credit Risk Exposure | Rating as of December 31, 2021 | Less than 2 Years | | 2-5 Years | | Exposure Greater than 5 Years | | Total Exposure Before Credit Collateral | Investment grade | $ | 605 | | | $ | 62 | | | $ | 48 | | | $ | 715 | | Non-investment grade | 13 | | | — | | | — | | | 13 | | No external ratings | | | | | | | | Internally rated—investment grade | 111 | | | — | | | — | | | 111 | | Internally rated—non-investment grade | 181 | | | 39 | | | 6 | | | 226 | | Total | $ | 910 | | | $ | 101 | | | $ | 54 | | | $ | 1,065 | |
| | | | | | Net Credit Exposure by Type of Counterparty | As of December 31, 2021 | Financial institutions | $ | 32 | | Investor-owned utilities, marketers, power producers | 711 | | Energy cooperatives and municipalities | 62 | | Other | 37 | | Total | $ | 842 | |
The Utility Registrants Credit risk for the Utility Registrants is set forth under Credit Matters in EXELON CORPORATION — Liquiditygoverned by credit and Capital Resources of this Form 10-K. Contractual Obligationscollection policies, which are aligned with state regulatory requirements. The Utility Registrants are currently obligated to provide service to all electric customers within their franchised territories. The Utility Registrants record an allowance for credit losses on customer receivables, based upon historical loss experience, current conditions, and Off-Balance Sheet Arrangements
A discussion of BGE’s contractual obligations, commercial commitmentsforward-looking risk factors, to provide for the potential loss from nonpayment by these customers. The Utility Registrants will monitor nonpayment from customers and off-balance sheet arrangements is set forth under Contractual Obligations and Off-Balance Sheet Arrangements in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Critical Accounting Policies and Estimates
See All Registrants — Critical Accounting Policies and Estimates abovewill make any necessary adjustments to the allowance for a discussion of BGE’s critical accounting policies and estimates.
New Accounting Pronouncements
credit losses on customer receivables. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for information regarding new accounting pronouncements. | | | ITEM 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
BGE
BGE is exposed to market risks associated withthe allowance for credit and interest rates. These risks are described above under Quantitative and Qualitative Disclosures about Market Risk—Exelon.
| | | ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
PHI
General
PHI has three reportable segments Pepco, DPL, and ACE. Its operations consistlosses policy. The Utility Registrants did not have any customers representing over 10% of the purchase and regulated retail saletheir revenues as of electricity and the provision of distribution and transmission services, and to a lesser extent, the purchase and regulated retail sale and supply of natural gas in Delaware. This segment is discussed in further detail in ITEM 1. BUSINESS — PHI of this Form 10-K.
Executive Overview
A discussion of items pertinent to PHI’s executive overview is set forth under EXELON CORPORATION — Executive Overview of this Form 10-K.
Results of Operations
Year Ended December 31, 2019 Compared to Year Ended December 31, 2018
A discussion of PHI’s results of operations for 2019 compared to 2018 is set forth under Results of Operations—PHI in EXELON CORPORATION — Results of Operations of this Form 10-K.
Liquidity and Capital Resources
PHI’s business is capital intensive and requires considerable capital resources. PHI’s capital resources are primarily provided by internally generated cash flows from operations and, to the extent necessary, external financing, including the issuance of long-term debt or commercial paper, borrowings from the Exelon money pool or capital contributions from Exelon. PHI’s access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of the utility industry in general.
See EXELON CORPORATION — Liquidity and Capital Resources and Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements of this Form 10-K for additional information.
Capital resources are used primarily to fund PHI’s capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and other postretirement benefit obligations and invest in new and existing ventures. PHI spends a significant amount of cash on capital improvements and construction projects that have a long-term return on investment.
Cash Flows from Operating Activities
A discussion of items pertinent to PHI’s cash flows from operating activities is set forth under Cash Flows from Operating Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Cash Flows from Investing Activities
A discussion of items pertinent to PHI’s cash flows from investing activities is set forth under “Cash Flows from Investing Activities” in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Cash Flows from Financing Activities
A discussion of items pertinent to PHI’s cash flows from financing activities is set forth under “Cash Flows from Financing Activities” in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Credit Matters
A discussion of credit matters pertinent to PHI is set forth under Credit Matters in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Contractual Obligations and Off-Balance Sheet Arrangements
A discussion of PHI’s contractual obligations, commercial commitments and off-balance sheet arrangements is set forth under Contractual Obligations and Off-Balance Sheet Arrangements in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Critical Accounting Policies and Estimates
See All Registrants — Critical Accounting Policies and Estimates above for a discussion of PHI’s critical accounting policies and estimates.
New Accounting Pronouncements
2021. See Note 13 — Significant Accounting PoliciesRegulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information regarding new accounting pronouncements.the regulatory recovery of credit losses on customer accounts receivable. | | | ITEM 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
PHI
PHI is exposed to market risks associated with credit and interest rates. These risks are described above under Quantitative and Qualitative Disclosures about Market Risk — Exelon.
| | | ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
Pepco
General
Pepco operates in a single business segment and its operations consistAs of the purchase and regulated retail sale of electricity and the provision of distribution and transmission services to retail customers in District of Columbia and major portions of Prince George’s County and Montgomery County in Maryland. This segment is discussed in further detail in ITEM 1. BUSINESS — Pepco of this Form 10-K.
Executive Overview
A discussion of items pertinent to Pepco’s executive overview is set forth under EXELON CORPORATION — Executive Overview of this Form 10-K.
Results of Operations
Year Ended December 31, 2019 Compared2021, the Utility Registrants net credit exposure to Year Ended December 31, 2018
A discussion of Pepco’s results of operations for 2019 compared to 2018 is set forth under Results of Operations—Pepco in EXELON CORPORATION — Results of Operations of this Form 10-K.
Liquidity and Capital Resources
Pepco’s business is capital intensive and requires considerable capital resources. Pepco’s capital resources are primarily provided by internally generated cash flows from operations and, to the extent necessary, external financing, including the issuance of long-term debt, commercial paper or credit facility borrowings. Pepco’s access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of the utility industry in general. At December 31, 2019, Pepco had access to a revolving credit facility with aggregate bank commitments of $300 million.
suppliers was immaterial. See EXELON CORPORATION — Liquidity and Capital Resources and Note 16 — Debt and Credit Agreements of the Combined Notes to ConsolidatedDerivative Financial Statements of this Form 10-K for additional information. Capital resources are used primarily to fund Pepco’s capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and other postretirement benefit obligations and invest in new and existing ventures. Pepco spends a significant amount of cash on capital improvements and construction projects that have a long-term return on investment. Additionally, Pepco operates in rate-regulated environments in which the amount of new investment recovery may be limited and where such recovery takes place over an extended period of time.
Cash Flows from Operating Activities
A discussion of items pertinent to Pepco’s cash flows from operating activities is set forth under Cash Flows from Operating Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Cash Flows from Investing Activities
A discussion of items pertinent to Pepco’s cash flows from investing activities is set forth under Cash Flows from Investing Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Cash Flows from Financing Activities
A discussion of items pertinent to Pepco’s cash flows from financing activities is set forth under Cash Flows from Financing Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Credit Matters
A discussion of credit matters pertinent to Pepco is set forth under Credit Matters in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Contractual Obligations and Off-Balance Sheet Arrangements
A discussion of Pepco’s contractual obligations, commercial commitments and off-balance sheet arrangements is set forth under Contractual Obligations and Off-Balance Sheet Arrangements in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Critical Accounting Policies and Estimates
See All Registrants — Critical Accounting Policies and Estimates above for a discussion of Pepco’s critical accounting policies and estimates.
New Accounting Pronouncements
See Note 1 — Significant Accounting PoliciesInstruments of the Combined Notes to Consolidated Financial Statements for information regarding new accounting pronouncements.additional information.
Credit-Risk-Related Contingent Features (All Registrants) Generation
| | | ITEM 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
Pepco
Pepco is exposed to market risks associated with credit and interest rates. These risks are described above under Quantitative and Qualitative Disclosures about Market Risk— Exelon.
| | | ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
DPL
General
DPL operates in a single business segment and its operations consistAs part of the purchasenormal course of business, Generation routinely enters into physical or financial contracts for the sale and regulated retail salepurchase of electricity, and the provision of distribution and transmission services in portions of Maryland and Delaware, and the purchase and regulated retail sale and supply of natural gas, in New Castle County, Delaware. This segmentand other commodities. In accordance with the contracts and applicable law, if Generation is discussed in further detail in ITEM 1. BUSINESS — DPLdowngraded 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 this Form 10-K.
Executive Overview
A discussionfuture performance. Depending on Generation’s net position with a counterparty, the demand could be for the posting of items pertinent to DPL’s executive overview is set forth under EXELON CORPORATION — Executive Overviewcollateral. In the absence of this Form 10-K.
Results of Operations
Year Ended December 31, 2019 Compared to Year Ended December 31, 2018
A discussion of DPL’s results of operations for 2019 compared to 2018 is set forth under Results of Operations—DPL in EXELON CORPORATION — Results of Operations of this Form 10-K.
Liquidity and Capital Resources
DPL’s business is capital intensive and requires considerable capital resources. DPL’s capital resources are primarilyexpressly agreed-to provisions that specify the collateral that must be provided, by internally generated cash flows from operations and, to the extent necessary, external financing, including the issuance of long-term debt or commercial paper. DPL’s access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as thatcollateral requested will be a function of the utility industry in general. If these conditions deteriorate to where DPL no longer has access tofacts and circumstances of the capital marketssituation at reasonable terms, DPL has access to a revolving credit facility. At December 31, 2019, DPL had access to a revolving credit facility with aggregate bank commitmentsthe time of $300 million.
the demand. See EXELON CORPORATION — Liquidity and Capital Resources and Note 16 — Debt and Credit Agreements of the Combined Notes to ConsolidatedDerivative Financial Statements of this Form 10-K for additional information. Capital resources are used primarily to fund DPL’s capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and other postretirement benefit obligations and invest in new and existing ventures. DPL spends a significant amount of cash on capital improvements and construction projects that have a long-term return on investment. Additionally, DPL operates in a rate-regulated environment in which the amount of new investment recovery may be limited and where such recovery takes place over an extended period of time.
Cash Flows from Operating Activities
A discussion of items pertinent to DPL’s cash flows from operating activities is set forth under Cash Flows from Operating Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Cash Flows from Investing Activities
A discussion of items pertinent to DPL’s cash flows from investing activities is set forth under Cash Flows from Investing Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Cash Flows from Financing Activities
A discussion of items pertinent to DPL’s cash flows from financing activities is set forth under Cash Flows from Financing Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Credit Matters
A discussion of credit matters pertinent to DPL is set forth under Credit Matters in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Contractual Obligations and Off-Balance Sheet Arrangements
A discussion of DPL’s contractual obligations, commercial commitments and off-balance sheet arrangements is set forth under Contractual Obligations and Off-Balance Sheet Arrangements in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Critical Accounting Policies and Estimates
See All Registrants — Critical Accounting Policies and Estimates above for a discussion of DPL’s critical accounting policies and estimates.
New Accounting Pronouncements
See Note 1 — Significant Accounting PoliciesInstruments of the Combined Notes to Consolidated Financial Statements for additional information regarding new accounting pronouncements.
| | | ITEM 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
DPL
DPL is exposed to market risks associated with credit and interest rates. These risks are described above under Quantitative and Qualitative Disclosures about Market Risk—Exelon.
| | | ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
ACE
General
ACE operates in a single business segment and its operations consist of the purchase and regulated retail sale of electricity and the provision of distribution and transmission services to retail customers in portions of southern New Jersey. This segment is discussed in further detail in ITEM 1. BUSINESS — ACE of this Form 10-K.
Executive Overview
A discussion of items pertinent to ACE’s executive overview is set forth under EXELON CORPORATION — Executive Overview of this Form 10-K.
Results of Operations
Year Ended December 31, 2019 Compared to Year Ended December 31, 2018
A discussion of ACE’s results of operations for 2019 compared to 2018 is set forth under Results of Operations—ACE in EXELON CORPORATION — Results of Operations of this Form 10-K.
Liquidity and Capital Resources
ACE’s business is capital intensive and requires considerable capital resources. ACE’s capital resources are primarily provided by internally generated cash flows from operations and, to the extent necessary, external financing, including the issuance of long-term debt, commercial paper or credit facility borrowings. ACE’s access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of the utility industry in general. At December 31, 2019, ACE had access to a revolving credit facility with aggregate bank commitments of $300 million.
See EXELON CORPORATION — Liquidity and Capital Resourcescollateral requirements and Note 1619 — DebtCommitments and Credit Agreements of the Combined Notes to Consolidated Financial Statements of this Form 10-K for additional information.
Capital resources are used primarily to fund ACE’s capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and other postretirement benefit obligations and invest in new and existing ventures. ACE spends a significant amount of cash on capital improvements and construction projects that have a long-term return on investment. Additionally, ACE operates in rate-regulated environments in which the amount of new investment recovery may be limited and where such recovery takes place over an extended period of time.
Cash Flows from Operating Activities
A discussion of items pertinent to ACE’s cash flows from operating activities is set forth under Cash Flows from Operating Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Cash Flows from Investing Activities
A discussion of items pertinent to ACE’s cash flows from investing activities is set forth under Cash Flows from Investing Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Cash Flows from Financing Activities
A discussion of items pertinent to ACE’s cash flows from financing activities is set forth under Cash Flows from Financing Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Credit Matters
A discussion of credit matters pertinent to ACE is set forth under Credit Matters in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Contractual Obligations and Off-Balance Sheet Arrangements
A discussion of ACE’s contractual obligations, commercial commitments and off-balance sheet arrangements is set forth under Contractual Obligations and Off-Balance Sheet Arrangements in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Critical Accounting Policies and Estimates
See All Registrants — Critical Accounting Policies and Estimates above for a discussion of ACE’s critical accounting policies and estimates.
New Accounting Pronouncements
See Note 1 — Significant Accounting PoliciesContingencies of the Combined Notes to Consolidated Financial Statements for additional information regarding new accounting pronouncements.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. 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 ITEM 7. Liquidity and Capital Resources — Credit Matters — Exelon Credit Facilities for additional information. The Utility Registrants As of December 31, 2021, the Utility Registrants were not required to post collateral under their energy and/or natural gas procurement contracts. See Note 3 — Regulatory Matters and Note 16 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information. RTOs and ISOs (All Registrants) All Registrants participate in all, or some, of the established, wholesale spot energy markets that are administered by PJM, ISO-NE, NYISO, CAISO, MISO, SPP, AESO, OIESO, and ERCOT. ERCOT is not subject to regulation by FERC but performs a similar function in Texas to that performed by RTOs in markets regulated by FERC. In these areas, power is traded through bilateral agreements between buyers and sellers and on the spot energy markets that are administered by the RTOs or ISOs, as applicable. In areas where there is no spot energy market, electricity is purchased and sold solely through bilateral agreements. For sales into the spot markets administered by an RTO or ISO, the RTO or ISO maintains financial assurance policies that are established and enforced by those administrators. The credit policies of the RTOs and ISOs 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. Non-performance or non-payment by a major counterparty could result in a material adverse impact on the Registrants’ financial statements. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on the February 2021 extreme cold weather event and Texas-based generating asset outages. Exchange Traded Transactions (Exelon, PHI, and DPL) Generation enters into commodity transactions on NYMEX, ICE, NASDAQ, NGX, and the Nodal exchange ("the Exchanges"). DPL enters into commodity transactions on ICE. The Exchange clearinghouses act as the counterparty to each trade. Transactions on the Exchanges must adhere to comprehensive collateral and margining requirements. As a result, transactions on Exchanges are significantly collateralized and have limited counterparty credit risk. Interest Rate and Foreign Exchange Risk (Exelon) 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 $2 million decrease in Exelon pre-tax income for the year ended December 31, 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 16—Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information. Equity Price Risk (Exelon) Generation maintains trust funds, as required by the NRC, to fund certain costs of decommissioning its nuclear plants. Generation’s NDT funds are reflected at fair value in Exelon's 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 $892 million reduction in the fair value of the trust assets as of December 31, 2021. This calculation holds all other variables constant and assumes only the discussed changes in interest rates and equity prices. See Liquidity and Capital Resources section of ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS for additional information.
| | | | | | ITEM 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
ACE
ACE is exposed to market risks associated with credit and interest rates. These risks are described above under Quantitative and Qualitative Disclosures about Market Risk— Exelon.
| | | ITEM 8. | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA |
Management’s Report on Internal Control Over Financial Reporting The management of Exelon Corporation (Exelon) is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Exelon’s management conducted an assessment of the effectiveness of Exelon’s internal control over financial reporting as of December 31, 2019.2021. In making this assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, Exelon’s management concluded that, as of December 31, 2019,2021, Exelon’s internal control over financial reporting was effective. The effectiveness of Exelon’s internal control over financial reporting as of December 31, 2019,2021, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein. February 11, 202025, 2022
Management’s Report on Internal Control Over Financial Reporting
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Contents Generation’s management conducted an assessment of the effectiveness of Generation’s internal control over financial reporting as of December 31, 2019. In making this assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, Generation’s management concluded that, as of December 31, 2019, Generation’s internal control over financial reporting was effective.
February 11, 2020
Management’s Report on Internal Control Over Financial Reporting The management of Commonwealth Edison Company (ComEd) is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. ComEd’s management conducted an assessment of the effectiveness of ComEd’s internal control over financial reporting as of December 31, 2019.2021. In making this assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, ComEd’s management concluded that, as of December 31, 2019,2021, ComEd’s internal control over financial reporting was effective. February 11, 202025, 2022
Management’s Report on Internal Control Over Financial Reporting The management of PECO Energy Company (PECO) is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. PECO’s management conducted an assessment of the effectiveness of PECO’s internal control over financial reporting as of December 31, 2019.2021. In making this assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, PECO’s management concluded that, as of December 31, 2019,2021, PECO’s internal control over financial reporting was effective. February 11, 202025, 2022
Management’s Report on Internal Control Over Financial Reporting The management of Baltimore Gas and Electric Company (BGE) is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. BGE’s management conducted an assessment of the effectiveness of BGE’s internal control over financial reporting as of December 31, 2019.2021. In making this assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, BGE’s management concluded that, as of December 31, 2019,2021, BGE’s internal control over financial reporting was effective. February 11, 202025, 2022
Management’s Report on Internal Control Over Financial Reporting The management of Pepco Holdings LLC (PHI) is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. PHI’s management conducted an assessment of the effectiveness of PHI’s internal control over financial reporting as of December 31, 2019.2021. In making this assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, PHI’s management concluded that, as of December 31, 2019,2021, PHI’s internal control over financial reporting was effective. February 11, 202025, 2022
Management’s Report on Internal Control Over Financial Reporting The management of Potomac Electric Power Company (Pepco) is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Pepco’s management conducted an assessment of the effectiveness of Pepco’s internal control over financial reporting as of December 31, 2019.2021. In making this assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, Pepco’s management concluded that, as of December 31, 2019,2021, Pepco’s internal control over financial reporting was effective. February 11, 202025, 2022
Management’s Report on Internal Control Over Financial Reporting The management of Delmarva Power & Light Company (DPL) is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. DPL’s management conducted an assessment of the effectiveness of DPL’s internal control over financial reporting as of December 31, 2019.2021. In making this assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, DPL’s management concluded that, as of December 31, 2019,2021, DPL’s internal control over financial reporting was effective. February 11, 202025, 2022
Management’s Report on Internal Control Over Financial Reporting The management of Atlantic City Electric Company (ACE) is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. ACE’s management conducted an assessment of the effectiveness of ACE’s internal control over financial reporting as of December 31, 2019.2021. In making this assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, ACE’s management concluded that, as of December 31, 2019,2021, ACE’s internal control over financial reporting was effective. February 11, 202025, 2022
Report of Independent Registered Public Accounting Firm To the Board of Directors and Shareholders of Exelon Corporation
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the consolidated financial statements, including the related notes, as listed in the index appearing under Item 15(a)(1)(i), and the financial statement schedules listed in the index appearing under Item 15(a)(1)(ii), of Exelon Corporation and its subsidiaries (the “Company”) (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2019,2021, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 20192021 and 2018,2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 20192021 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019,2021, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.
Change in Accounting Principle
As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for leases in 2019.
Basis for Opinions
The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 8. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidatedfinancial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail,
accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Critical Audit Matters
The critical audit matters communicated beloware mattersarising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that (i) relate to accounts or disclosures that are material to theconsolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Annual Nuclear Decommissioning Asset Retirement Obligations (ARO) Assessment
As described in Notes 1 and 910 to the consolidated financial statements, Exelon Generationthe Company has a legal obligation to decommission its nuclear generation stations following the expirationpermanent cessation of their operating licenses.operations. To estimate its decommissioning obligationobligations related to its nuclear generating stations for financial accounting and reporting purposes, management 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, such asand are based on decommissioning cost studies, cost escalation rates, probabilistic cash flow models, and discount rates. Management updates its ARO annually, unless circumstances warrant more frequent updates, based on its review of updated cost studies and its annual evaluation of cost escalation factors and probabilities assigned to various scenarios. As of December 31, 2019,2021, the nuclear decommissioning asset retirement obligationARO was approximately $10.5$12.7 billion.
The principal considerations for our determination that performing procedures relating to Exelon Generation’sthe Company’s annual nuclear decommissioning ARO assessment is a critical audit matter are there was athe significant amount of judgment by management when estimating its decommissioning obligation. Thisobligations; this in turn led to significanta high degree of auditor judgment, subjectivity, and effort in performing procedures to evaluateand evaluating the reasonableness of management’s discounted cash flow model and significant assumptions including therelated to decommissioning cost studies. In addition, the audit effort involved the use of professionals with specialized skill and knowledge to assist in evaluating the audit evidence obtained from these procedures.
knowledge.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s development of the inputs, assumptions, and model used in management’s ARO assessment. These procedures also included, among others, testing management’s process for developingestimating the ARO estimatesdecommissioning obligations by evaluating the appropriateness of the discounted cash flow model, testing the completeness and accuracy of data used by management, and evaluating the reasonableness of management’s significant assumptions includingrelated to decommissioning cost studies. Professionals with specialized skill and knowledge were used to assist in evaluating the results of decommissioning cost studies.
Impairment Assessment of Long-Lived Generation Assets
As described in Notes 1, 8, and 1112 to the consolidated financial statements, Exelon Generationthe Company evaluates 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, or plans to dispose of a long-lived asset significantly before the end of its useful life. Management determines if long-lived assets andor asset groups are potentially impaired by comparing the undiscounted expected future
cash flows to the carrying value.value when indicators of impairment exist. When the undiscounted cash flow analysis indicates a long-lived asset or asset group ismay not be 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 undiscounted expected future cash flows includefair value analysis is primarily based on the income approach using significant unobservable inputs including revenue and generation forecasts, and projected capital and maintenance expenditures.expenditures, and discount rates. As of December 31, 2019,2021, the total carrying value of long-lived generation assets subject to this evaluationassessment was approximately $24.2$19.6 billion.
The principal considerations for our determination that performing procedures relating to Exelon Generation’sthe Company’s impairment assessment of long-lived generation assets is a critical audit matter are there was athe significant amount of judgment by management in assessing the recoverability and estimating the fair value of these long-lived generation assets or asset groups. Thisgroups; this in turn led to significanta high degree of auditor judgment, subjectivity and effort in performing procedures to evaluate the audit evidence related toand evaluating the reasonableness of management’s significant assumptions used in management's estimates, includingrelated to revenue and generation forecasts. In addition, the audit effort involved the use of professionals with specialized skillsskill and knowledge to assist in evaluating the audit evidence obtained from these procedures.
knowledge.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s development of the inputs, assumptions, and model used to assess the recoverability and estimate the recoverabilityfair value of Exelon Generation’sthe Company’s long-lived generation assets or asset groups. These procedures also included, among others, testing management’s process for developing undiscountedthe expected future cash flows for the long-lived generation assets or asset groups by evaluating the appropriateness of the future cash flow model, testing the completeness and accuracy of the data used by management, and evaluating the reasonableness of management’s significant assumptions includingrelated to revenue and generation forecasts. Evaluating the reasonableness of the revenue and generation forecasts involved considering whether the forecasts were consistent with future commodity prices and external market data. Professionals with specialized skill and knowledge were used to assist in evaluating the reasonableness of the revenue forecasts.
Level 3 Derivatives Significant Assumptions
As described in Notes 1, 15 and 17 to the consolidated financial statements, Exelon Generation has derivative instruments that include both observable and unobservable inputs. When valuing Level 3 derivatives, management utilizes various inputs and assumptions including forward commodity prices, commodity price volatility, contractual volumes, delivery location, interest rates, credit quality of counterparties and credit enhancements. Those derivatives with significant unobservable inputs are classified as Level 3. As of December 31, 2019, the Company had a level 3 fair value derivative asset position of $957 million and a level 3 fair value derivative liability position of $140 million.
The principal considerations for our determination that performing procedures relating to the significant assumptions used to value Exelon Generation’s Level 3 derivatives is a critical audit matter are there was a significant amount of judgment by management in determining the inputs and assumptions used to estimate the fair value of the Level 3 derivatives. This in turn led to significant auditor judgment, subjectivity, and effort in performing procedures to evaluate audit evidence related to the reasonableness of management’s significant assumptions used in management’s estimates, including forward commodity prices. In addition, the audit effort involved the use of professionals with specialized skill and knowledge to assist in evaluating the audit evidence obtained from these procedures.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s development of the inputs, assumptions, and model used to estimate the fair value of Level 3 derivatives. These procedures also included, among others, testing management’s process for valuing the Level 3 derivatives by evaluating the appropriateness of management’s model, testing the completeness and accuracy of data used by management, and evaluating the reasonableness of management’s significant assumptions, including forward commodity prices. Professionals with specialized skill and knowledge were used to assist in evaluating the reasonableness of forward commodity prices.
Accounting for the Effects of Rate Regulation
As described in Notes 1 and 3 to the consolidated financial statements, the Company applies the authoritative guidance for accounting for certain types of regulation, which requires management to record in theirthe consolidated financial statements the effects of cost-based rate regulation for entities with regulated operations
that meet the following criteria, (i) rates are established or approved by a third-party regulator; (ii) rates are designed to recover the entity’s cost of providing services or products; and (iii) there is a reasonable expectation that rates designed to recover costs can be charged to and collected from customers. The Company accounts for its regulated operations in accordance with regulatory and legislative guidance from the regulatory authorities having jurisdiction under state public utility laws and the FERC under various Federal laws. Upon updates in material regulatory and legislative proceedings, where applicable, management will record new regulatory assets or liabilities and will assess whether it is probable that its currently recorded regulatory assets and liabilities will be recovered and settled, respectively, in future rates. As of December 31, 2019,2021, there were $9.5 billion of regulatory assets and $10.4$10.0 billion of regulatory liabilities.
The principal considerations for our determination that performing procedures relating to the Company’s accounting for the effects of rate regulation is a critical audit matter are there was a significant amountthe high degree of judgment by management when assessingaudit effort to assess the impact of updates in regulation on accounting for new and existing regulatory assets and liabilities and to evaluate the evaluation ofcomplex audit evidence related to whether the regulatory assets and liabilities will be recovered and settled, respectively. This in turn led to significant auditor judgment and audit effort to perform procedures relating to the accounting for the impact of regulatory and legislative proceedings on new and existing regulatory assets and liabilities.
settled.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to the implementation of newaccounting for regulatory matters and evaluation of new and existing regulatory assets and liabilities. These procedures also included, among others, obtaining the Company’s correspondence with regulators, evaluating the reasonableness of management’s judgments regarding new and updatedinterpretation of regulatory guidance and proceedings and the related accounting implications, and calculatingrecalculating regulatory assets and liabilities based on provisions and formulas outlined in rate orders and other correspondence with regulators.
/s/ PricewaterhouseCoopers LLP Chicago, Illinois February 11, 202025, 2022
We have served as the Company’s auditor since 2000.
Report of Independent Registered Public Accounting Firm
To the Board of Directors and MemberShareholders of Exelon GenerationCommonwealth Edison Company LLC
Opinion on the Financial Statements
We have audited the consolidated financial statements, including the related notes, as listed in the index appearing under Item 15(a)(2)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(2)(ii), of Exelon GenerationCommonwealth Edison Company LLC and its subsidiaries (the “Company”) (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Companyas of December 31, 20192021 and 2018,2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 20192021 in conformity with accounting principles generally accepted in the United States of America.
Change in Accounting Principle
As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for leases in 2019.
Basis for Opinion
These consolidatedfinancial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits of theseconsolidated financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the auditaudits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the consolidatedfinancial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in theconsolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of theconsolidatedfinancial statements. We believe that our audits provide a reasonable basis for our opinion. Critical Audit Matters The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates. Accounting for the Effects of Rate Regulation As described in Notes 1 and 3 to the consolidated financial statements, the Company applies the authoritative guidance for accounting for certain types of regulation, which requires management to record in the consolidated financial statements the effects of cost-based rate regulation for entities with regulated operations that meet the following criteria, (i) rates are established or approved by a third-party regulator; (ii) rates are designed to recover the entity’s cost of providing services or products; and (iii) there is a reasonable expectation that rates designed to recover costs can be charged to and collected from customers. The Company accounts for its regulated operations in accordance with regulatory and legislative guidance from the regulatory authorities having jurisdiction under state public utility laws and the FERC under various Federal laws. Upon updates in material regulatory and legislative proceedings, where applicable, management will record new regulatory assets or liabilities and will assess whether it is probable that its currently recorded regulatory assets and liabilities will be
recovered and settled, respectively, in future rates. As of December 31, 2021, there were $2.2 billion of regulatory assets and $6.9 billion of regulatory liabilities. The principal considerations for our determination that performing procedures relating to the Company’s accounting for the effects of rate regulation is a critical audit matter are the high degree of audit effort to assess the impact of regulation on accounting for regulatory assets and liabilities and to evaluate the complex audit evidence related to whether the regulatory assets and liabilities will be recovered and settled. Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to accounting for regulatory matters and evaluation of new and existing regulatory assets and liabilities. These procedures also included, among others, obtaining the Company’s correspondence with regulators, evaluating the reasonableness of management’s interpretation of regulatory guidance and proceedings and the related accounting implications, and recalculating regulatory assets and liabilities based on provisions outlined in rate orders and other correspondence with regulators.
/s/ PricewaterhouseCoopers LLP Baltimore, MarylandChicago, Illinois
February 11, 202025, 2022
We have served as the Company's auditor since 2001.2000.
Report of Independent Registered Public Accounting Firm
To the Board of Directors and ShareholdersShareholder of Commonwealth EdisonPECO Energy Company
Opinion on the Financial Statements
We have audited the consolidated financial statements, including the related notes, as listed in the index appearing under Item 15(a)(3)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(3)(ii), of Commonwealth Edison PECO Energy Company and its subsidiaries (the “Company”) (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Companyas of December 31, 20192021 and 2018,2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 20192021 in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits of theseconsolidated financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the auditaudits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of theconsolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in theconsolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of theconsolidated financial statements. We believe that our audits provide a reasonable basis for our opinion. Critical Audit Matters The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates. Accounting for the Effects of Rate Regulation As described in Notes 1 and 3 to the consolidated financial statements, the Company applies the authoritative guidance for accounting for certain types of regulation, which requires management to record in the consolidated financial statements the effects of cost-based rate regulation for entities with regulated operations that meet the following criteria, (i) rates are established or approved by a third-party regulator; (ii) rates are designed to recover the entity’s cost of providing services or products; and (iii) there is a reasonable expectation that rates designed to recover costs can be charged to and collected from customers. The Company accounts for its regulated operations in accordance with regulatory and legislative guidance from the regulatory authorities having jurisdiction under state public utility laws and the FERC under various Federal laws. Upon updates in material regulatory and legislative proceedings, where applicable, management will record new regulatory assets or liabilities and will assess whether it is probable that its currently recorded regulatory assets and liabilities will be
recovered and settled, respectively, in future rates. As of December 31, 2021, there were $991 million of regulatory assets and $729 million of regulatory liabilities. The principal considerations for our determination that performing procedures relating to the Company’s accounting for the effects of rate regulation is a critical audit matter are the high degree of audit effort to assess the impact of regulation on accounting for regulatory assets and liabilities and to evaluate the complex audit evidence related to whether the regulatory assets and liabilities will be recovered and settled. Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to accounting for regulatory matters and evaluation of new and existing regulatory assets and liabilities. These procedures also included, among others, obtaining the Company’s correspondence with regulators, evaluating the reasonableness of management’s interpretation of regulatory guidance and proceedings and the related accounting implications, and recalculating regulatory assets and liabilities based on provisions outlined in rate orders and other correspondence with regulators.
/s/ PricewaterhouseCoopers LLP Chicago, IllinoisPhiladelphia, Pennsylvania
February 11, 202025, 2022
We have served as the Company's auditor since 2000.1932.
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholder of PECO EnergyBaltimore Gas and Electric Company
Opinion on the Financial Statements
We have audited the consolidated financial statements, including the related notes, as listed in the index appearing under Item 15(a)(4)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(4)(ii), of PECO EnergyBaltimore Gas and Electric Company (the “Company”) (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021 in conformity with accounting principles generally accepted in the United States of America. Basis for Opinion These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits of these financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion. Critical Audit Matters The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates. Accounting for the Effects of Rate Regulation As described in Notes 1 and 3 to the financial statements, the Company applies the authoritative guidance for accounting for certain types of regulation, which requires management to record in the financial statements the effects of cost-based rate regulation for entities with regulated operations that meet the following criteria, (i) rates are established or approved by a third-party regulator; (ii) rates are designed to recover the entity’s cost of providing services or products; and (iii) there is a reasonable expectation that rates designed to recover costs can be charged to and collected from customers. The Company accounts for its regulated operations in accordance with regulatory and legislative guidance from the regulatory authorities having jurisdiction under state public utility laws and the FERC under various Federal laws. Upon updates in material regulatory and legislative proceedings, where applicable, management will record new regulatory assets or liabilities and will assess whether it is probable that its currently recorded regulatory assets and liabilities will be recovered and settled,
respectively, in future rates. As of December 31, 2021, there were $692 million of regulatory assets and $960 million of regulatory liabilities. The principal considerations for our determination that performing procedures relating to the Company’s accounting for the effects of rate regulation is a critical audit matter are the high degree of audit effort to assess the impact of regulation on accounting for regulatory assets and liabilities and to evaluate the complex audit evidence related to whether the regulatory assets and liabilities will be recovered and settled. Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the financial statements. These procedures included testing the effectiveness of controls relating to accounting for regulatory matters and evaluation of new and existing regulatory assets and liabilities. These procedures also included, among others, obtaining the Company’s correspondence with regulators, evaluating the reasonableness of management’s interpretation of regulatory guidance and proceedings and the related accounting implications, and recalculating regulatory assets and liabilities based on provisions outlined in rate orders and other correspondence with regulators.
/s/ PricewaterhouseCoopers LLP Baltimore, Maryland February 25, 2022 We have served as the Company’s auditor since at least 1993. We have not been able to determine the specific year we began serving as auditor of the Company.
Report of Independent Registered Public Accounting Firm
To theBoard of Directors and Member of Pepco Holdings LLC
Opinion on the Financial Statements We have audited the consolidated financial statements, including the related notes, as listed in the index appearing under Item 15(a)(5)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(5)(ii), of Pepco Holdings LLC and its subsidiaries (the “Company”) (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Companyas of December 31, 20192021 and 2018,2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 20192021 in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
Theseconsolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits of theseconsolidatedfinancial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the auditaudits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of theconsolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidatedfinancial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidatedfinancial statements. We believe that our audits provide a reasonable basis for our opinion. Critical Audit Matters The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates. Accounting for the Effects of Rate Regulation As described in Notes 1 and 3 to the consolidated financial statements, the Company applies the authoritative guidance for accounting for certain types of regulation, which requires management to record in the consolidated financial statements the effects of cost-based rate regulation for entities with regulated operations that meet the following criteria, (i) rates are established or approved by a third-party regulator; (ii) rates are designed to recover the entity’s cost of providing services or products; and (iii) there is a reasonable expectation that rates designed to recover costs can be charged to and collected from customers. The Company accounts for its regulated operations in accordance with regulatory and legislative guidance from the regulatory authorities having jurisdiction under state public utility laws and the FERC under various Federal laws. Upon updates in material regulatory and legislative proceedings, where applicable, management will record new regulatory assets or liabilities and will assess whether it is probable that its currently recorded regulatory assets and liabilities will be
recovered and settled, respectively, in future rates. As of December 31, 2021, there were $2.2 billion of regulatory assets and $1.3 billion of regulatory liabilities. The principal considerations for our determination that performing procedures relating to the Company’s accounting for the effects of rate regulation is a critical audit matter are the high degree of audit effort to assess the impact of regulation on accounting for regulatory assets and liabilities and to evaluate the complex audit evidence related to whether the regulatory assets and liabilities will be recovered and settled. Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to accounting for regulatory matters and evaluation of new and existing regulatory assets and liabilities. These procedures also included, among others, obtaining the Company’s correspondence with regulators, evaluating the reasonableness of management’s interpretation of regulatory guidance and proceedings and the related accounting implications, and recalculating regulatory assets and liabilities based on provisions outlined in rate orders and other correspondence with regulators.
/s/ PricewaterhouseCoopers LLP Philadelphia, Pennsylvania February 11, 202025, 2022
We have served as the Company's auditor since 1932.2001.
Report of Independent Registered Public Accounting Firm
To the the Board of Directors and Shareholder of Baltimore Gas andPotomac Electric Power Company
Opinion on the Financial Statements
We have audited the financial statements, including the related notes, as listed in the index appearing under Item 15(a)(6)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(6)(ii), of Potomac Electric Power Company (the “Company”) (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021 in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits of these financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion. Critical Audit Matters The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates. Accounting for the Effects of Rate Regulation As described in Notes 1 and 3 to the financial statements, the Company applies the authoritative guidance for accounting for certain types of regulation, which requires management to record in the financial statements the effects of cost-based rate regulation for entities with regulated operations that meet the following criteria, (i) rates are established or approved by a third-party regulator; (ii) rates are designed to recover the entity’s cost of providing services or products; and (iii) there is a reasonable expectation that rates designed to recover costs can be charged to and collected from customers. The Company accounts for its regulated operations in accordance with regulatory and legislative guidance from the regulatory authorities having jurisdiction under state public utility laws and the FERC under various Federal laws. Upon updates in material regulatory and legislative proceedings, where applicable, management will record new regulatory assets or liabilities and will assess whether it is probable that its currently recorded regulatory assets and liabilities will be recovered and settled,
respectively, in future rates. As of December 31, 2021, there were $745 million of regulatory assets and $563 million of regulatory liabilities. The principal considerations for our determination that performing procedures relating to the Company’s accounting for the effects of rate regulation is a critical audit matter are the high degree of audit effort to assess the impact of regulation on accounting for regulatory assets and liabilities and to evaluate the complex audit evidence related to whether the regulatory assets and liabilities will be recovered and settled. Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the financial statements. These procedures included testing the effectiveness of controls relating to accounting for regulatory matters and evaluation of new and existing regulatory assets and liabilities. These procedures also included, among others, obtaining the Company’s correspondence with regulators, evaluating the reasonableness of management’s interpretation of regulatory guidance and proceedings and the related accounting implications, and recalculating regulatory assets and liabilities based on provisions outlined in rate orders and other correspondence with regulators.
/s/ PricewaterhouseCoopers LLP Philadelphia, Pennsylvania February 25, 2022
We have served as the Company's auditor since at least 1993. We have not been able to determine the specific year we began serving as auditor of the Company.
Report of Independent Registered Public Accounting Firm
Tothe Board of Directors and Shareholder of Delmarva Power & Light Company
Opinion on the Financial Statements We have audited the financial statements, including the related notes, as listed in the index appearing under Item 15(a)(7)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(7)(ii), of Delmarva Power & Light Company (the “Company”) (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021 in conformity with accounting principles generally accepted in the United States of America. Basis for Opinion These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits of these financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion. Critical Audit Matters The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates. Accounting for the Effects of Rate Regulation As described in Notes 1 and 3 to the financial statements, the Company applies the authoritative guidance for accounting for certain types of regulation, which requires management to record in the financial statements the effects of cost-based rate regulation for entities with regulated operations that meet the following criteria, (i) rates are established or approved by a third-party regulator; (ii) rates are designed to recover the entity’s cost of providing services or products; and (iii) there is a reasonable expectation that rates designed to recover costs can be charged to and collected from customers. The Company accounts for its regulated operations in accordance with regulatory and legislative guidance from the regulatory authorities having jurisdiction under state public utility laws and the FERC under various Federal laws. Upon updates in material regulatory and legislative proceedings, where applicable, management will record new regulatory assets or liabilities and will assess whether it is probable that its currently recorded regulatory assets and liabilities will be recovered and settled,
respectively, in future rates. As of December 31, 2021, there were $280 million of regulatory assets and $466 million of regulatory liabilities. The principal considerations for our determination that performing procedures relating to the Company’s accounting for the effects of rate regulation is a critical audit matter are the high degree of audit effort to assess the impact of regulation on accounting for regulatory assets and liabilities and to evaluate the complex audit evidence related to whether the regulatory assets and liabilities will be recovered and settled. Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the financial statements. These procedures included testing the effectiveness of controls relating to accounting for regulatory matters and evaluation of new and existing regulatory assets and liabilities. These procedures also included, among others, obtaining the Company’s correspondence with regulators, evaluating the reasonableness of management’s interpretation of regulatory guidance and proceedings and the related accounting implications, and recalculating regulatory assets and liabilities based on provisions outlined in rate orders and other correspondence with regulators.
/s/ PricewaterhouseCoopers LLP Philadelphia, Pennsylvania February 25, 2022
We have served as the Company's auditor since at least 1993. We have not been able to determine the specific year we began serving as auditor of the Company.
Report of Independent Registered Public Accounting Firm
Tothe Board of Directors and Shareholder of Atlantic City Electric Company
Opinion on the Financial Statements We have audited the consolidated financial statements, including the related notes, as listed in the index appearing under Item 15(a)(5)(8)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(5)(8)(ii), of Baltimore Gas andAtlantic City Electric Company and its subsidiariessubsidiary (the “Company”) (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Companyas of December 31, 20192021 and 2018,2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 20192021 in conformity with accounting principles generally accepted in the United States of America.
Change in Accounting Principle
As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for leases in 2019.
Basis for Opinion
Theseconsolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits of theseconsolidatedfinancial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the auditaudits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the consolidatedfinancial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidatedfinancial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
Baltimore, Maryland
February 11, 2020
We have served as the Company’s auditor since at least 1993. We have not been able to determine the specific year we began serving as auditor of the Company.
Report of Independent Registered Public Accounting Firm
To theBoard of Directors and Member of Pepco Holdings LLC
Opinion on the Financial Statements
We have audited the consolidated financial statements, including the related notes, as listed in the index appearing under Item 15(a)(6)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(6)(ii), of Pepco Holdings LLC and its subsidiaries (the “Company”) (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Companyas of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019in conformity with accounting principles generally accepted in the United States of America.
Change in Accounting Principle
As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for leases in 2019.
Basis for Opinion
Theseconsolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits of theseconsolidated financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the consolidatedfinancial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidatedfinancial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of theconsolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
Washington, DC
February 11, 2020
We have served as the Company's auditor since 2001.
Report of Independent Registered Public Accounting Firm
Tothe Board of Directors and Shareholder of Potomac Electric Power Company
Opinion on the Financial Statements
We have audited the financial statements, including the related notes, as listed in the index appearing under Item 15(a)(7)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(7)(ii), of Potomac Electric Power Company (the “Company”) (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Companyas of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019in conformity with accounting principles generally accepted in the United States of America.
Change in Accounting Principle
As discussed in Note 1 to the financial statements, the Company changed the manner in which it accounts for leases in 2019.
Basis for Opinion
Thesefinancial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits of thesefinancial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of thefinancial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in thefinancial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of thefinancial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
Washington, DC
February 11, 2020
We have served as the Company's auditor since at least 1993. We have not been able to determine the specific year we began serving as auditor of the Company.
Report of Independent Registered Public Accounting Firm
Tothe Board of Directors and Shareholder of Delmarva Power & Light Company
Opinion on the Financial Statements
We have audited the financial statements, including the related notes, as listed in the index appearing under Item 15(a)(8)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(8)(ii), of Delmarva Power & Light Company (the “Company”) (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Companyas of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019in conformity with accounting principles generally accepted in the United States of America.
Change in Accounting Principle
As discussed in Note 1 to the financial statements, the Company changed the manner in which it accounts for leases in 2019.
Basis for Opinion
Thesefinancial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits of thesefinancial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of thefinancial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in thefinancial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of thefinancial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
Washington, DC
February 11, 2020
We have served as the Company's auditor since at least 1993. We have not been able to determine the specific year we began serving as auditor of the Company.
Report of Independent Registered Public Accounting Firm
Tothe Board of Directors and Shareholder of Atlantic City Electric Company
Opinion on the Financial Statements
We have audited the consolidated financial statements, including the related notes, as listed in the index appearing under Item 15(a)(9)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(9)(ii), of Atlantic City Electric Company and its subsidiary (the “Company”) (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Companyas of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019in conformity with accounting principles generally accepted in the United States of America.
Change in Accounting Principle
As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for leases in 2019.
Basis for Opinion
These consolidatedfinancial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits of these consolidatedfinancial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the consolidatedfinancial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidatedfinancial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidatedfinancial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates. Accounting for the Effects of Rate Regulation As described in Notes 1 and 3 to the consolidated financial statements, the Company applies the authoritative guidance for accounting for certain types of regulation, which requires management to record in the consolidated financial statements the effects of cost-based rate regulation for entities with regulated operations that meet the following criteria, (i) rates are established or approved by a third-party regulator; (ii) rates are designed to recover the entity’s cost of providing services or products; and (iii) there is a reasonable expectation that rates designed to recover costs can be charged to and collected from customers. The Company accounts for its regulated operations in accordance with regulatory and legislative guidance from the regulatory authorities having jurisdiction under state public utility laws and the FERC under various Federal laws. Upon updates in material regulatory and legislative proceedings, where applicable, management will record new regulatory assets or liabilities and will assess whether it is probable that its currently recorded regulatory assets and liabilities will be
recovered and settled, respectively, in future rates. As of December 31, 2021, there were $491 million of regulatory assets and $252 million of regulatory liabilities. The principal considerations for our determination that performing procedures relating to the Company’s accounting for the effects of rate regulation is a critical audit matter are the high degree of audit effort to assess the impact of regulation on accounting for regulatory assets and liabilities and to evaluate the complex audit evidence related to whether the regulatory assets and liabilities will be recovered and settled. Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to accounting for regulatory matters and evaluation of new and existing regulatory assets and liabilities. These procedures also included, among others, obtaining the Company’s correspondence with regulators, evaluating the reasonableness of management’s interpretation of regulatory guidance and proceedings and the related accounting implications, and recalculating regulatory assets and liabilities based on provisions outlined in rate orders and other correspondence with regulators.
/s/ PricewaterhouseCoopers LLP Washington, DCPhiladelphia, Pennsylvania
February 11, 202025, 2022
We have served as the Company's auditor since 1998.
Exelon Corporation and Subsidiary Companies Consolidated Statements of Operations and Comprehensive Income | | | For the Years Ended December 31, | | For the Years Ended December 31, | (In millions, except per share data) | 2019 | | 2018 | | 2017 | (In millions, except per share data) | 2021 | | 2020 | | 2019 | Operating revenues | | | | | | Operating revenues | | | | | | Competitive businesses revenues | $ | 17,754 |
| | $ | 19,168 |
| | $ | 17,394 |
| Competitive businesses revenues | $ | 18,467 | | | $ | 16,400 | | | $ | 17,754 | | Rate-regulated utility revenues | 16,839 |
| | 16,879 |
| | 15,964 |
| Rate-regulated utility revenues | 17,709 | | | 16,633 | | | 16,839 | | Revenues from alternative revenue programs | (155 | ) | | (69 | ) | | 200 |
| Revenues from alternative revenue programs | 171 | | | 6 | | | (155) | | | Total operating revenues | 34,438 |
| | 35,978 |
| | 33,558 |
| Total operating revenues | 36,347 | | | 33,039 | | | 34,438 | | Operating expenses | | | | | | Operating expenses | | | | | | Competitive businesses purchased power and fuel | 10,849 |
| | 11,679 |
| | 9,668 |
| Competitive businesses purchased power and fuel | 12,157 | | | 9,592 | | | 10,849 | | Rate-regulated utility purchased power and fuel | 4,648 |
| | 4,991 |
| | 4,367 |
| Rate-regulated utility purchased power and fuel | 5,207 | | | 4,512 | | | 4,648 | | | Operating and maintenance | 8,615 |
| | 9,337 |
| | 10,025 |
| Operating and maintenance | 8,659 | | | 9,408 | | | 8,615 | | Depreciation and amortization | 4,252 |
| | 4,353 |
| | 3,828 |
| Depreciation and amortization | 6,036 | | | 5,014 | | | 4,252 | | Taxes other than income taxes | 1,732 |
| | 1,783 |
| | 1,731 |
| Taxes other than income taxes | 1,766 | | | 1,714 | | | 1,732 | | Total operating expenses | 30,096 |
|
| 32,143 |
|
| 29,619 |
| Total operating expenses | 33,825 | | | 30,240 | | | 30,096 | | | Gain on sales of assets and businesses | 31 |
| | 56 |
| | 3 |
| Gain on sales of assets and businesses | 201 | | | 24 | | | 31 | | Bargain purchase gain | — |
| | — |
| | 233 |
| | | Gain on deconsolidation of business | 1 |
| | — |
| | 213 |
| Gain on deconsolidation of business | — | | | — | | | 1 | | Operating income | 4,374 |
|
| 3,891 |
|
| 4,388 |
| Operating income | 2,723 | | | 2,823 | | | 4,374 | | Other income and (deductions) | | | | | | Other income and (deductions) | | | | | | Interest expense, net | (1,591 | ) | | (1,529 | ) | | (1,524 | ) | Interest expense, net | (1,546) | | | (1,610) | | | (1,591) | | Interest expense to affiliates | (25 | ) | | (25 | ) | | (36 | ) | Interest expense to affiliates | (25) | | | (25) | | | (25) | | Other, net | 1,227 |
| | (112 | ) | | 947 |
| Other, net | 1,056 | | | 1,145 | | | 1,227 | | Total other income and (deductions) | (389 | ) |
| (1,666 | ) |
| (613 | ) | Total other income and (deductions) | (515) | | | (490) | | | (389) | | Income before income taxes | 3,985 |
| | 2,225 |
| | 3,775 |
| Income before income taxes | 2,208 | | | 2,333 | | | 3,985 | | Income taxes | 774 |
| | 118 |
| | (126 | ) | Income taxes | 370 | | | 373 | | | 774 | | Equity in losses of unconsolidated affiliates | (183 | ) | | (28 | ) | | (32 | ) | Equity in losses of unconsolidated affiliates | (9) | | | (6) | | | (183) | | Net income | 3,028 |
|
| 2,079 |
|
| 3,869 |
| Net income | 1,829 | | | 1,954 | | | 3,028 | | Net income attributable to noncontrolling interests | 92 |
| | 74 |
| | 90 |
| | Net income (loss) attributable to noncontrolling interests | | Net income (loss) attributable to noncontrolling interests | 123 | | | (9) | | | 92 | | Net income attributable to common shareholders | $ | 2,936 |
|
| $ | 2,005 |
|
| $ | 3,779 |
| Net income attributable to common shareholders | $ | 1,706 | | | $ | 1,963 | | | $ | 2,936 | | Comprehensive income, net of income taxes | | | | | | Comprehensive income, net of income taxes | | | | | | Net income | $ | 3,028 |
| | $ | 2,079 |
| | $ | 3,869 |
| Net income | $ | 1,829 | | | $ | 1,954 | | | $ | 3,028 | | 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: | | Prior service benefit reclassified to periodic benefit cost | (65 | ) | | (66 | ) | | (56 | ) | Prior service benefit reclassified to periodic benefit cost | (4) | | | (40) | | | (65) | | Actuarial loss reclassified to periodic benefit cost | 149 |
| | 247 |
| | 197 |
| Actuarial loss reclassified to periodic benefit cost | 223 | | | 190 | | | 149 | | | Pension and non-pension postretirement benefit plan valuation adjustment | (289 | ) | | (143 | ) | | 10 |
| Pension and non-pension postretirement benefit plan valuation adjustment | 432 | | | (357) | | | (289) | | Unrealized gain on cash flow hedges | — |
| | 12 |
| | 3 |
| | Unrealized gain on marketable securities | — |
| | — |
| | 6 |
| | Unrealized loss on cash flow hedges | | Unrealized loss on cash flow hedges | (1) | | | (3) | | | — | | | Unrealized gain on investments in unconsolidated affiliates | 1 |
| | 2 |
| | 4 |
| Unrealized gain on investments in unconsolidated affiliates | — | | | — | | | 1 | | Unrealized gain (loss) on foreign currency translation | 6 |
| | (10 | ) | | 7 |
| | Other comprehensive income | (198 | ) |
| 42 |
|
| 171 |
| | Unrealized gain on foreign currency translation | | Unrealized gain on foreign currency translation | — | | | 4 | | | 6 | | | Other comprehensive income (loss) | | Other comprehensive income (loss) | 650 | | | (206) | | | (198) | | Comprehensive income | 2,830 |
|
| 2,121 |
|
| 4,040 |
| Comprehensive income | 2,479 | | | 1,748 | | | 2,830 | | Comprehensive income attributable to noncontrolling interests | 93 |
| | 75 |
| | 88 |
| | Comprehensive income (loss) attributable to noncontrolling interests | | Comprehensive income (loss) attributable to noncontrolling interests | 123 | | | (9) | | | 93 | | Comprehensive income attributable to common shareholders | $ | 2,737 |
| | $ | 2,046 |
|
| $ | 3,952 |
| Comprehensive income attributable to common shareholders | $ | 2,356 | | | $ | 1,757 | | | $ | 2,737 | | | | | | | | | | | | | | Average shares of common stock outstanding: | | | | | | Average shares of common stock outstanding: | | Basic | 973 |
| | 967 |
| | 947 |
| Basic | 979 | | | 976 | | | 973 | | Assumed exercise and/or distributions of stock-based awards | 1 |
| | 2 |
| | 2 |
| Assumed exercise and/or distributions of stock-based awards | 1 | | | 1 | | | 1 | | Diluted(a) | 974 |
| | 969 |
| | 949 |
| Diluted(a) | 980 | | | 977 | | | 974 | | Earnings per average common share: | | | | | | Earnings per average common share: | | | | | | Basic | $ | 3.02 |
| | $ | 2.07 |
| | $ | 3.99 |
| Basic | $ | 1.74 | | | $ | 2.01 | | | $ | 3.02 | | Diluted | $ | 3.01 |
|
| $ | 2.07 |
| | $ | 3.98 |
| Diluted | $ | 1.74 | | | $ | 2.01 | | | $ | 3.01 | |
__________ | | (a) | The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was immaterial for the year ended December 31, 2019 and approximately 3 million and 8 million for the years ended December 31, 2018 and 2017, respectively. |
(a)The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was zero for the year ended December 31, 2021 and less than 1 million for the years ended December 31, 2020 and 2019.
See the Combined Notes to Consolidated Financial Statements
178151
Exelon Corporation and Subsidiary Companies Consolidated Statements of Cash Flows | | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | (In millions) | 2021 | | 2020 | | 2019 | Cash flows from operating activities | | | | | | Net income | $ | 1,829 | | | $ | 1,954 | | | $ | 3,028 | | Adjustments to reconcile net income to net cash flows provided by operating activities: | | | | | | Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization | 7,573 | | | 6,527 | | | 5,780 | | Asset impairments | 552 | | | 591 | | | 201 | | Gain on sales of assets and businesses | (201) | | | (24) | | | (27) | | | | | | | | | | | | | | Deferred income taxes and amortization of investment tax credits | 18 | | | 309 | | | 681 | | Net fair value changes related to derivatives | (568) | | | (268) | | | 222 | | Net realized and unrealized gains on NDT funds | (586) | | | (461) | | | (663) | | Net unrealized losses (gains) on equity investments | 160 | | | (186) | | | — | | Other non-cash operating activities | (200) | | | 592 | | | 613 | | Changes in assets and liabilities: | | | | | | Accounts receivable | (703) | | | 697 | | | (243) | | Inventories | (141) | | | (85) | | | (87) | | Accounts payable and accrued expenses | 440 | | | (129) | | | (425) | | Option premiums paid, net | (338) | | | (139) | | | (29) | | Collateral (posted) received, net | (74) | | | 494 | | | (438) | | Income taxes | 327 | | | 140 | | | (64) | | Pension and non-pension postretirement benefit contributions | (665) | | | (601) | | | (408) | | | | | | | | Other assets and liabilities | (4,411) | | | (5,176) | | | (1,482) | | Net cash flows provided by operating activities | 3,012 | | | 4,235 | | | 6,659 | | Cash flows from investing activities | | | | | | Capital expenditures | (7,981) | | | (8,048) | | | (7,248) | | | | | | | | Proceeds from NDT fund sales | 6,532 | | | 3,341 | | | 10,051 | | Investment in NDT funds | (6,673) | | | (3,464) | | | (10,087) | | Collection of DPP | 3,902 | | | 3,771 | | | — | | Acquisitions of assets and businesses, net | — | | | — | | | (41) | | Proceeds from sales of assets and businesses | 877 | | | 46 | | | 53 | | | | | | | | | | | | | | | | | | | | Other investing activities | 26 | | | 18 | | | 12 | | Net cash flows used in investing activities | (3,317) | | | (4,336) | | | (7,260) | | Cash flows from financing activities | | | | | | | | | | | | Changes in short-term borrowings | 269 | | | 161 | | | 781 | | Proceeds from short-term borrowings with maturities greater than 90 days | 1,380 | | | 500 | | | — | | Repayments on short-term borrowings with maturities greater than 90 days | (350) | | | — | | | (125) | | Issuance of long-term debt | 3,481 | | | 7,507 | | | 1,951 | | Retirement of long-term debt | (1,640) | | | (6,440) | | | (1,287) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Dividends paid on common stock | (1,497) | | | (1,492) | | | (1,408) | | Acquisition of CENG noncontrolling interest | (885) | | | — | | | — | | Proceeds from employee stock plans | 80 | | | 45 | | | 112 | | | | | | | | Other financing activities | (80) | | | (136) | | | (82) | | Net cash flows provided by (used in) financing activities | 758 | | | 145 | | | (58) | | Increase (decrease) in cash, restricted cash, and cash equivalents | 453 | | | 44 | | | (659) | | Cash, restricted cash, and cash equivalents at beginning of period | 1,166 | | | 1,122 | | | 1,781 | | Cash, restricted cash, and cash equivalents at end of period | $ | 1,619 | | | $ | 1,166 | | | $ | 1,122 | | | | | | | | Supplemental cash flow information | | | | | | Increase (decrease) in capital expenditures not paid | $ | 16 | | | $ | 194 | | | $ | (7) | | Increase in DPP | 3,652 | | | 4,441 | | | — | | Increase in PP&E related to ARO update | 642 | | | 850 | | | 968 | |
| | | | | | | | | | | | | | For the Years Ended December 31, | (In millions) | 2019 | | 2018 | | 2017 | Cash flows from operating activities | | | | | | Net income | $ | 3,028 |
| | $ | 2,079 |
| | $ | 3,869 |
| Adjustments to reconcile net income to net cash flows provided by operating activities: | | | | | | Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization | 5,780 |
| | 5,971 |
| | 5,427 |
| Asset impairments | 201 |
| | 50 |
| | 573 |
| Gain on sales of assets and businesses | (27 | ) | | (56 | ) | | (3 | ) | Bargain purchase gain | — |
| | — |
| | (233 | ) | Gain on deconsolidation of business
| — |
| | — |
| | (213 | ) | Deferred income taxes and amortization of investment tax credits | 681 |
| | (108 | ) | | (362 | ) | Net fair value changes related to derivatives | 222 |
| | 294 |
| | 151 |
| Net realized and unrealized (gains) losses on NDT funds | (663 | ) | | 303 |
| | (616 | ) | Other non-cash operating activities | 613 |
| | 1,131 |
| | 728 |
| Changes in assets and liabilities: | | | | | | Accounts receivable | (243 | ) | | (565 | ) | | (470 | ) | Inventories | (87 | ) | | (37 | ) | | (72 | ) | Accounts payable and accrued expenses | (425 | ) | | 551 |
| | (388 | ) | Option premiums (paid) received, net | (29 | ) | | (43 | ) | | 28 |
| Collateral (posted) received, net | (438 | ) | | 82 |
| | (158 | ) | Income taxes | (64 | ) | | 340 |
| | 299 |
| Pension and non-pension postretirement benefit contributions | (408 | ) | | (383 | ) | | (405 | ) | Other assets and liabilities | (1,482 | ) | | (965 | ) | | (675 | ) | Net cash flows provided by operating activities | 6,659 |
|
| 8,644 |
|
| 7,480 |
| Cash flows from investing activities | | | | | | Capital expenditures | (7,248 | ) | | (7,594 | ) | | (7,584 | ) | Proceeds from NDT fund sales | 10,051 |
| | 8,762 |
| | 7,845 |
| Investment in NDT funds | (10,087 | ) | | (8,997 | ) | | (8,113 | ) | Reduction of restricted cash from deconsolidation of business | — |
| | — |
| | (87 | ) | Acquisitions of assets and businesses, net | (41 | ) | | (154 | ) | | (208 | ) | Proceeds from sales of assets and businesses | 53 |
| | 91 |
| | 219 |
| Other investing activities | 12 |
| | 58 |
| | (43 | ) | Net cash flows used in investing activities | (7,260 | ) |
| (7,834 | ) |
| (7,971 | ) | Cash flows from financing activities | | | | | | Changes in short-term borrowings | 781 |
| | (338 | ) | | (261 | ) | Proceeds from short-term borrowings with maturities greater than 90 days | — |
| | 126 |
| | 621 |
| Repayments on short-term borrowings with maturities greater than 90 days | (125 | ) | | (1 | ) | | (700 | ) | Issuance of long-term debt | 1,951 |
| | 3,115 |
| | 3,470 |
| Retirement of long-term debt | (1,287 | ) | | (1,786 | ) | | (2,490 | ) | Retirement of long-term debt to financing trust | — |
| | — |
| | (250 | ) | Common stock issued from treasury stock
| — |
| | — |
| | 1,150 |
| Dividends paid on common stock | (1,408 | ) | | (1,332 | ) | | (1,236 | ) | Proceeds from employee stock plans | 112 |
| | 105 |
| | 150 |
| Sale of noncontrolling interests | — |
| | — |
| | 396 |
| Other financing activities | (82 | ) | | (108 | ) | | (83 | ) | Net cash flows (used in) provided by financing activities | (58 | ) |
| (219 | ) |
| 767 |
| (Decrease) increase in cash, cash equivalents and restricted cash | (659 | ) | | 591 |
| | 276 |
| Cash, cash equivalents and restricted cash at beginning of period | 1,781 |
| | 1,190 |
| | 914 |
| Cash, cash equivalents and restricted cash at end of period | $ | 1,122 |
|
| $ | 1,781 |
|
| $ | 1,190 |
| | | | | | | Supplemental cash flow information | | | | | | (Decrease) increase in capital expenditures not paid | $ | (7 | ) | | $ | (69 | ) | | $ | 42 |
| Increase (decrease) in PPE related to ARO update | 968 |
| | (107 | ) | | 29 |
|
See the Combined Notes to Consolidated Financial Statements
179152
Exelon Corporation and Subsidiary Companies Consolidated Balance Sheets | | | | | | | | | | | | | December 31, | (In millions) | 2021 | | 2020 | ASSETS | | | | Current assets | | | | Cash and cash equivalents | $ | 1,182 | | | $ | 663 | | Restricted cash and cash equivalents | 393 | | | 438 | | | | | | Accounts receivable | | | | Customer accounts receivable | 3,913 | | 3,597 | Customer allowance for credit losses | (375) | | (366) | Customer accounts receivable, net | 3,538 | | | 3,231 | | Other accounts receivable | 1,664 | | 1,469 | Other allowance for credit losses | (76) | | (71) | Other accounts receivable, net | 1,588 | | | 1,398 | | Mark-to-market derivative assets | 2,169 | | | 644 | | | | | | Inventories, net | | | | Fossil fuel and emission allowances | 389 | | | 297 | | Materials and supplies | 1,480 | | | 1,425 | | | | | | Regulatory assets | 1,296 | | | 1,228 | | Renewable energy credits | 529 | | | 633 | | Assets held for sale | 13 | | | 958 | | Other | 1,380 | | | 1,647 | | Total current assets | 13,957 | | | 12,562 | | Property, plant, and equipment (net of accumulated depreciation and amortization of $30,318 and $26,727 as of December 31, 2021 and 2020, respectively) | 84,219 | | | 82,584 | | Deferred debits and other assets | | | | Regulatory assets | 8,224 | | | 8,759 | | Nuclear decommissioning trust funds | 15,938 | | | 14,464 | | Investments | 443 | | | 440 | | | | | | Goodwill | 6,677 | | | 6,677 | | Mark-to-market derivative assets | 949 | | | 555 | | | | | | | | | | Other | 2,606 | | | 3,276 | | Total deferred debits and other assets | 34,837 | | | 34,171 | | Total assets(a) | $ | 133,013 | | | $ | 129,317 | |
| | | | | | | | | | December 31, | (In millions) | 2019 | | 2018 | ASSETS | | | | Current assets | | | | Cash and cash equivalents | $ | 587 |
| | $ | 1,349 |
| Restricted cash and cash equivalents | 358 |
| | 247 |
| Accounts receivable, net | | | | Customer (net of allowance for uncollectible accounts of $243 and $283 as of December 31, 2019 and 2018, respectively)
| 4,592 |
| | 4,607 |
| Other (net of allowance for uncollectible accounts of $48 and $36 as of December 31, 2019 and 2018, respectively) | 1,583 |
| | 1,256 |
| Mark-to-market derivative assets | 679 |
| | 804 |
| Unamortized energy contract assets | 47 |
| | 48 |
| Inventories, net | | | | Fossil fuel and emission allowances | 312 |
| | 334 |
| Materials and supplies | 1,456 |
| | 1,351 |
| Regulatory assets | 1,170 |
| | 1,190 |
| Assets held for sale | — |
|
| 904 |
| Other | 1,253 |
| | 1,238 |
| Total current assets | 12,037 |
|
| 13,328 |
| Property, plant and equipment (net of accumulated depreciation and amortization of $23,979 and $22,902 as of December 31, 2019 and 2018, respectively) | 80,233 |
| | 76,707 |
| Deferred debits and other assets | | | | Regulatory assets | 8,335 |
| | 8,237 |
| Nuclear decommissioning trust funds | 13,190 |
| | 11,661 |
| Investments | 464 |
| | 625 |
| Goodwill | 6,677 |
| | 6,677 |
| Mark-to-market derivative assets | 508 |
| | 452 |
| Unamortized energy contract assets | 336 |
| | 372 |
| Other | 3,197 |
| | 1,575 |
| Total deferred debits and other assets | 32,707 |
|
| 29,599 |
| Total assets(a) | $ | 124,977 |
|
| $ | 119,634 |
|
See the Combined Notes to Consolidated Financial Statements
180153
Exelon Corporation and Subsidiary Companies Consolidated Balance Sheets | | | December 31, | | December 31, | (In millions) | 2019 | | 2018 | (In millions) | 2021 | | 2020 | LIABILITIES AND SHAREHOLDERS’ EQUITY | | | | LIABILITIES AND SHAREHOLDERS’ EQUITY | | | | Current liabilities | | | | Current liabilities | | Short-term borrowings | $ | 1,370 |
| | $ | 714 |
| Short-term borrowings | $ | 3,330 | | | $ | 2,031 | | Long-term debt due within one year | 4,710 |
| | 1,349 |
| Long-term debt due within one year | 3,373 | | | 1,819 | | Accounts payable | 3,560 |
| | 3,800 |
| Accounts payable | 4,136 | | | 3,562 | | Accrued expenses | 1,981 |
| | 2,112 |
| Accrued expenses | 1,955 | | | 2,078 | | Payables to affiliates | 5 |
| | 5 |
| Payables to affiliates | 5 | | | 5 | | | Regulatory liabilities | 406 |
| | 644 |
| Regulatory liabilities | 376 | | | 581 | | Mark-to-market derivative liabilities | 247 |
| | 475 |
| Mark-to-market derivative liabilities | 999 | | | 295 | | Unamortized energy contract liabilities | 132 |
| | 149 |
| Unamortized energy contract liabilities | 91 | | | 100 | | Renewable energy credit obligation | 443 |
| | 344 |
| Renewable energy credit obligation | 779 | | | 661 | | | Liabilities held for sale | — |
| | 777 |
| Liabilities held for sale | 3 | | | 375 | | Other | 1,331 |
| | 1,035 |
| Other | 1,064 | | | 1,264 | | Total current liabilities | 14,185 |
|
| 11,404 |
| Total current liabilities | 16,111 | | | 12,771 | | Long-term debt | 31,329 |
| | 34,075 |
| Long-term debt | 35,324 | | | 35,093 | | Long-term debt to financing trusts | 390 |
| | 390 |
| Long-term debt to financing trusts | 390 | | | 390 | | Deferred credits and other liabilities | | | | Deferred credits and other liabilities | | Deferred income taxes and unamortized investment tax credits | 12,351 |
| | 11,321 |
| Deferred income taxes and unamortized investment tax credits | 14,194 | | | 13,035 | | Asset retirement obligations | 10,846 |
| | 9,679 |
| Asset retirement obligations | 13,090 | | | 12,300 | | Pension obligations | 4,247 |
| | 3,988 |
| Pension obligations | 2,990 | | | 4,503 | | Non-pension postretirement benefit obligations | 2,076 |
| | 1,928 |
| Non-pension postretirement benefit obligations | 1,687 | | | 2,011 | | Spent nuclear fuel obligation | 1,199 |
| | 1,171 |
| Spent nuclear fuel obligation | 1,210 | | | 1,208 | | Regulatory liabilities | 9,986 |
| | 9,559 |
| Regulatory liabilities | 9,628 | | | 9,485 | | Mark-to-market derivative liabilities | 393 |
| | 479 |
| Mark-to-market derivative liabilities | 714 | | | 473 | | Unamortized energy contract liabilities | 338 |
| | 463 |
| Unamortized energy contract liabilities | 147 | | | 238 | | Other | 3,064 |
| | 2,130 |
| Other | 2,733 | | | 2,942 | | Total deferred credits and other liabilities | 44,500 |
|
| 40,718 |
| Total deferred credits and other liabilities | 46,393 | | | 46,195 | | Total liabilities(a) | 90,404 |
|
| 86,587 |
| Total liabilities(a) | 98,218 | | | 94,449 | | Commitments and contingencies |
| |
| Commitments and contingencies | 0 | | 0 | | Shareholders’ equity | | | | Shareholders’ equity | | Common stock (No par value, 2,000 shares authorized, 973 shares and 968 shares outstanding at December 31, 2019 and 2018, respectively) | 19,274 |
| | 19,116 |
| | Treasury stock, at cost (2 shares at December 31, 2019 and 2018) | (123 | ) | | (123 | ) | | Common stock (No par value, 2,000 shares authorized, 979 shares and 976 shares outstanding as of December 31, 2021 and 2020, respectively) | | Common stock (No par value, 2,000 shares authorized, 979 shares and 976 shares outstanding as of December 31, 2021 and 2020, respectively) | 20,324 | | | 19,373 | | Treasury stock, at cost (2 shares as of December 31, 2021 and 2020) | | Treasury stock, at cost (2 shares as of December 31, 2021 and 2020) | (123) | | | (123) | | Retained earnings | 16,267 |
| | 14,743 |
| Retained earnings | 16,942 | | | 16,735 | | Accumulated other comprehensive loss, net | (3,194 | ) | | (2,995 | ) | Accumulated other comprehensive loss, net | (2,750) | | | (3,400) | | Total shareholders’ equity | 32,224 |
|
| 30,741 |
| Total shareholders’ equity | 34,393 | | | 32,585 | | | Noncontrolling interests | 2,349 |
| | 2,306 |
| Noncontrolling interests | 402 | | | 2,283 | | Total equity | 34,573 |
|
| 33,047 |
| Total equity | 34,795 | | | 34,868 | | Total liabilities and shareholders' equity | $ | 124,977 |
|
| $ | 119,634 |
| Total liabilities and shareholders' equity | $ | 133,013 | | | $ | 129,317 | |
__________ | | (a) | Exelon’s consolidated assets include $9,532 million and $9,667 million at December 31, 2019 and 2018, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $3,473 million and $3,548 million at December 31, 2019 and 2018, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 22–Variable Interest Entities for additional information. |
(a)Exelon’s consolidated assets include $2,549 million and $10,200 million as of December 31, 2021 and 2020, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $1,077 million and $3,598 million as of December 31, 2021 and 2020, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 23–Variable Interest Entities for additional information.
See the Combined Notes to Consolidated Financial Statements
181154
Exelon Corporation and Subsidiary Companies Consolidated Statements of Changes in Equity | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Shareholders' Equity | | | | | (In millions, shares in thousands) | Issued Shares | | Common Stock | | Treasury Stock | | Retained Earnings | | Accumulated Other Comprehensive Loss | | Noncontrolling Interests | | Total Equity | Balance, December 31, 2016 | 958,778 |
| | $ | 18,794 |
| | $ | (2,327 | ) | | $ | 12,042 |
| | $ | (2,660 | ) | | $ | 1,780 |
| | $ | 27,629 |
| Net income | — |
| | — |
| | — |
| | 3,779 |
| | — |
| | 90 |
| | 3,869 |
| Long-term incentive plan activity | 5,066 |
| | 56 |
| | — |
| | — |
| | — |
| | — |
| | 56 |
| Employee stock purchase plan issuances | 1,324 |
| | 150 |
| | — |
| | — |
| | — |
| | — |
| | 150 |
| Common stock issued from treasury stock | — |
| | — |
| | 2,204 |
| | (1,054 | ) | | — |
| | — |
| | 1,150 |
| Sale of noncontrolling interests | — |
| | (36 | ) | | — |
| | — |
| | — |
| | 443 |
| | 407 |
| Changes in equity of noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | (20 | ) | | (20 | ) | Common stock dividends ($1.31/common share) | — |
| | — |
| | — |
| | (1,243 | ) | | — |
| | — |
| | (1,243 | ) | Other comprehensive income (loss), net of income taxes
| — |
| | — |
| | — |
| | — |
| | 173 |
| | (2 | ) | | 171 |
| Impact of adoption of Reclassification of Certain Tax Effects from AOCI standard | — |
| | — |
| | — |
| | 539 |
| | (539 | ) | | — |
| | — |
| Balance, December 31, 2017 | 965,168 |
|
| $ | 18,964 |
|
| $ | (123 | ) |
| $ | 14,063 |
|
| $ | (3,026 | ) |
| $ | 2,291 |
|
| $ | 32,169 |
| Net income | — |
| | — |
| | — |
| | 2,005 |
| | — |
| | 74 |
| | 2,079 |
| Long-term incentive plan activity | 3,534 |
| | 41 |
| | — |
| | — |
| | — |
| | — |
| | 41 |
| Employee stock purchase plan issuances | 1,318 |
| | 105 |
| | — |
| | — |
| | — |
| | — |
| | 105 |
| Sale of noncontrolling interests | — |
| | 6 |
| | — |
| | — |
| | — |
| | — |
| | 6 |
| Changes in equity of noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | (60 | ) | | (60 | ) | Common stock dividends ($1.38/common share) | — |
| | — |
| | — |
| | (1,339 | ) | | — |
| | — |
| | (1,339 | ) | Other comprehensive income, net of income taxes | — |
| | — |
| | — |
| | — |
| | 41 |
| | 1 |
| | 42 |
| Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard
| — |
| | — |
| | — |
| | 14 |
| | (10 | ) | | — |
| | 4 |
| Balance, December 31, 2018 | 970,020 |
|
| $ | 19,116 |
|
| $ | (123 | ) |
| $ | 14,743 |
|
| $ | (2,995 | ) |
| $ | 2,306 |
|
| $ | 33,047 |
| Net income | — |
| | — |
| | — |
| | 2,936 |
| | — |
| | 92 |
| | 3,028 |
| Long-term incentive plan activity | 3,111 |
| | 40 |
| | — |
| | — |
| | — |
| | — |
| | 40 |
| Employee stock purchase plan issuances | 1,285 |
| | 112 |
| | — |
| | — |
| | — |
| | — |
| | 112 |
| Sale of noncontrolling interests | — |
| | 6 |
| | — |
| | — |
| | — |
| | — |
| | 6 |
| Changes in equity of noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | (48 | ) | | (48 | ) | Common stock dividends ($1.45/common share)
| — |
| | — |
| | — |
| | (1,412 | ) | | — |
| | — |
| | (1,412 | ) | Other comprehensive income, net of income taxes | — |
| | — |
| | — |
| | — |
| | (199 | ) | | (1 | ) | | (200 | ) | Balance, December 31, 2019 | 974,416 |
|
| $ | 19,274 |
|
| $ | (123 | ) |
| $ | 16,267 |
|
| $ | (3,194 | ) |
| $ | 2,349 |
|
| $ | 34,573 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Shareholders' Equity | | | | | (In millions, shares in thousands) | Issued Shares | | Common Stock | | Treasury Stock | | Retained Earnings | | Accumulated Other Comprehensive Loss, net | | Noncontrolling Interests | | Total Equity | Balance, December 31, 2018 | 970,020 | | | $ | 19,116 | | | $ | (123) | | | $ | 14,743 | | | $ | (2,995) | | | $ | 2,306 | | | $ | 33,047 | | Net income | — | | | — | | | — | | | 2,936 | | | — | | | 92 | | | 3,028 | | Long-term incentive plan activity | 3,111 | | | 40 | | | — | | | — | | | — | | | — | | | 40 | | Employee stock purchase plan issuances | 1,285 | | | 112 | | | — | | | — | | | — | | | — | | | 112 | | Sale of noncontrolling interests | — | | | 6 | | | — | | | — | | | — | | | — | | | 6 | | Changes in equity of noncontrolling interests | — | | | — | | | — | | | — | | | — | | | (48) | | | (48) | | | | | | | | | | | | | | | | Common stock dividends ($1.45/common share) | — | | | — | | | — | | | (1,412) | | | — | | | — | | | (1,412) | | Other comprehensive loss, net of income taxes | — | | | — | | | — | | | — | | | (199) | | | (1) | | | (200) | | Balance, December 31, 2019 | 974,416 | | | $ | 19,274 | | | $ | (123) | | | $ | 16,267 | | | $ | (3,194) | | | $ | 2,349 | | | $ | 34,573 | | Net income (loss) | — | | | — | | | — | | | 1,963 | | | — | | | (9) | | | 1,954 | | Long-term incentive plan activity | 1,570 | | | 40 | | | — | | | — | | | — | | | — | | | 40 | | Employee stock purchase plan issuances | 1,480 | | | 56 | | | — | | | — | | | — | | | — | | | 56 | | Sale of noncontrolling interests | — | | | 3 | | | — | | | — | | | — | | | — | | | 3 | | Changes in equity of noncontrolling interests | — | | | — | | | — | | | — | | | — | | | (57) | | | (57) | | Common stock dividends ($1.53/common share) | — | | | — | | | — | | | (1,495) | | | — | | | — | | | (1,495) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Other comprehensive loss, net of income taxes | — | | | — | | | — | | | — | | | (206) | | | — | | | (206) | | Balance, December 31, 2020 | 977,466 | | | $ | 19,373 | | | $ | (123) | | | $ | 16,735 | | | $ | (3,400) | | | $ | 2,283 | | | $ | 34,868 | | Net income | — | | | — | | | — | | | 1,706 | | | — | | | 123 | | | 1,829 | | Long-term incentive plan activity | 1,734 | | | 69 | | | — | | | — | | | — | | | — | | | 69 | | Employee stock purchase plan issuances | 2,091 | | | 90 | | | — | | | — | | | — | | | — | | | 90 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Changes in equity of noncontrolling interests | — | | | — | | | — | | | — | | | — | | | (37) | | | (37) | | 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 ($1.53/common share) | — | | | — | | | — | | | (1,499) | | | — | | | — | | | (1,499) | | | | | | | | | | | | | | | | Acquisition of other noncontrolling interest | — | | | 2 | | | — | | | — | | | — | | | (2) | | | — | | Other comprehensive income, net of income taxes | — | | | — | | | — | | | — | | | 650 | | | — | | | 650 | | Balance, December 31, 2021 | 981,291 | | | $ | 20,324 | | | $ | (123) | | | $ | 16,942 | | | $ | (2,750) | | | $ | 402 | | | $ | 34,795 | |
See the Combined Notes to Consolidated Financial Statements
182155
Exelon Generation Company, LLC and Subsidiary Companies
Consolidated Statements of Operations and Comprehensive Income
| | | | | | | | | | | | | | For the Years Ended December 31, | (In millions) | 2019 | | 2018 | | 2017 | Operating revenues | | | | | | Operating revenues | $ | 17,752 |
| | $ | 19,169 |
| | $ | 17,385 |
| Operating revenues from affiliates | 1,172 |
| | 1,268 |
| | 1,115 |
| Total operating revenues | 18,924 |
|
| 20,437 |
|
| 18,500 |
| Operating expenses | | | | | | Purchased power and fuel | 10,849 |
| | 11,679 |
| | 9,671 |
| Purchased power and fuel from affiliates | 7 |
| | 14 |
| | 19 |
| Operating and maintenance | 4,131 |
| | 4,803 |
| | 5,602 |
| Operating and maintenance from affiliates | 587 |
| | 661 |
| | 697 |
| Depreciation and amortization | 1,535 |
| | 1,797 |
| | 1,457 |
| Taxes other than income taxes | 519 |
| | 556 |
| | 555 |
| Total operating expenses | 17,628 |
|
| 19,510 |
|
| 18,001 |
| Gain on sales of assets and businesses | 27 |
| | 48 |
| | 2 |
| Bargain purchase gain | — |
| | — |
| | 233 |
| Gain on deconsolidation of business | — |
| | — |
| | 213 |
| Operating income | 1,323 |
| | 975 |
| | 947 |
| Other income and (deductions) | | | | | | Interest expense, net | (394 | ) | | (396 | ) | | (401 | ) | Interest expense to affiliates | (35 | ) | | (36 | ) | | (39 | ) | Other, net | 1,023 |
| | (178 | ) | | 948 |
| Total other income and (deductions) | 594 |
|
| (610 | ) |
| 508 |
| Income before income taxes | 1,917 |
| | 365 |
| | 1,455 |
| Income taxes | 516 |
| | (108 | ) | | (1,376 | ) | Equity in losses of unconsolidated affiliates | (184 | ) | | (30 | ) | | (33 | ) | Net income | 1,217 |
|
| 443 |
|
| 2,798 |
| Net income attributable to noncontrolling interests | 92 |
| | 73 |
| | 88 |
| Net income attributable to membership interest | $ | 1,125 |
|
| $ | 370 |
|
| $ | 2,710 |
| Comprehensive income, net of income taxes | | | | | | Net income | $ | 1,217 |
| | $ | 443 |
| | $ | 2,798 |
| Other comprehensive income (loss), net of income taxes | | | | | | Unrealized gain on cash flow hedges | — |
| | 12 |
| | 3 |
| Unrealized gain on marketable securities | — |
| | — |
| | 1 |
| Unrealized gain on investments in unconsolidated affiliates | 1 |
| | 1 |
| | 4 |
| Unrealized gain (loss) on foreign currency translation | 6 |
| | (10 | ) | | 7 |
| Other comprehensive income | 7 |
|
| 3 |
|
| 15 |
| Comprehensive income | $ | 1,224 |
|
| $ | 446 |
|
| $ | 2,813 |
| Comprehensive income attributable to noncontrolling interests | 93 |
| | 74 |
| | 86 |
| Comprehensive income attributable to membership interest | $ | 1,131 |
| | $ | 372 |
| | $ | 2,727 |
|
See the Combined Notes to Consolidated Financial Statements
183
Exelon Generation Company, LLC and Subsidiary Companies
Consolidated Statements of Cash Flows | | | | | | | | | | | | | | For the Years Ended December 31, | (In millions) | 2019 | | 2018 | | 2017 | Cash flows from operating activities | | | | | | Net income | $ | 1,217 |
| | $ | 443 |
| | $ | 2,798 |
| Adjustments to reconcile net income to net cash flows provided by operating activities: | | | | | | Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization | 3,063 |
| | 3,415 |
| | 3,056 |
| Asset impairments | 201 |
| | 50 |
| | 510 |
| Gain on sales of assets and businesses | (27 | ) | | (48 | ) | | (2 | ) | Bargain purchase gain | — |
| | — |
| | (233 | ) | Gain on deconsolidation of business | — |
| | — |
| | (213 | ) | Deferred income taxes and amortization of investment tax credits | 361 |
| | (451 | ) | | (2,023 | ) | Net fair value changes related to derivatives | 228 |
| | 307 |
| | 167 |
| Net realized and unrealized (gains) losses on NDT fund investments | (663 | ) | | 303 |
| | (616 | ) | Other non-cash operating activities | (124 | ) | | 298 |
| | 112 |
| Changes in assets and liabilities: | | | | | | Accounts receivable | (186 | ) | | (359 | ) | | (320 | ) | Receivables from and payables to affiliates, net | (52 | ) | | 8 |
| | (7 | ) | Inventories | (47 | ) | | (12 | ) | | (29 | ) | Accounts payable and accrued expenses | (248 | ) | | 376 |
| | 4 |
| Option premiums (paid) received, net | (29 | ) | | (43 | ) | | 28 |
| Collateral (posted) received, net | (481 | ) | | 64 |
| | (129 | ) | Income taxes | 302 |
| | (193 | ) | | 496 |
| Pension and non-pension postretirement benefit contributions | (175 | ) | | (139 | ) | | (148 | ) | Other assets and liabilities | (467 | ) | | (158 | ) | | (152 | ) | Net cash flows provided by operating activities | 2,873 |
|
| 3,861 |
|
| 3,299 |
| Cash flows from investing activities | | | | | | Capital expenditures | (1,845 | ) | | (2,242 | ) | | (2,259 | ) | Proceeds from NDT fund sales | 10,051 |
| | 8,762 |
| | 7,845 |
| Investment in NDT funds | (10,087 | ) | | (8,997 | ) | | (8,113 | ) | Reduction of restricted cash from deconsolidation of business
| — |
| | — |
| | (87 | ) | Proceeds from sales of assets and businesses | 52 |
| | 90 |
| | 218 |
| Acquisitions of assets and businesses, net | (41 | ) | | (154 | ) | | (208 | ) | Other investing activities | 3 |
| | 10 |
| | (58 | ) | Net cash flows used in investing activities | (1,867 | ) |
| (2,531 | ) |
| (2,662 | ) | Cash flows from financing activities | | | | | | Change in short-term borrowings | 320 |
| | — |
| | (620 | ) | Proceeds from short-term borrowings with maturities greater than 90 days | — |
| | — |
| | 121 |
| Repayments of short-term borrowings with maturities greater than 90 days | — |
| | — |
| | (200 | ) | Issuance of long-term debt | 42 |
| | 15 |
| | 1,645 |
| Retirement of long-term debt | (813 | ) | | (141 | ) | | (1,261 | ) | Changes in Exelon intercompany money pool | (100 | ) | | 46 |
| | (1 | ) | Distributions to member | (899 | ) | | (1,001 | ) | | (659 | ) | Contributions from member | 41 |
| | 155 |
| | 102 |
| Sale of noncontrolling interests | — |
| | — |
| | 396 |
| Other financing activities | (51 | ) | | (55 | ) | | (54 | ) | Net cash flows used in financing activities | (1,460 | ) |
| (981 | ) |
| (531 | ) | (Decrease) increase in cash, cash equivalents and restricted cash | (454 | ) | | 349 |
| | 106 |
| Cash, cash equivalents and restricted cash at beginning of period | 903 |
| | 554 |
| | 448 |
| Cash, cash equivalents and restricted cash at end of period | $ | 449 |
|
| $ | 903 |
|
| $ | 554 |
| | | | | | | Supplemental cash flow information | | | | | | (Decrease) increase in capital expenditures not paid | $ | (34 | ) | | $ | (199 | ) | | $ | 73 |
| Increase (decrease) in PPE related to ARO update | 959 |
| | (130 | ) | | 29 |
|
See the Combined Notes to Consolidated Financial Statements
184
Exelon Generation Company, LLC and Subsidiary Companies
Consolidated Balance Sheets
| | | | | | | | | | December 31, | (In millions) | 2019 | | 2018 | ASSETS | | | | Current assets | | | | Cash and cash equivalents | $ | 303 |
| | $ | 750 |
| Restricted cash and cash equivalents | 146 |
| | 153 |
| Accounts receivable, net | | | | Customer (net of allowance for uncollectible accounts of $80 and $103 as of December 31, 2019 and 2018, respectively) | 2,893 |
| | 2,941 |
| Other (net of allowance for uncollectible accounts of $0 and $1 as of December 31, 2019 and 2018, respectively) | 619 |
| | 562 |
| Mark-to-market derivative assets | 675 |
| | 804 |
| Receivables from affiliates | 190 |
| | 173 |
| Unamortized energy contract assets | 47 |
| | 49 |
| Inventories, net | | | | Fossil fuel and emission allowances | 236 |
| | 251 |
| Materials and supplies | 1,026 |
| | 963 |
| Assets held for sale | — |
| | 904 |
| Other | 941 |
| | 883 |
| Total current assets | 7,076 |
|
| 8,433 |
| Property, plant and equipment (net of accumulated depreciation and amortization of $12,017 and $12,206 as of December 31, 2019 and 2018, respectively) | 24,193 |
| | 23,981 |
| Deferred debits and other assets | | | | Nuclear decommissioning trust funds | 13,190 |
| | 11,661 |
| Investments | 235 |
| | 414 |
| Goodwill | 47 |
| | 47 |
| Mark-to-market derivative assets | 508 |
| | 452 |
| Prepaid pension asset | 1,438 |
| | 1,421 |
| Unamortized energy contract assets | 336 |
| | 371 |
| Deferred income taxes | 12 |
| | 21 |
| Other | 1,960 |
| | 755 |
| Total deferred debits and other assets | 17,726 |
|
| 15,142 |
| Total assets(a) | $ | 48,995 |
|
| $ | 47,556 |
|
See the Combined Notes to Consolidated Financial Statements
185
Exelon Generation Company, LLC and Subsidiary Companies
Consolidated Balance Sheets
| | | | | | | | | | December 31, | (In millions) | 2019 | | 2018 | LIABILITIES AND EQUITY | | | | Current liabilities | | | | Short-term borrowings | $ | 320 |
| | $ | — |
| Long-term debt due within one year | 2,624 |
| | 906 |
| Long-term debt to affiliates due within one year | 558 |
| | — |
| Accounts payable | 1,692 |
| | 1,847 |
| Accrued expenses | 786 |
| | 898 |
| Payables to affiliates | 117 |
| | 139 |
| Borrowings from Exelon intercompany money pool | — |
| | 100 |
| Mark-to-market derivative liabilities | 215 |
| | 449 |
| Unamortized energy contract liabilities | 17 |
| | 31 |
| Renewable energy credit obligation | 443 |
| | 343 |
| Liabilities held for sale | — |
| | 777 |
| Other | 517 |
| | 279 |
| Total current liabilities | 7,289 |
|
| 5,769 |
| Long-term debt | 4,464 |
| | 6,989 |
| Long-term debt to affiliates | 328 |
| | 898 |
| Deferred credits and other liabilities | | | | Deferred income taxes and unamortized investment tax credits | 3,752 |
| | 3,383 |
| Asset retirement obligations | 10,603 |
| | 9,450 |
| Non-pension postretirement benefit obligations | 878 |
| | 900 |
| Spent nuclear fuel obligation | 1,199 |
| | 1,171 |
| Payables to affiliates | 3,103 |
| | 2,606 |
| Mark-to-market derivative liabilities | 123 |
| | 252 |
| Unamortized energy contract liabilities | 11 |
| | 20 |
| Other | 1,415 |
| | 610 |
| Total deferred credits and other liabilities | 21,084 |
|
| 18,392 |
| Total liabilities(a) | 33,165 |
|
| 32,048 |
| Commitments and contingencies |
| |
| Equity | | | | Member’s equity | | | | Membership interest | 9,566 |
| | 9,518 |
| Undistributed earnings | 3,950 |
| | 3,724 |
| Accumulated other comprehensive loss, net | (32 | ) | | (38 | ) | Total member’s equity | 13,484 |
|
| 13,204 |
| Noncontrolling interests | 2,346 |
| | 2,304 |
| Total equity | 15,830 |
|
| 15,508 |
| Total liabilities and equity | $ | 48,995 |
|
| $ | 47,556 |
|
__________
| | (a) | Generation’s consolidated assets include $9,512 million and $9,634 million at December 31, 2019 and 2018, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Generation’s consolidated liabilities include $3,429 million and $3,480 million at December 31, 2019 and 2018, respectively, of certain VIEs for which the VIE creditors do not have recourse to Generation. See Note 22–Variable Interest Entities for additional information. |
See the Combined Notes to Consolidated Financial Statements
186
Exelon Generation Company, LLC and Subsidiary Companies
Consolidated Statements of Changes in Equity
| | | | | | | | | | | | | | | | | | | | |
| Member’s Equity |
| Noncontrolling Interests |
| Total Equity | (In millions) | Membership Interest |
| Undistributed Earnings |
| Accumulated Other Comprehensive Loss, net |
| Balance, December 31, 2016 | $ | 9,261 |
| | $ | 2,298 |
| | $ | (54 | ) | | $ | 1,779 |
| | $ | 13,284 |
| Net income | — |
|
| 2,710 |
|
| — |
|
| 88 |
|
| 2,798 |
| Sale of noncontrolling interests | (36 | ) |
| — |
|
| — |
|
| 443 |
|
| 407 |
| Changes in equity of noncontrolling interests | — |
| | — |
| | — |
| | (18 | ) | | (18 | ) | Distribution of net retirement benefit obligation to member | 33 |
|
| — |
|
| — |
|
| — |
|
| 33 |
| Distributions to member | — |
| | (659 | ) | | — |
| | — |
| | (659 | ) | Contributions from member | 99 |
| | — |
| | — |
| | — |
| | 99 |
| Other comprehensive income (loss), net of income taxes | — |
|
| — |
|
| 17 |
|
| (2 | ) |
| 15 |
| Balance, December 31, 2017 | $ | 9,357 |
|
| $ | 4,349 |
|
| $ | (37 | ) |
| $ | 2,290 |
|
| $ | 15,959 |
| Net income | — |
|
| 370 |
|
| — |
|
| 73 |
|
| 443 |
| Sale of noncontrolling interests | 6 |
| | — |
| | — |
| | — |
| | 6 |
| Changes in equity of noncontrolling interests | — |
| | — |
| | — |
| | (60 | ) | | (60 | ) | Distributions to member | — |
|
| (1,001 | ) |
| — |
|
| — |
|
| (1,001 | ) | Contributions from member | 155 |
| | — |
| | — |
| | — |
| | 155 |
| Other comprehensive income, net of income taxes | — |
|
| — |
|
| 2 |
|
| 1 |
|
| 3 |
| Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard | — |
|
| 6 |
|
| (3 | ) |
| — |
|
| 3 |
| Balance, December 31, 2018 | $ | 9,518 |
|
| $ | 3,724 |
|
| $ | (38 | ) |
| $ | 2,304 |
|
| $ | 15,508 |
| Net income | — |
| | 1,125 |
| | — |
| | 92 |
| | 1,217 |
| Sale of noncontrolling interests | 7 |
| | — |
| | — |
| | — |
| | 7 |
| Changes in equity of noncontrolling interests | — |
| | — |
| | — |
| | (48 | ) | | (48 | ) | Distributions to member | — |
| | (899 | ) | | — |
| | — |
| | (899 | ) | Contributions from member | 41 |
| | — |
| | — |
| | — |
| | 41 |
| Other comprehensive income, net of income taxes | — |
| | — |
| | 6 |
| | (2 | ) | | 4 |
| Balance, December 31, 2019 | $ | 9,566 |
| | $ | 3,950 |
| | $ | (32 | ) | | $ | 2,346 |
| | $ | 15,830 |
|
See the Combined Notes to Consolidated Financial Statements
187
Commonwealth Edison Company and Subsidiary Companies Consolidated Statements of Operations and Comprehensive Income | | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | (In millions) | 2021 | | 2020 | | 2019 | Operating revenues | | | | | | Electric operating revenues | $ | 6,323 | | | $ | 5,914 | | | $ | 5,850 | | Revenues from alternative revenue programs | 42 | | | (47) | | | (133) | | Operating revenues from affiliates | 41 | | | 37 | | | 30 | | Total operating revenues | 6,406 | | | 5,904 | | | 5,747 | | Operating expenses | | | | | | Purchased power | 1,888 | | | 1,653 | | | 1,565 | | Purchased power from affiliates | 383 | | | 345 | | | 376 | | Operating and maintenance | 1,048 | | | 1,231 | | | 1,041 | | Operating and maintenance from affiliates | 307 | | | 289 | | | 264 | | Depreciation and amortization | 1,205 | | | 1,133 | | | 1,033 | | Taxes other than income taxes | 320 | | | 299 | | | 301 | | Total operating expenses | 5,151 | | | 4,950 | | | 4,580 | | Gain on sales of assets | — | | | — | | | 4 | | Operating income | 1,255 | | | 954 | | | 1,171 | | Other income and (deductions) | | | | | | Interest expense, net | (376) | | | (369) | | | (346) | | Interest expense to affiliates | (13) | | | (13) | | | (13) | | Other, net | 48 | | | 43 | | | 39 | | Total other income and (deductions) | (341) | | | (339) | | | (320) | | Income before income taxes | 914 | | | 615 | | | 851 | | Income taxes | 172 | | | 177 | | | 163 | | Net income | $ | 742 | | | $ | 438 | | | $ | 688 | | | | | | | | | | | | | | | | | | | | Comprehensive income | $ | 742 | | | $ | 438 | | | $ | 688 | |
| | | | | | | | | | | | | | For the Years Ended December 31, | (In millions) | 2019 | | 2018 | | 2017 | Operating revenues | | | | | | Electric operating revenues | $ | 5,850 |
| | $ | 5,884 |
| | $ | 5,478 |
| Revenues from alternative revenue programs | (133 | ) | | (29 | ) | | 43 |
| Operating revenues from affiliates | 30 |
| | 27 |
| | 15 |
| Total operating revenues | 5,747 |
| | 5,882 |
| | 5,536 |
| Operating expenses | | | | | | Purchased power | 1,565 |
| | 1,626 |
| | 1,533 |
| Purchased power from affiliates | 376 |
| | 529 |
| | 108 |
| Operating and maintenance | 1,041 |
| | 1,068 |
| | 1,157 |
| Operating and maintenance from affiliates | 264 |
| | 267 |
| | 270 |
| Depreciation and amortization | 1,033 |
| | 940 |
| | 850 |
| Taxes other than income taxes | 301 |
| | 311 |
| | 296 |
| Total operating expenses | 4,580 |
| | 4,741 |
| | 4,214 |
| Gain on sales of assets | 4 |
| | 5 |
| | 1 |
| Operating income | 1,171 |
| | 1,146 |
| | 1,323 |
| Other income and (deductions) | | | | | | Interest expense, net | (346 | ) | | (334 | ) | | (348 | ) | Interest expense to affiliates | (13 | ) | | (13 | ) | | (13 | ) | Other, net | 39 |
| | 33 |
| | 22 |
| Total other income and (deductions) | (320 | ) | | (314 | ) | | (339 | ) | Income before income taxes | 851 |
| | 832 |
| | 984 |
| Income taxes | 163 |
| | 168 |
| | 417 |
| Net income | $ | 688 |
| | $ | 664 |
| | $ | 567 |
| Comprehensive income | $ | 688 |
| | $ | 664 |
| | $ | 567 |
|
See the Combined Notes to Consolidated Financial Statements
188156
Commonwealth Edison Company and Subsidiary Companies Consolidated Statements of Cash Flows | | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | (In millions) | 2021 | | 2020 | | 2019 | Cash flows from operating activities | | | | | | Net income | $ | 742 | | | $ | 438 | | | $ | 688 | | Adjustments to reconcile net income to net cash flows provided by operating activities: | | | | | | Depreciation and amortization | 1,205 | | | 1,133 | | | 1,033 | | | | | | | | Deferred income taxes and amortization of investment tax credits | 244 | | | 228 | | | 109 | | Other non-cash operating activities | 126 | | | 202 | | | 265 | | Changes in assets and liabilities: | | | | | | Accounts receivable | (25) | | | (10) | | | (34) | | Receivables from and payables to affiliates, net | 32 | | | (1) | | | (12) | | Inventories | (2) | | | (13) | | | (16) | | Accounts payable and accrued expenses | — | | | 63 | | | (51) | | Collateral received, net | — | | | 14 | | | 48 | | Income taxes | — | | | 8 | | | 95 | | Pension and non-pension postretirement benefit contributions | (196) | | | (148) | | | (77) | | Other assets and liabilities | (531) | | | (590) | | | (345) | | Net cash flows provided by operating activities | 1,595 | | | 1,324 | | | 1,703 | | Cash flows from investing activities | | | | | | Capital expenditures | (2,387) | | | (2,217) | | | (1,915) | | | | | | | | | | | | | | Other investing activities | 26 | | | 2 | | | 29 | | Net cash flows used in investing activities | (2,361) | | | (2,215) | | | (1,886) | | Cash flows from financing activities | | | | | | Changes in short-term borrowings | (323) | | | 193 | | | 130 | | Issuance of long-term debt | 1,150 | | | 1,000 | | | 700 | | Retirement of long-term debt | (350) | | | (500) | | | (300) | | Dividends paid on common stock | (507) | | | (499) | | | (508) | | Contributions from parent | 791 | | | 712 | | | 250 | | Other financing activities | (16) | | | (13) | | | (16) | | Net cash flows provided by financing activities | 745 | | | 893 | | | 256 | | (Decrease) increase in cash, restricted cash, and cash equivalents | (21) | | | 2 | | | 73 | | Cash, restricted cash, and cash equivalents at beginning of period | 405 | | | 403 | | | 330 | | Cash, restricted cash, and cash equivalents at end of period | $ | 384 | | | $ | 405 | | | $ | 403 | | | | | | | | Supplemental cash flow information | | | | | | (Decrease) increase in capital expenditures not paid | $ | (46) | | | $ | 109 | | | $ | (37) | | | | | | | |
| | | | | | | | | | | | | | For the Years Ended December 31, | (In millions) | 2019 | | 2018 | | 2017 | Cash flows from operating activities | | | | | | Net income | $ | 688 |
| | $ | 664 |
| | $ | 567 |
| Adjustments to reconcile net income to net cash flows provided by operating activities: | | | | | | Depreciation, amortization and accretion | 1,033 |
| | 940 |
| | 850 |
| Deferred income taxes and amortization of investment tax credits | 109 |
| | 259 |
| | 659 |
| Other non-cash operating activities | 265 |
| | 242 |
| | 164 |
| Changes in assets and liabilities: | | | | | | Accounts receivable | (34 | ) | | (136 | ) | | (59 | ) | Receivables from and payables to affiliates, net | (12 | ) | | 26 |
| | 8 |
| Inventories | (16 | ) | | 1 |
| | 4 |
| Accounts payable and accrued expenses | (51 | ) | | 70 |
| | (297 | ) | Counterparty collateral received (posted), net and cash deposits | 48 |
| | 11 |
| | (26 | ) | Income taxes | 95 |
| | 62 |
| | (308 | ) | Pension and non-pension postretirement benefit contributions | (77 | ) | | (42 | ) | | (41 | ) | Other assets and liabilities | (345 | ) | | (348 | ) | | 6 |
| Net cash flows provided by operating activities | 1,703 |
| | 1,749 |
| | 1,527 |
| Cash flows from investing activities | | | | | | Capital expenditures | (1,915 | ) | | (2,126 | ) | | (2,250 | ) | Other investing activities | 29 |
| | 29 |
| | 20 |
| Net cash flows used in investing activities | (1,886 | ) | | (2,097 | ) | | (2,230 | ) | Cash flows from financing activities | | | | | | Changes in short-term borrowings | 130 |
| | — |
| | — |
| Issuance of long-term debt | 700 |
| | 1,350 |
| | 1,000 |
| Retirement of long-term debt | (300 | ) | | (840 | ) | | (425 | ) | Dividends paid on common stock | (508 | ) | | (459 | ) | | (422 | ) | Contributions from parent | 250 |
| | 500 |
| | 651 |
| Other financing activities | (16 | ) | | (17 | ) | | (15 | ) | Net cash flows provided by financing activities | 256 |
| | 534 |
| | 789 |
| Increase in cash, cash equivalents and restricted cash | 73 |
| | 186 |
| | 86 |
| Cash, cash equivalents and restricted cash at beginning of period | 330 |
| | 144 |
| | 58 |
| Cash, cash equivalents and restricted cash at end of period | $ | 403 |
| | $ | 330 |
| | $ | 144 |
| | | | | | | Supplemental cash flow information | | | | | | (Decrease) increase in capital expenditures not paid | $ | (37 | ) | | $ | 11 |
| | $ | (61 | ) | Increase in PPE related to ARO update | 7 |
| | 7 |
| | — |
|
See the Combined Notes to Consolidated Financial Statements
189157
Commonwealth Edison Company and Subsidiary Companies Consolidated Balance Sheets | | | | | | | | | | | | | December 31, | (In millions) | 2021 | | 2020 | ASSETS | | | | Current assets | | | | Cash and cash equivalents | $ | 131 | | | $ | 83 | | Restricted cash and cash equivalents | 210 | | | 279 | | Accounts receivable | | | | Customer accounts receivable | 647 | | 656 | Customer allowance for credit losses | (73) | | (97) | Customer accounts receivable, net | 574 | | | 559 | | Other accounts receivable | 227 | | 239 | Other allowance for credit losses | (17) | | (21) | Other accounts receivable, net | 210 | | | 218 | | Receivables from affiliates | 16 | | | 22 | | Inventories, net | 170 | | | 170 | | | | | | | | | | Regulatory assets | 335 | | | 279 | | Other | 76 | | | 49 | | Total current assets | 1,722 | | | 1,659 | | Property, plant, and equipment (net of accumulated depreciation and amortization of $6,099 and $5,672 as of December 31, 2021 and 2020, respectively) | 25,995 | | | 24,557 | | Deferred debits and other assets | | | | Regulatory assets | 1,870 | | | 1,749 | | Investments | 6 | | | 6 | | | | | | Goodwill | 2,625 | | | 2,625 | | Receivables from affiliates | 2,761 | | | 2,541 | | Prepaid pension asset | 1,086 | | | 1,022 | | Other | 405 | | | 307 | | Total deferred debits and other assets | 8,753 | | | 8,250 | | Total assets | $ | 36,470 | | | $ | 34,466 | |
| | | | | | | | | | December 31, | (In millions) | 2019 | | 2018 | ASSETS | | | | Current assets | | | | Cash and cash equivalents | $ | 90 |
| | $ | 135 |
| Restricted cash and cash equivalents | 150 |
| | 29 |
| Accounts receivable, net | | | | Customer (net of allowance for uncollectible accounts of $59 and $61 as of December 31, 2019 and December 31, 2018, respectively) | 545 |
| | 539 |
| Other (net of allowance for uncollectible accounts of $20 as of both December 31, 2019 and December 31, 2018, respectively) | 286 |
| | 320 |
| Receivables from affiliates | 28 |
| | 20 |
| Inventories, net | 159 |
| | 148 |
| Regulatory assets | 281 |
| | 293 |
| Other | 44 |
| | 86 |
| Total current assets | 1,583 |
| | 1,570 |
| Property, plant and equipment (net of accumulated depreciation and amortization of $5,168 and $4,684 as of December 31, 2019 and December 31, 2018, respectively)
| 23,107 |
| | 22,058 |
| Deferred debits and other assets | | | | Regulatory assets | 1,480 |
| | 1,307 |
| Investments | 6 |
| | 6 |
| Goodwill | 2,625 |
| | 2,625 |
| Receivables from affiliates | 2,622 |
| | 2,217 |
| Prepaid pension asset | 995 |
| | 1,035 |
| Other | 347 |
| | 395 |
| Total deferred debits and other assets | 8,075 |
| | 7,585 |
| Total assets | $ | 32,765 |
| | $ | 31,213 |
|
See the Combined Notes to Consolidated Financial Statements
190158
Commonwealth Edison Company and Subsidiary Companies Consolidated Balance Sheets | | | December 31, | | December 31, | (In millions) | 2019 | | 2018 | (In millions) | 2021 | | 2020 | LIABILITIES AND SHAREHOLDERS’ EQUITY | | | | LIABILITIES AND SHAREHOLDERS’ EQUITY | | | | Current liabilities | | | | Current liabilities | | Short-term borrowings | $ | 130 |
| | $ | — |
| Short-term borrowings | $ | — | | | $ | 323 | | Long-term debt due within one year | 500 |
| | 300 |
| Long-term debt due within one year | — | | | 350 | | Accounts payable | 527 |
| | 607 |
| Accounts payable | 647 | | | 683 | | Accrued expenses | 385 |
| | 373 |
| Accrued expenses | 384 | | | 390 | | Payables to affiliates | 103 |
| | 119 |
| Payables to affiliates | 121 | | | 96 | | Customer deposits | 118 |
| | 111 |
| Customer deposits | 99 | | | 86 | | Regulatory liabilities | 200 |
| | 293 |
| Regulatory liabilities | 185 | | | 289 | | Mark-to-market derivative liability | 32 |
| | 26 |
| | Mark-to-market derivative liabilities | | Mark-to-market derivative liabilities | 18 | | | 33 | | | Other | 122 |
| | 96 |
| Other | 133 | | | 143 | | Total current liabilities | 2,117 |
| | 1,925 |
| Total current liabilities | 1,587 | | | 2,393 | | Long-term debt | 7,991 |
| | 7,801 |
| Long-term debt | 9,773 | | | 8,633 | | Long-term debt to financing trust | 205 |
| | 205 |
| | Long-term debt to financing trusts | | Long-term debt to financing trusts | 205 | | | 205 | | Deferred credits and other liabilities | | | | Deferred credits and other liabilities | | Deferred income taxes and unamortized investment tax credits | 4,021 |
| | 3,813 |
| Deferred income taxes and unamortized investment tax credits | 4,685 | | | 4,341 | | Asset retirement obligations | 128 |
| | 118 |
| Asset retirement obligations | 144 | | | 126 | | Non-pension postretirement benefits obligations | 180 |
| | 201 |
| Non-pension postretirement benefits obligations | 169 | | | 173 | | Regulatory liabilities | 6,542 |
| | 6,050 |
| Regulatory liabilities | 6,759 | | | 6,403 | | Mark-to-market derivative liability | 269 |
| | 223 |
| | Mark-to-market derivative liabilities | | Mark-to-market derivative liabilities | 201 | | | 268 | | Other | 635 |
| | 630 |
| Other | 592 | | | 595 | | Total deferred credits and other liabilities | 11,775 |
| | 11,035 |
| Total deferred credits and other liabilities | 12,550 | | | 11,906 | | Total liabilities | 22,088 |
| | 20,966 |
| Total liabilities | 24,115 | | | 23,137 | | Commitments and contingencies |
| |
| Commitments and contingencies | 0 | | 0 | Shareholders’ equity | | | | Shareholders’ equity | | Common stock ($12.50 par value, 250 shares authorized, 127 shares outstanding at December 31, 2019 and 2018) | 1,588 |
| | 1,588 |
| | Common stock ($12.50 par value, 250 shares authorized, 127 shares outstanding as of December 31, 2021 and 2020) | | Common stock ($12.50 par value, 250 shares authorized, 127 shares outstanding as of December 31, 2021 and 2020) | 1,588 | | | 1,588 | | Other paid-in capital | 7,572 |
| | 7,322 |
| Other paid-in capital | 9,076 | | | 8,285 | | Retained deficit unappropriated | (1,639 | ) | | (1,639 | ) | Retained deficit unappropriated | (1,639) | | | (1,639) | | Retained earnings appropriated | 3,156 |
| | 2,976 |
| Retained earnings appropriated | 3,330 | | | 3,095 | | Total shareholders’ equity | 10,677 |
| | 10,247 |
| Total shareholders’ equity | 12,355 | | | 11,329 | | Total liabilities and shareholders’ equity | $ | 32,765 |
| | $ | 31,213 |
| Total liabilities and shareholders’ equity | $ | 36,470 | | | $ | 34,466 | |
See the Combined Notes to Consolidated Financial Statements
191159
Commonwealth Edison Company and Subsidiary Companies Consolidated Statements of Changes in Shareholders’ Equity | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (In millions) | Common Stock | | Other Paid-In Capital | | Retained Deficit Unappropriated | | Retained Earnings Appropriated | | Total Shareholders’ Equity | Balance, December 31, 2018 | $ | 1,588 | | | $ | 7,322 | | | $ | (1,639) | | | $ | 2,976 | | | $ | 10,247 | | Net income | — | | | — | | | 688 | | | — | | | 688 | | Appropriation of retained earnings for future dividends | — | | | — | | | (688) | | | 688 | | | — | | Common stock dividends | — | | | — | | | — | | | (508) | | | (508) | | Contributions from parent | — | | | 250 | | | — | | | — | | | 250 | | | | | | | | | | | | Balance, December 31, 2019 | $ | 1,588 | | | $ | 7,572 | | | $ | (1,639) | | | $ | 3,156 | | | $ | 10,677 | | Net income | — | | | — | | | 438 | | | — | | | 438 | | Appropriation of retained earnings for future dividends | — | | | — | | | (438) | | | 438 | | | — | | Common stock dividends | — | | | — | | | — | | | (499) | | | (499) | | Contributions from parent | — | | | 713 | | | — | | | — | | | 713 | | | | | | | | | | | | Balance, December 31, 2020 | $ | 1,588 | | | $ | 8,285 | | | $ | (1,639) | | | $ | 3,095 | | | $ | 11,329 | | Net income | — | | | — | | | 742 | | | — | | | 742 | | Appropriation of retained earnings for future dividends | — | | | — | | | (742) | | | 742 | | | — | | Common stock dividends | — | | | — | | | — | | | (507) | | | (507) | | Contributions from parent | — | | | 791 | | | — | | | — | | | 791 | | | | | | | | | | | | Balance, December 31, 2021 | $ | 1,588 | | | $ | 9,076 | | | $ | (1,639) | | | $ | 3,330 | | | $ | 12,355 | |
| | | | | | | | | | | | | | | | | | | | | (In millions) | Common Stock | | Other Paid-In Capital | | Retained Deficit Unappropriated | | Retained Earnings Appropriated | | Total Shareholders’ Equity | Balance, December 31, 2016 | $ | 1,588 |
| | $ | 6,150 |
| | $ | (1,639 | ) | | $ | 2,626 |
| | $ | 8,725 |
| Net income | — |
| | — |
| | 567 |
| | — |
| | 567 |
| Appropriation of retained earnings for future dividends | — |
| | — |
| | (567 | ) | | 567 |
| | — |
| Common stock dividends | — |
| | — |
| | — |
| | (422 | ) | | (422 | ) | Contributions from parent | — |
| | 651 |
| | — |
| | — |
| | 651 |
| Parent tax matter indemnification | — |
| | 21 |
| | — |
| | — |
| | 21 |
| Balance, December 31, 2017 | $ | 1,588 |
| | $ | 6,822 |
| | $ | (1,639 | ) | | $ | 2,771 |
| | $ | 9,542 |
| Net income | — |
| | — |
| | 664 |
| | — |
| | 664 |
| Appropriation of retained earnings for future dividends | — |
| | — |
| | (664 | ) | | 664 |
| | — |
| Common stock dividends | — |
| | — |
| | — |
| | (459 | ) | | (459 | ) | Contributions from parent | — |
| | 500 |
| | — |
| | — |
| | 500 |
| Balance, December 31, 2018 | $ | 1,588 |
| | $ | 7,322 |
| | $ | (1,639 | ) | | $ | 2,976 |
| | $ | 10,247 |
| Net income | — |
| | — |
| | 688 |
| | — |
| | 688 |
| Appropriation of retained earnings for future dividends | — |
| | — |
| | (688 | ) | | 688 |
| | — |
| Common stock dividends | — |
| | — |
| | — |
| | (508 | ) | | (508 | ) | Contributions from parent | — |
| | 250 |
| | — |
| | — |
| | 250 |
| Balance, December 31, 2019 | $ | 1,588 |
| | $ | 7,572 |
| | $ | (1,639 | ) | | $ | 3,156 |
| | $ | 10,677 |
|
See the Combined Notes to Consolidated Financial Statements
192160
PECO Energy Company and Subsidiary Companies Consolidated Statements of Operations and Comprehensive Income | | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | (In millions) | 2021 | | 2020 | | 2019 | Operating revenues | | | | | | Electric operating revenues | $ | 2,613 | | | $ | 2,519 | | | $ | 2,505 | | Natural gas operating revenues | 538 | | | 514 | | | 610 | | Revenues from alternative revenue programs | 26 | | | 16 | | | (21) | | Operating revenues from affiliates | 21 | | | 9 | | | 6 | | Total operating revenues | 3,198 | | | 3,058 | | | 3,100 | | Operating expenses | | | | | | Purchased power | 699 | | | 645 | | | 610 | | Purchased fuel | 188 | | | 185 | | | 262 | | Purchased power from affiliates | 194 | | | 188 | | | 157 | | Operating and maintenance | 757 | | | 816 | | | 707 | | Operating and maintenance from affiliates | 177 | | | 159 | | | 154 | | Depreciation and amortization | 348 | | | 347 | | | 333 | | Taxes other than income taxes | 184 | | | 172 | | | 165 | | Total operating expenses | 2,547 | | | 2,512 | | | 2,388 | | Gain on sales of assets | — | | | — | | | 1 | | Operating income | 651 | | | 546 | | | 713 | | Other income and (deductions) | | | | | | Interest expense, net | (149) | | | (136) | | | (124) | | Interest expense to affiliates, net | (12) | | | (11) | | | (12) | | Other, net | 26 | | | 18 | | | 16 | | Total other income and (deductions) | (135) | | | (129) | | | (120) | | Income before income taxes | 516 | | | 417 | | | 593 | | Income taxes | 12 | | | (30) | | | 65 | | | | | | | | | | | | | | Net income | $ | 504 | | | $ | 447 | | | $ | 528 | | Comprehensive income | $ | 504 | | | $ | 447 | | | $ | 528 | |
| | | | | | | | | | | | | | For the Years Ended December 31, | (In millions) | 2019 | | 2018 | | 2017 | Operating revenues | | | | | | Electric operating revenues | $ | 2,505 |
| | $ | 2,469 |
| | $ | 2,369 |
| Natural gas operating revenues | 610 |
| | 568 |
| | 494 |
| Revenues from alternative revenue programs | (21 | ) | | (7 | ) | | — |
| Operating revenues from affiliates | 6 |
| | 8 |
| | 7 |
| Total operating revenues | 3,100 |
|
| 3,038 |
|
| 2,870 |
| Operating expenses | | | | | | Purchased power | 610 |
| | 734 |
| | 648 |
| Purchased fuel | 262 |
| | 230 |
| | 186 |
| Purchased power from affiliates | 157 |
| | 126 |
| | 135 |
| Operating and maintenance | 707 |
| | 742 |
| | 657 |
| Operating and maintenance from affiliates | 154 |
| | 156 |
| | 149 |
| Depreciation and amortization | 333 |
| | 301 |
| | 286 |
| Taxes other than income taxes | 165 |
| | 163 |
| | 154 |
| Total operating expenses | 2,388 |
|
| 2,452 |
|
| 2,215 |
| Gain on sales of assets | 1 |
| | 1 |
| | — |
| Operating income | 713 |
|
| 587 |
|
| 655 |
| Other income and (deductions) | | | | | | Interest expense, net | (124 | ) | | (115 | ) | | (115 | ) | Interest expense to affiliates, net | (12 | ) | | (14 | ) | | (11 | ) | Other, net | 16 |
| | 8 |
| | 9 |
| Total other income and (deductions) | (120 | ) |
| (121 | ) |
| (117 | ) | Income before income taxes | 593 |
|
| 466 |
|
| 538 |
| Income taxes | 65 |
| | 6 |
| | 104 |
| Net income | $ | 528 |
|
| $ | 460 |
|
| $ | 434 |
| Comprehensive income | $ | 528 |
|
| $ | 460 |
|
| $ | 434 |
|
See the Combined Notes to Consolidated Financial Statements
193161
PECO Energy Company and Subsidiary Companies Consolidated Statements of Cash Flows | | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | (In millions) | 2021 | | 2020 | | 2019 | Cash flows from operating activities | | | | | | Net income | $ | 504 | | | $ | 447 | | | $ | 528 | | Adjustments to reconcile net income to net cash flows provided by operating activities: | | | | | | Depreciation and amortization | 348 | | | 347 | | | 333 | | | | | | | | | | | | | | Deferred income taxes and amortization of investment tax credits | 11 | | | (23) | | | 20 | | | | | | | | Other non-cash operating activities | — | | | 24 | | | 38 | | Changes in assets and liabilities: | | | | | | Accounts receivable | (35) | | | (88) | | | (29) | | Receivables from and payables to affiliates, net | 21 | | | (6) | | | (5) | | Inventories | (26) | | | (1) | | | 4 | | Accounts payable and accrued expenses | 15 | | | 63 | | | (11) | | | | | | | | Income taxes | 5 | | | 31 | | | (34) | | Pension and non-pension postretirement benefit contributions | (18) | | | (18) | | | (28) | | Other assets and liabilities | (52) | | | 1 | | | (65) | | Net cash flows provided by operating activities | 773 | | | 777 | | | 751 | | Cash flows from investing activities | | | | | | Capital expenditures | (1,240) | | | (1,147) | | | (939) | | Changes in Exelon intercompany money pool | — | | | 68 | | | (68) | | | | | | | | Other investing activities | 9 | | | 7 | | | (1) | | Net cash flows used in investing activities | (1,231) | | | (1,072) | | | (1,008) | | Cash flows from financing activities | | | | | | | | | | | | | | | | | | Issuance of long-term debt | 750 | | | 350 | | | 325 | | Retirement of long-term debt | (300) | | | — | | | — | | | | | | | | Changes in Exelon intercompany money pool | (40) | | | 40 | | | — | | | | | | | | Dividends paid on common stock | (339) | | | (340) | | | (358) | | Contributions from parent | 414 | | | 248 | | | 188 | | | | | | | | Other financing activities | (9) | | | (4) | | | (6) | | Net cash flows provided by financing activities | 476 | | | 294 | | | 149 | | Increase (decrease) in cash, restricted cash, and cash equivalents | 18 | | | (1) | | | (108) | | Cash, restricted cash, and cash equivalents at beginning of period | 26 | | | 27 | | | 135 | | Cash, restricted cash, and cash equivalents at end of period | $ | 44 | | | $ | 26 | | | $ | 27 | | | | | | | | Supplemental cash flow information | | | | | | Increase in capital expenditures not paid | $ | 26 | | | $ | 55 | | | $ | 40 | | | | | | | |
| | | | | | | | | | | | | | For the Years Ended December 31, | (In millions) | 2019 | | 2018 | | 2017 | Cash flows from operating activities | | | | | | Net income | $ | 528 |
| | $ | 460 |
| | $ | 434 |
| Adjustments to reconcile net income to net cash flows provided by operating activities: | | | | | | Depreciation, amortization and accretion | 333 |
| | 301 |
| | 286 |
| Gain on sale of assets | (1 | ) | | — |
| | — |
| Deferred income taxes and amortization of investment tax credits | 20 |
| | (5 | ) | | 19 |
| Other non-cash operating activities | 38 |
| | 51 |
| | 54 |
| Changes in assets and liabilities: | | | | | | Accounts receivable | (29 | ) | | (74 | ) | | (44 | ) | Receivables from and payables to affiliates, net | (5 | ) | | 7 |
| | (6 | ) | Inventories | 4 |
| | (14 | ) | | 1 |
| Accounts payable and accrued expenses | (11 | ) | | (3 | ) | | 6 |
| Income taxes | (34 | ) | | 15 |
| | 34 |
| Pension and non-pension postretirement benefit contributions | (28 | ) | | (28 | ) | | (24 | ) | Other assets and liabilities | (64 | ) | | 29 |
| | (5 | ) | Net cash flows provided by operating activities | 751 |
|
| 739 |
|
| 755 |
| Cash flows from investing activities | | | | | | Capital expenditures | (939 | ) | | (849 | ) | | (732 | ) | Changes in intercompany money pool | (68 | ) | | — |
| | 131 |
| Other investing activities | (1 | ) | | 9 |
| | 4 |
| Net cash flows used in investing activities | (1,008 | ) |
| (840 | ) |
| (597 | ) | Cash flows from financing activities | | | | | | Issuance of long-term debt | 325 |
| | 700 |
| | 325 |
| Retirement of long-term debt | — |
| | (500 | ) | | — |
| Dividends paid on common stock | (358 | ) | | (306 | ) | | (288 | ) | Contributions from parent | 188 |
| | 89 |
| | 16 |
| Other financing activities | (6 | ) | | (22 | ) | | (3 | ) | Net cash flows provided by (used in) financing activities | 149 |
|
| (39 | ) |
| 50 |
| (Decrease) increase in cash, cash equivalents and restricted cash
| (108 | ) | | (140 | ) | | 208 |
| Cash, cash equivalents and restricted cash at beginning of period | 135 |
| | 275 |
| | 67 |
| Cash, cash equivalents and restricted cash at end of period | $ | 27 |
|
| $ | 135 |
|
| $ | 275 |
| | | | | | | Supplemental cash flow information | | | | | | Increase (decrease) in capital expenditures not paid
| $ | 40 |
| | $ | (12 | ) | | $ | 22 |
|
See the Combined Notes to Consolidated Financial Statements
194162
PECO Energy Company and Subsidiary Companies Consolidated Balance Sheets | | | | | | | | | | | | | December 31, | (In millions) | 2021 | | 2020 | ASSETS | | | | Current assets | | | | Cash and cash equivalents | $ | 36 | | | $ | 19 | | Restricted cash and cash equivalents | 8 | | | 7 | | Accounts receivable | | | | Customer accounts receivable | 489 | | 511 | Customer allowance for credit losses | (105) | | (116) | Customer accounts receivable, net | 384 | | | 395 | | Other accounts receivable | 116 | | 130 | Other allowance for credit losses | (7) | | (8) | Other accounts receivable, net | 109 | | | 122 | | Receivables from affiliates | 1 | | | 2 | | | | | | Inventories, net | | | | Fossil fuel | 51 | | | 33 | | Materials and supplies | 45 | | | 38 | | | | | | | | | | Regulatory assets | 48 | | | 25 | | Other | 29 | | | 21 | | Total current assets | 711 | | | 662 | | Property, plant, and equipment (net of accumulated depreciation and amortization of $3,964 and $3,843 as of December 31, 2021 and 2020, respectively) | 11,117 | | | 10,181 | | Deferred debits and other assets | | | | Regulatory assets | 943 | | | 776 | | Investments | 34 | | | 30 | | Receivables from affiliates | 597 | | | 475 | | Prepaid pension asset | 386 | | | 375 | | Other | 36 | | | 32 | | Total deferred debits and other assets | 1,996 | | | 1,688 | | Total assets | $ | 13,824 | | | $ | 12,531 | |
| | | | | | | | | | December 31, | (In millions) | 2019 | | 2018 | ASSETS | | | | Current assets | | | | Cash and cash equivalents | $ | 21 |
| | $ | 130 |
| Restricted cash and cash equivalents | 6 |
| | 5 |
| Accounts receivable, net | | | | Customer (net of allowance for uncollectible accounts of $55 and $53 as of December 31, 2019 and 2018, respectively) | 357 |
| | 321 |
| Other (net of allowance for uncollectible accounts of $7 and $8 as of December 31, 2019 and 2018, respectively) | 138 |
| | 151 |
| Receivables from affiliates | 1 |
| | — |
| Receivable from Exelon intercompany pool | 68 |
| | — |
| Inventories, net | | | | Fossil fuel | 36 |
| | 38 |
| Materials and supplies | 35 |
| | 37 |
| Regulatory assets | 41 |
| | 81 |
| Other | 19 |
| | 19 |
| Total current assets | 722 |
|
| 782 |
| Property, plant and equipment (net of accumulated depreciation and amortization of $3,718 and $3,561 as of December 31, 2019 and 2018, respectively) | 9,292 |
| | 8,610 |
| Deferred debits and other assets | | | | Regulatory assets | 554 |
| | 460 |
| Investments | 27 |
| | 25 |
| Receivables from affiliates | 480 |
| | 389 |
| Prepaid pension asset | 365 |
| | 349 |
| Other | 29 |
| | 27 |
| Total deferred debits and other assets | 1,455 |
|
| 1,250 |
| Total assets | $ | 11,469 |
|
| $ | 10,642 |
|
See the Combined Notes to Consolidated Financial Statements
195163
PECO Energy Company and Subsidiary Companies Consolidated Balance Sheets | | | | | | | | | | | | | December 31, | (In millions) | 2021 | | 2020 | LIABILITIES AND SHAREHOLDER'S EQUITY | | | | Current liabilities | | | | | | | | Long-term debt due within one year | $ | 350 | | | $ | 300 | | Accounts payable | 494 | | | 479 | | Accrued expenses | 136 | | | 129 | | Payables to affiliates | 70 | | | 50 | | Borrowings from Exelon intercompany money pool | — | | | 40 | | Customer deposits | 48 | | | 59 | | Regulatory liabilities | 94 | | | 121 | | Other | 35 | | | 30 | | Total current liabilities | 1,227 | | | 1,208 | | Long-term debt | 3,847 | | | 3,453 | | Long-term debt to financing trusts | 184 | | | 184 | | Deferred credits and other liabilities | | | | Deferred income taxes and unamortized investment tax credits | 2,421 | | | 2,242 | | Asset retirement obligations | 29 | | | 29 | | Non-pension postretirement benefits obligations | 286 | | | 286 | | Regulatory liabilities | 635 | | | 503 | | Other | 83 | | | 93 | | Total deferred credits and other liabilities | 3,454 | | | 3,153 | | Total liabilities | 8,712 | | | 7,998 | | Commitments and contingencies | 0 | | 0 | | | | | Shareholder's equity | | | | Common stock (No par value, 500 shares authorized, 170 shares outstanding as of December 31, 2021 and 2020) | 3,428 | | | 3,014 | | Retained earnings | 1,684 | | | 1,519 | | | | | | Total shareholder's equity | 5,112 | | | 4,533 | | Total liabilities and shareholder's equity | $ | 13,824 | | | $ | 12,531 | |
| | | | | | | | | | December 31, | (In millions) | 2019 | | 2018 | LIABILITIES AND SHAREHOLDER'S EQUITY | | | | Current liabilities | | | | Accounts payable | $ | 387 |
| | $ | 370 |
| Accrued expenses | 101 |
| | 113 |
| Payables to affiliates | 55 |
| | 59 |
| Customer deposits | 69 |
| | 68 |
| Regulatory liabilities | 91 |
| | 175 |
| Other | 19 |
| | 24 |
| Total current liabilities | 722 |
|
| 809 |
| Long-term debt | 3,405 |
| | 3,084 |
| Long-term debt to financing trusts | 184 |
| | 184 |
| Deferred credits and other liabilities | | | | Deferred income taxes and unamortized investment tax credits | 2,080 |
| | 1,933 |
| Asset retirement obligations | 28 |
| | 27 |
| Non-pension postretirement benefits obligations | 288 |
| | 288 |
| Regulatory liabilities | 510 |
| | 421 |
| Other | 74 |
| | 76 |
| Total deferred credits and other liabilities | 2,980 |
|
| 2,745 |
| Total liabilities | 7,291 |
|
| 6,822 |
| Commitments and contingencies |
| |
| Shareholder's equity | | | | Common stock (No par value, 500 shares authorized, 170 shares outstanding at December 31, 2019 and 2018) | 2,766 |
| | 2,578 |
| Retained earnings | 1,412 |
| | 1,242 |
| Total shareholder's equity | 4,178 |
|
| 3,820 |
| Total liabilities and shareholder's equity | $ | 11,469 |
|
| $ | 10,642 |
|
See the Combined Notes to Consolidated Financial Statements
196164
PECO Energy Company and Subsidiary Companies Consolidated Statements of Changes in Shareholder's Equity | | | | | | | | | | | | | | | | | (In millions) | Common Stock | | Retained Earnings | | Accumulated Other Comprehensive Income | | Total Shareholder's Equity | Balance, December 31, 2016 | $ | 2,473 |
| | $ | 941 |
| | $ | 1 |
| | $ | 3,415 |
| Net income | — |
| | 434 |
| | — |
| | 434 |
| Common stock dividends | — |
| | (288 | ) | | — |
| | (288 | ) | Contributions from parent | 16 |
| | — |
| | — |
| | 16 |
| Balance, December 31, 2017 | $ | 2,489 |
|
| $ | 1,087 |
|
| $ | 1 |
|
| $ | 3,577 |
| Net income | — |
| | 460 |
| | — |
| | 460 |
| Common stock dividends | — |
| | (306 | ) | | — |
| | (306 | ) | Contributions from parent | 89 |
| | — |
| | — |
| | 89 |
| Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard | — |
| | 1 |
| | (1 | ) | | — |
| Balance, December 31, 2018 | $ | 2,578 |
|
| $ | 1,242 |
|
| $ | — |
|
| $ | 3,820 |
| Net income | — |
| | 528 |
| | — |
| | 528 |
| Common stock dividends | — |
| | (358 | ) | | — |
| | (358 | ) | Contributions from parent | 188 |
| | — |
| | — |
| | 188 |
| Balance, December 31, 2019 | $ | 2,766 |
|
| $ | 1,412 |
|
| $ | — |
|
| $ | 4,178 |
|
| | | | | | | | | | | | | | | | | | | | (In millions) | Common Stock | | Retained Earnings | | | | Total Shareholder's Equity | Balance, December 31, 2018 | $ | 2,578 | | | $ | 1,242 | | | | | $ | 3,820 | | Net income | — | | | 528 | | | | | 528 | | Common stock dividends | — | | | (358) | | | | | (358) | | Contributions from parent | 188 | | | — | | | | | 188 | | | | | | | | | | Balance, December 31, 2019 | $ | 2,766 | | | $ | 1,412 | | | | | $ | 4,178 | | Net income | — | | | 447 | | | | | 447 | | Common stock dividends | — | | | (340) | | | | | (340) | | Contributions from parent | 248 | | | — | | | | | 248 | | | | | | | | | | Balance, December 31, 2020 | $ | 3,014 | | | $ | 1,519 | | | | | $ | 4,533 | | Net income | — | | | 504 | | | | | 504 | | Common stock dividends | — | | | (339) | | | | | (339) | | | | | | | | | | | | | | | | | | Contributions from parent | 414 | | | — | | | | | 414 | | | | | | | | | | | | | | | | | | Balance, December 31, 2021 | $ | 3,428 | | | $ | 1,684 | | | | | $ | 5,112 | |
See the Combined Notes to Consolidated Financial Statements
197165
Baltimore Gas and Electric Company and Subsidiary Companies Consolidated Statements of Operations and Comprehensive Income
| | | | | | | | | | | | | | For the Years Ended December 31, | (In millions) | 2019 | | 2018 | | 2017 | Operating revenues | | | | | | Electric operating revenues | $ | 2,368 |
| | $ | 2,428 |
| | $ | 2,384 |
| Natural gas operating revenues | 700 |
| | 738 |
| | 652 |
| Revenues from alternative revenue programs | 12 |
| | (26 | ) | | 124 |
| Operating revenues from affiliates | 26 |
| | 29 |
| | 16 |
| Total operating revenues | 3,106 |
|
| 3,169 |
|
| 3,176 |
| Operating expenses | | | | | | Purchased power | 585 |
| | 671 |
| | 566 |
| Purchased fuel | 181 |
| | 254 |
| | 183 |
| Purchased power from affiliates | 286 |
| | 257 |
| | 384 |
| Operating and maintenance | 600 |
| | 615 |
| | 563 |
| Operating and maintenance from affiliates | 160 |
| | 162 |
| | 153 |
| Depreciation and amortization | 502 |
| | 483 |
| | 473 |
| Taxes other than income taxes | 260 |
| | 254 |
| | 240 |
| Total operating expenses | 2,574 |
|
| 2,696 |
|
| 2,562 |
| Gain on sales of assets | — |
| | 1 |
| | — |
| Operating income | 532 |
|
| 474 |
|
| 614 |
| Other income and (deductions) | | | | | | Interest expense, net | (121 | ) | | (106 | ) | | (95 | ) | Interest expense to affiliates | — |
| | — |
| | (10 | ) | Other, net | 28 |
| | 19 |
| | 16 |
| Total other income and (deductions) | (93 | ) |
| (87 | ) |
| (89 | ) | Income before income taxes | 439 |
| | 387 |
| | 525 |
| Income taxes | 79 |
| | 74 |
| | 218 |
| Net income | 360 |
|
| 313 |
|
| 307 |
| Comprehensive income | $ | 360 |
|
| $ | 313 |
|
| $ | 307 |
|
| | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | (In millions) | 2021 | | 2020 | | 2019 | Operating revenues | | | | | | Electric operating revenues | $ | 2,497 | | | $ | 2,323 | | | $ | 2,368 | | Natural gas operating revenues | 801 | | | 739 | | | 700 | | Revenues from alternative revenue programs | 12 | | | 16 | | | 12 | | Operating revenues from affiliates | 31 | | | 20 | | | 26 | | Total operating revenues | 3,341 | | | 3,098 | | | 3,106 | | Operating expenses | | | | | | Purchased power | 699 | | | 509 | | | 585 | | Purchased fuel | 243 | | | 171 | | | 181 | | Purchased power and fuel from affiliates | 233 | | | 311 | | | 286 | | Operating and maintenance | 618 | | | 617 | | | 600 | | Operating and maintenance from affiliates | 193 | | | 172 | | | 160 | | Depreciation and amortization | 591 | | | 550 | | | 502 | | Taxes other than income taxes | 283 | | | 268 | | | 260 | | Total operating expenses | 2,860 | | | 2,598 | | | 2,574 | | | | | | | | Operating income | 481 | | | 500 | | | 532 | | Other income and (deductions) | | | | | | Interest expense, net | (138) | | | (133) | | | (121) | | | | | | | | Other, net | 30 | | | 23 | | | 28 | | Total other income and (deductions) | (108) | | | (110) | | | (93) | | Income before income taxes | 373 | | | 390 | | | 439 | | Income taxes | (35) | | | 41 | | | 79 | | Net income | $ | 408 | | | $ | 349 | | | $ | 360 | | | | | | | | | | | | | | | | | | | | Comprehensive income | $ | 408 | | | $ | 349 | | | $ | 360 | | | | | | | | | | | | | |
See the Combined Notes to Consolidated Financial Statements
198166
Baltimore Gas and Electric Company and Subsidiary Companies Consolidated Statements of Cash Flows
| | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | (In millions) | 2021 | | 2020 | | 2019 | Cash flows from operating activities | | | | | | Net income | $ | 408 | | | $ | 349 | | | $ | 360 | | Adjustments to reconcile net income to net cash flows provided by operating activities: | | | | | | Depreciation and amortization | 591 | | | 550 | | | 502 | | | | | | | | | | | | | | Deferred income taxes and amortization of investment tax credits | (17) | | | 37 | | | 130 | | Other non-cash operating activities | 75 | | | 97 | | | 85 | | Changes in assets and liabilities: | | | | | | Accounts receivable | 30 | | | (165) | | | 25 | | Receivables from and payables to affiliates, net | (13) | | | (8) | | | 1 | | Inventories | (29) | | | 10 | | | (1) | | Accounts payable and accrued expenses | 14 | | | 102 | | | (43) | | | | | | | | Income taxes | 20 | | | 60 | | | (67) | | Pension and non-pension postretirement benefit contributions | (81) | | | (78) | | | (48) | | Other assets and liabilities | (269) | | | (70) | | | (196) | | Net cash flows provided by operating activities | 729 | | | 884 | | | 748 | | Cash flows from investing activities | | | | | | Capital expenditures | (1,226) | | | (1,247) | | | (1,145) | | | | | | | | Other investing activities | 18 | | | 2 | | | 8 | | Net cash flows used in investing activities | (1,208) | | | (1,245) | | | (1,137) | | Cash flows from financing activities | | | | | | Changes in short-term borrowings | 130 | | | (76) | | | 40 | | Issuance of long-term debt | 600 | | | 400 | | | 400 | | Retirement of long-term debt | (300) | | | — | | | — | | | | | | | | | | | | | | | | | | | | Dividends paid on common stock | (292) | | | (246) | | | (224) | | | | | | | | Contributions from parent | 257 | | | 411 | | | 193 | | Other financing activities | (6) | | | (8) | | | (8) | | Net cash flows provided by financing activities | 389 | | | 481 | | | 401 | | (Decrease) increase in cash, restricted cash, and cash equivalents | (90) | | | 120 | | | 12 | | Cash, restricted cash, and cash equivalents at beginning of period | 145 | | | 25 | | | 13 | | Cash, restricted cash, and cash equivalents at end of period | $ | 55 | | | $ | 145 | | | $ | 25 | | | | | | | | Supplemental cash flow information | | | | | | (Decrease) increase in capital expenditures not paid | $ | (59) | | | $ | 53 | | | $ | 6 | | | | | | | |
| | | | | | | | | | | | | | For the Years Ended December 31, | (In millions) | 2019 | | 2018 | | 2017 | Cash flows from operating activities | | | | | | Net income | $ | 360 |
| | $ | 313 |
| | $ | 307 |
| Adjustments to reconcile net income to net cash flows provided by operating activities: | | | | | | Depreciation and amortization | 502 |
| | 483 |
| | 473 |
| Impairment losses on long-lived assets and regulatory assets | — |
| | — |
| | 7 |
| Deferred income taxes and amortization of investment tax credits | 130 |
| | 76 |
| | 145 |
| Other non-cash operating activities | 85 |
| | 58 |
| | 65 |
| Changes in assets and liabilities: | | | | | | Accounts receivable | 25 |
| | 8 |
| | (5 | ) | Receivables from and payables to affiliates, net | 1 |
| | 12 |
| | (4 | ) | Inventories | (1 | ) | | 2 |
| | (9 | ) | Accounts payable and accrued expenses | (43 | ) | | (1 | ) | | (15 | ) | Collateral (posted) received, net | (4 | ) | | 4 |
| | — |
| Income taxes | (67 | ) | | (20 | ) | | 60 |
| Pension and non-pension postretirement benefit contributions | (48 | ) | | (54 | ) | | (53 | ) | Other assets and liabilities | (192 | ) | | (92 | ) | | (150 | ) | Net cash flows provided by operating activities | 748 |
|
| 789 |
|
| 821 |
| Cash flows from investing activities | | | | | | Capital expenditures | (1,145 | ) | | (959 | ) | | (882 | ) | Other investing activities | 8 |
| | 9 |
| | 7 |
| Net cash flows used in investing activities | (1,137 | ) |
| (950 | ) |
| (875 | ) | Cash flows from financing activities | | | | | | Changes in short-term borrowings | 40 |
| | (42 | ) | | 32 |
| Issuance of long-term debt | 400 |
| | 300 |
| | 300 |
| Retirement of long-term debt | — |
| | — |
| | (41 | ) | Retirement of long-term debt to financing trust | — |
| | — |
| | (250 | ) | Dividends paid on common stock | (224 | ) | | (209 | ) | | (198 | ) | Contributions from parent | 193 |
| | 109 |
| | 184 |
| Other financing activities | (8 | ) | | (2 | ) | | (5 | ) | Net cash flows provided by financing activities | 401 |
|
| 156 |
|
| 22 |
| Increase (Decrease) in cash, cash equivalents and restricted cash | 12 |
| | (5 | ) | | (32 | ) | Cash, cash equivalents and restricted cash at beginning of period | 13 |
| | 18 |
| | 50 |
| Cash, cash equivalents and restricted cash at end of period | $ | 25 |
|
| $ | 13 |
|
| $ | 18 |
| | | | | | | Supplemental cash flow information | | | | | | Increase in capital expenditures not paid | $ | 6 |
| | $ | 50 |
| | $ | 23 |
|
See the Combined Notes to Consolidated Financial Statements
199167
Baltimore Gas and Electric Company Balance Sheets | | | | | | | | | | | | | December 31, | (In millions) | 2021 | | 2020 | ASSETS | | | | Current assets | | | | Cash and cash equivalents | $ | 51 | | | $ | 144 | | Restricted cash and cash equivalents | 4 | | | 1 | | Accounts receivable | | | | Customer accounts receivable | 436 | | 487 | Customer allowance for credit losses | (38) | | (35) | Customer accounts receivable, net | 398 | | | 452 | | Other accounts receivable | 124 | | 117 | Other allowance for credit losses | (9) | | (9) | Other accounts receivable, net | 115 | | | 108 | | Receivables from affiliates | 1 | | | 3 | | Inventories, net | | | | Fossil fuel | 42 | | | 25 | | Materials and supplies | 53 | | | 41 | | | | | | Prepaid utility taxes | 49 | | | — | | Regulatory assets | 215 | | | 168 | | Other | 8 | | | 6 | | Total current assets | 936 | | | 948 | | Property, plant, and equipment (net of accumulated depreciation and amortization of $4,299 and $4,034 as of December 31, 2021 and 2020, respectively) | 10,577 | | | 9,872 | | Deferred debits and other assets | | | | Regulatory assets | 477 | | | 481 | | Investments | 14 | | | 10 | | | | | | Prepaid pension asset | 276 | | | 270 | | Other | 44 | | | 69 | | Total deferred debits and other assets | 811 | | | 830 | | Total assets | $ | 12,324 | | | $ | 11,650 | |
| | | | | | | | | | December 31, | (In millions) | 2019 |
| 2018 | ASSETS | | | | Current assets | | | | Cash and cash equivalents | $ | 24 |
| | $ | 7 |
| Restricted cash and cash equivalents | 1 |
| | 6 |
| Accounts receivable, net | | | | Customer (net of allowance for uncollectible accounts of $12 and $16 as of December 31, 2019 and 2018, respectively)
| 317 |
| | 353 |
| Other (net of allowance for uncollectible accounts of $5 and $4 as December 31, 2019 and 2018, respectively) | 147 |
| | 90 |
| Receivables from affiliates | 1 |
| | 1 |
| Inventories, net | | | | Gas held in storage | 30 |
| | 36 |
| Materials and supplies | 46 |
| | 39 |
| Prepaid utility taxes | 78 |
| | 74 |
| Regulatory assets | 183 |
| | 177 |
| Other | 6 |
| | 3 |
| Total current assets | 833 |
|
| 786 |
| Property, plant and equipment (net of accumulated depreciation and amortization of $3,834 and $3,633 as of December 31, 2019 and 2018, respectively) | 8,990 |
| | 8,243 |
| Deferred debits and other assets | | | | Regulatory assets | 454 |
| | 398 |
| Investments | 7 |
| | 5 |
| Prepaid pension asset | 264 |
| | 279 |
| Other | 86 |
| | 5 |
| Total deferred debits and other assets | 811 |
|
| 687 |
| Total assets | $ | 10,634 |
|
| $ | 9,716 |
|
See the Combined Notes to Consolidated Financial Statements
200168
Baltimore Gas and Electric Company Balance Sheets | | | | | | | | | | | | | December 31, | (In millions) | 2021 | | 2020 | LIABILITIES AND SHAREHOLDER'S EQUITY | | | | Current liabilities | | | | Short-term borrowings | $ | 130 | | | $ | — | | Long-term debt due within one year | 250 | | | 300 | | Accounts payable | 349 | | | 346 | | Accrued expenses | 176 | | | 205 | | | | | | Payables to affiliates | 48 | | | 61 | | Customer deposits | 97 | | | 110 | | Regulatory liabilities | 26 | | | 30 | | Other | 48 | | | 91 | | Total current liabilities | 1,124 | | | 1,143 | | Long-term debt | 3,711 | | | 3,364 | | | | | | Deferred credits and other liabilities | | | | Deferred income taxes and unamortized investment tax credits | 1,686 | | | 1,521 | | Asset retirement obligations | 26 | | | 23 | | Non-pension postretirement benefits obligations | 175 | | | 189 | | Regulatory liabilities | 934 | | | 1,109 | | Other | 98 | | | 104 | | Total deferred credits and other liabilities | 2,919 | | | 2,946 | | Total liabilities | 7,754 | | | 7,453 | | Commitments and contingencies | 0 | | 0 | Shareholder's equity | | | | Common stock (No par value, 0 shares(a) authorized, 0 shares(a) outstanding as of December 31, 2021 and 2020) | 2,575 | | | 2,318 | | Retained earnings | 1,995 | | | 1,879 | | | | | | Total shareholder's equity | 4,570 | | | 4,197 | | | | | | | | | | Total liabilities and shareholder's equity | $ | 12,324 | | | $ | 11,650 | |
| | | | | | | | | | December 31, | (In millions) | 2019 | | 2018 | LIABILITIES AND SHAREHOLDER'S EQUITY | | | | Current liabilities | | | | Short-term borrowings | $ | 76 |
| | $ | 35 |
| Accounts payable | 243 |
| | 295 |
| Accrued expenses | 152 |
| | 155 |
| Payables to affiliates | 66 |
| | 65 |
| Customer deposits | 120 |
| | 120 |
| Regulatory liabilities | 33 |
| | 77 |
| Other | 63 |
| | 27 |
| Total current liabilities | 753 |
|
| 774 |
| Long-term debt | 3,270 |
| | 2,876 |
| Deferred credits and other liabilities | | | | Deferred income taxes and unamortized investment tax credits | 1,396 |
| | 1,222 |
| Asset retirement obligations | 22 |
| | 24 |
| Non-pension postretirement benefits obligations | 199 |
| | 201 |
| Regulatory liabilities | 1,195 |
| | 1,192 |
| Other | 116 |
| | 73 |
| Total deferred credits and other liabilities | 2,928 |
|
| 2,712 |
| Total liabilities | 6,951 |
|
| 6,362 |
| Commitments and contingencies |
| |
| Shareholder's equity | | | | Common stock (No par value, 0 shares(a) authorized, 0 shares(a) outstanding at December 31, 2019 and 2018) | 1,907 |
| | 1,714 |
| Retained earnings | 1,776 |
| | 1,640 |
| Total shareholder's equity | 3,683 |
|
| 3,354 |
| Total liabilities and shareholder's equity | $ | 10,634 |
|
| $ | 9,716 |
|
_____________(a)In millions, shares round to zero. Number of shares is 1,500 authorized and 1,000 outstanding as of December 31, 2021 and 2020.
_____________
| | (a) | In millions, shares round to zero. Number of shares is 1,500 authorized and 1,000 outstanding at December 31, 2019 and 2018. |
See the Combined Notes to Consolidated Financial Statements
201169
Baltimore Gas and Electric Company and Subsidiary Companies Consolidated Statements of Changes in Shareholder's Equity
| | | | | | | | | | | | | | | | | | | | | | | | (In millions) | Common Stock | | Retained Earnings | | | | Total Shareholder's Equity | | | | | Balance, December 31, 2018 | $ | 1,714 | | | $ | 1,640 | | | | | $ | 3,354 | | | | | | Net income | — | | | 360 | | | | | 360 | | | | | | | | | | | | | | | | | | Common stock dividends | — | | | (224) | | | | | (224) | | | | | | | | | | | | | | | | | | Contributions from parent | 193 | | | — | | | | | 193 | | | | | | | | | | | | | | | | | | Balance, December 31, 2019 | $ | 1,907 | | | $ | 1,776 | | | | | $ | 3,683 | | | | | | Net income | — | | | 349 | | | | | 349 | | | | | | | | | | | | | | | | | | Common stock dividends | — | | | (246) | | | | | (246) | | | | | | | | | | | | | | | | | | Contributions from parent | 411 | | | — | | | | | 411 | | | | | | | | | | | | | | | | | | Balance, December 31, 2020 | $ | 2,318 | | | $ | 1,879 | | | | | $ | 4,197 | | | | | | Net income | — | | | 408 | | | | | 408 | | | | | | Common stock dividends | — | | | (292) | | | | | (292) | | | | | | | | | | | | | | | | | | Contributions from parent | 257 | | | — | | | | | 257 | | | | | | | | | | | | | | | | | | Balance, December 31, 2021 | $ | 2,575 | | | $ | 1,995 | | | | | $ | 4,570 | | | | | |
| | | | | | | | | | | | | (In millions) | Common Stock | | Retained Earnings | | Total Shareholder's Equity | Balance, December 31, 2016 | $ | 1,421 |
| | $ | 1,427 |
| | $ | 2,848 |
| Net income | — |
| | 307 |
| | 307 |
| Common stock dividends | — |
| | (198 | ) | | (198 | ) | Contributions from parent | 184 |
| | — |
| | 184 |
| Balance, December 31, 2017 | $ | 1,605 |
|
| $ | 1,536 |
|
| $ | 3,141 |
| Net income | — |
| | 313 |
| | 313 |
| Common stock dividends | — |
| | (209 | ) | | (209 | ) | Contributions from parent | 109 |
| | — |
| | 109 |
| Balance, December 31, 2018 | $ | 1,714 |
|
| $ | 1,640 |
|
| $ | 3,354 |
| Net income | — |
| | 360 |
| | 360 |
| Common stock dividends | — |
| | (224 | ) | | (224 | ) | Contributions from parent | 193 |
| | — |
| | 193 |
| Balance, December 31, 2019 | $ | 1,907 |
|
| $ | 1,776 |
|
| $ | 3,683 |
|
See the Combined Notes to Consolidated Financial Statements
202170
Pepco Holdings LLC and Subsidiary Companies Consolidated Statements of Operations and Comprehensive Income | | | | | | | | | | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | | | | (In millions) | 2021 | | 2020 | | 2019 | | | | Operating revenues | | | | | | | | | Electric operating revenues | $ | 4,769 | | | $ | 4,463 | | | $ | 4,639 | | | | | Natural gas operating revenues | 168 | | | 162 | | | 167 | | | | | Revenues from alternative revenue programs | 91 | | | 21 | | | (14) | | | | | Operating revenues from affiliates | 13 | | | 17 | | | 14 | | | | | Total operating revenues | 5,041 | | | 4,663 | | | 4,806 | | | | | Operating expenses | | | | | | | | | Purchased power | 1,417 | | | 1,279 | | | 1,371 | | | | | Purchased fuel | 73 | | | 69 | | | 75 | | | | | Purchased power from affiliates | 367 | | | 366 | | | 352 | | | | | Operating and maintenance | 925 | | | 940 | | | 939 | | | | | Operating and maintenance from affiliates | 179 | | | 159 | | | 143 | | | | | Depreciation and amortization | 821 | | | 782 | | | 754 | | | | | Taxes other than income taxes | 458 | | | 450 | | | 450 | | | | | | | | | | | | | | Total operating expenses | 4,240 | | | 4,045 | | | 4,084 | | | | | | | | | | | | | | Gain on sales of assets | — | | | 11 | | | — | | | | | Operating income | 801 | | | 629 | | | 722 | | | | | Other income and (deductions) | | | | | | | | | Interest expense, net | (267) | | | (268) | | | (263) | | | | | | | | | | | | | | Other, net | 69 | | | 57 | | | 55 | | | | | Total other income and (deductions) | (198) | | | (211) | | | (208) | | | | | Income before income taxes | 603 | | | 418 | | | 514 | | | | | Income taxes | 42 | | | (77) | | | 38 | | | | | Equity in earnings of unconsolidated affiliate | — | | | — | | | 1 | | | | | Net income | $ | 561 | | | $ | 495 | | | $ | 477 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Comprehensive income | $ | 561 | | | $ | 495 | | | $ | 477 | | | | |
| | | | | | | | | | | | | | For the Years Ended December 31, | (In millions) | 2019 | | 2018 | | 2017 | Operating revenues | | | | | | Electric operating revenues | $ | 4,639 |
| | $ | 4,609 |
| | $ | 4,428 |
| Natural gas operating revenues | 167 |
| | 181 |
| | 161 |
| Revenues from alternative revenue programs | (14 | ) | | (7 | ) | | 33 |
| Operating revenues from affiliates | 14 |
| | 15 |
| | 50 |
| Total operating revenues | 4,806 |
|
| 4,798 |
| | 4,672 |
| Operating expenses | | | | | | Purchased power | 1,371 |
| | 1,387 |
| | 1,182 |
| Purchased fuel | 75 |
| | 89 |
| | 71 |
| Purchased power from affiliates | 352 |
| | 355 |
| | 463 |
| Operating and maintenance | 939 |
| | 978 |
| | 918 |
| Operating and maintenance from affiliates | 143 |
| | 152 |
| | 150 |
| Depreciation, amortization and accretion | 754 |
| | 740 |
| | 675 |
| Taxes other than income taxes | 450 |
| | 455 |
| | 452 |
| Total operating expenses | 4,084 |
|
| 4,156 |
| | 3,911 |
| Gain on sales of assets | — |
| | 1 |
| | 1 |
| Operating income | 722 |
|
| 643 |
| | 762 |
| Other income and (deductions) | | | | | | Interest expense, net | (263 | ) | | (261 | ) | | (245 | ) | Other, net | 55 |
| | 43 |
| | 54 |
| Total other income and (deductions) | (208 | ) | | (218 | ) | | (191 | ) | Income before income taxes | 514 |
|
| 425 |
| | 571 |
| Income taxes | 38 |
| | 33 |
| | 217 |
| Equity in earnings of unconsolidated affiliates | 1 |
| | 1 |
| | 1 |
| Net income | 477 |
| | 393 |
| | 355 |
| Comprehensive income | $ | 477 |
| | $ | 393 |
| | $ | 355 |
|
See the Combined Notes to Consolidated Financial Statements
203171
Pepco Holdings LLC and Subsidiary Companies Consolidated Statements of Cash Flows | | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | (In millions) | 2021 | | 2020 | | 2019 | Cash flows from operating activities | | | | | | Net income | $ | 561 | | | $ | 495 | | | $ | 477 | | | | | | | | Adjustments to reconcile net income to net cash from operating activities: | | | | | | Depreciation and amortization | 821 | | | 782 | | | 754 | | | | | | | | | | | | | | Deferred income taxes and amortization of investment tax credits | 24 | | | (97) | | | (7) | | | | | | | | Other non-cash operating activities | (12) | | | 103 | | | 161 | | Changes in assets and liabilities: | | | | | | Accounts receivable | (48) | | | (159) | | | (39) | | Receivables from and payables to affiliates, net | 6 | | | 3 | | | 3 | | Inventories | (16) | | | (6) | | | (27) | | Accounts payable and accrued expenses | 34 | | | 49 | | | (17) | | | | | | | | | | | | | | Income taxes | 17 | | | (25) | | | 16 | | Pension and non-pension postretirement benefit contributions | (48) | | | (39) | | | (25) | | Other assets and liabilities | (182) | | | (104) | | | (179) | | Net cash flows provided by operating activities | 1,157 | | | 1,002 | | | 1,117 | | Cash flows from investing activities | | | | | | Capital expenditures | (1,720) | | | (1,604) | | | (1,355) | | | | | | | | | | | | | | | | | | | | | | | | | | Other investing activities | 2 | | | 7 | | | (3) | | Net cash flows used in investing activities | (1,718) | | | (1,597) | | | (1,358) | | Cash flows from financing activities | | | | | | Changes in short-term borrowings | 100 | | | 160 | | | 154 | | | | | | | | Repayments of short-term borrowings with maturities greater than 90 days | — | | | — | | | (125) | | Issuance of long-term debt | 825 | | | 602 | | | 485 | | Retirement of long-term debt | (260) | | | (128) | | | (157) | | Change in Exelon intercompany money pool | (14) | | | 9 | | | 12 | | | | | | | | | | | | | | | | | | | | Distributions to member | (703) | | | (553) | | | (526) | | Contributions from member | 683 | | | 494 | | | 398 | | | | | | | | | | | | | | | | | | | | Other financing activities | (17) | | | (10) | | | (5) | | Net cash flows provided by financing activities | 614 | | | 574 | | | 236 | | Increase (decrease) in cash, restricted cash, and cash equivalents | 53 | | | (21) | | | (5) | | Cash, restricted cash, and cash equivalents at beginning of period | 160 | | | 181 | | | 186 | | Cash, restricted cash, and cash equivalents at end of period | $ | 213 | | | $ | 160 | | | $ | 181 | | | | | | | | Supplemental cash flow information | | | | | | (Decrease) increase in capital expenditures not paid | $ | (6) | | | $ | 54 | | | $ | 2 | | | | | | | |
| | | | | | | | | | | | | | For the Years Ended December 31, | (In millions) | 2019 | | 2018 | | 2017 | Cash flows from operating activities | | | | | | Net income | $ | 477 |
| | $ | 393 |
| | $ | 355 |
| Adjustments to reconcile net income (loss) to net cash from operating activities: | | | | | | Depreciation and amortization | 754 |
| | 740 |
| | 675 |
| Impairment losses on intangibles and regulatory assets | — |
| | — |
| | 52 |
| Deferred income taxes and amortization of investment tax credits | (7 | ) | | 30 |
| | 252 |
| Other non-cash operating activities | 161 |
| | 150 |
| | 65 |
| Changes in assets and liabilities: | | | | | | Accounts receivable | (39 | ) | | (2 | ) | | (26 | ) | Receivables from and payables to affiliates, net | 3 |
| | 8 |
| | (2 | ) | Inventories | (27 | ) | | (14 | ) | | (37 | ) | Accounts payable and accrued expenses | (17 | ) | | 45 |
| | (106 | ) | Income taxes | 16 |
| | 34 |
| | 79 |
| Pension and non-pension postretirement benefit contributions | (25 | ) | | (74 | ) | | (99 | ) | Other assets and liabilities | (179 | ) | | (178 | ) | | (258 | ) | Net cash flows provided by operating activities | 1,117 |
| | 1,132 |
| | 950 |
| Cash flows from investing activities | | | | | | Capital expenditures | (1,355 | ) | | (1,375 | ) | | (1,396 | ) | Other investing activities | (3 | ) | | 4 |
| | (1 | ) | Net cash flows used in investing activities | (1,358 | ) | | (1,371 | ) | | (1,397 | ) | Cash flows from financing activities | | | | | | Changes in short-term borrowings | 154 |
| | (296 | ) | | 328 |
| Proceeds from short-term borrowings with maturities greater than 90 days | — |
| | 125 |
| | — |
| Repayments of short-term borrowings with maturities greater than 90 days | (125 | ) | | — |
| | (500 | ) | Issuance of long-term debt | 485 |
| | 750 |
| | 202 |
| Retirement of long-term debt | (157 | ) | | (299 | ) | | (169 | ) | Change in Exelon intercompany money pool | 12 |
| | — |
| | — |
| Distributions to member | (526 | ) | | (326 | ) | | (311 | ) | Contributions from member | 398 |
| | 385 |
| | 758 |
| Other financing activities | (5 | ) | | (9 | ) | | (2 | ) | Net cash flows provided by financing activities | 236 |
| | 330 |
| | 306 |
| (Decrease) increase in cash, cash equivalents and restricted cash | (5 | ) | | 91 |
|
| (141 | ) | Cash, cash equivalents and restricted cash at beginning of period | 186 |
| | 95 |
| | 236 |
| Cash, cash equivalents and restricted cash at end of period | $ | 181 |
| | $ | 186 |
|
| $ | 95 |
| | | | | | | Supplemental cash flow information | | | | | | Increase (decrease) in capital expenditures not paid | $ | 2 |
| | $ | 93 |
| | $ | (12 | ) |
See the Combined Notes to Consolidated Financial Statements
204172
Pepco Holdings LLC and Subsidiary Companies Consolidated Balance Sheets | | | | | | | | | | | | | December 31, | (In millions) | 2021 | | 2020 | ASSETS | | | | Current assets | | | | Cash and cash equivalents | $ | 136 | | | $ | 111 | | Restricted cash and cash equivalents | 77 | | | 39 | | Accounts receivable | | | | Customer accounts receivable | 616 | | 611 | Customer allowance for credit losses | (104) | | (86) | Customer accounts receivable, net | 512 | | | 525 | | Other accounts receivable | 283 | | 260 | Other allowance for credit losses | (39) | | (33) | Other accounts receivable, net | 244 | | | 227 | | | | | | Receivable from affiliates | 2 | | | 8 | | | | | | | | | | Inventories, net | | | | Fossil fuel | 11 | | | 6 | | Materials and supplies | 209 | | | 198 | | | | | | | | | | Regulatory assets | 432 | | | 440 | | | | | | Other | 69 | | | 45 | | Total current assets | 1,692 | | | 1,599 | | Property, plant, and equipment (net of accumulated depreciation and amortization of $2,108 and $1,811 as of December 31, 2021 and 2020, respectively) | 16,498 | | | 15,377 | | Deferred debits and other assets | | | | Regulatory assets | 1,794 | | | 1,933 | | Investments | 145 | | | 140 | | Goodwill | 4,005 | | | 4,005 | | | | | | | | | | Prepaid pension asset | 344 | | | 365 | | | | | | Deferred income taxes | 8 | | | 10 | | Other | 258 | | | 307 | | Total deferred debits and other assets | 6,554 | | | 6,760 | | Total assets(a) | $ | 24,744 | | | $ | 23,736 | |
| | | | | | | | | | December 31, | (In millions) | 2019 | | 2018 | ASSETS | | | | Current assets | | | | Cash and cash equivalents | $ | 131 |
| | $ | 124 |
| Restricted cash and cash equivalents | 36 |
| | 43 |
| Accounts receivable, net | | | | Customer (net of allowance for uncollectible accounts of $37 and $50 as of December 31, 2019 and 2018, respectively) | 479 |
| | 453 |
| Other (net of allowance for uncollectible accounts of $16 and $3 as of December 31, 2019 and 2018, respectively) | 174 |
| | 177 |
| Receivable from affiliates | 1 |
| | — |
| Inventories, net | | | | Fossil Fuel | 8 |
| | 9 |
| Materials and supplies | 190 |
| | 163 |
| Regulatory assets | 412 |
| | 457 |
| Other | 49 |
| | 75 |
| Total current assets | 1,480 |
| | 1,501 |
| Property, plant and equipment (net of accumulated depreciation and amortization of $1,213 and $841 as of December 31, 2019 and 2018, respectively) | 14,296 |
| | 13,446 |
| Deferred debits and other assets | | | | Regulatory assets | 2,061 |
| | 2,312 |
| Investments | 135 |
| | 130 |
| Goodwill | 4,005 |
| | 4,005 |
| Prepaid pension asset | 406 |
| | 486 |
| Deferred income taxes | 13 |
| | 12 |
| Other | 323 |
| | 60 |
| Total deferred debits and other assets | 6,943 |
| | 7,005 |
| Total assets(a) | $ | 22,719 |
| | $ | 21,952 |
|
See the Combined Notes to Consolidated Financial Statements
205173
Pepco Holdings LLC and Subsidiary Companies Consolidated Balance Sheets | | | December 31, | | December 31, | (In millions) | 2019 | | 2018 | (In millions) | 2021 | | 2020 | LIABILITIES AND EQUITY | | | | LIABILITIES AND EQUITY | | | | Current liabilities | | | | Current liabilities | | Short-term borrowings | $ | 208 |
| | $ | 179 |
| Short-term borrowings | $ | 468 | | | $ | 368 | | Long-term debt due within one year | 103 |
| | 125 |
| Long-term debt due within one year | 399 | | | 347 | | Accounts payable | 462 |
| | 496 |
| Accounts payable | 578 | | | 539 | | Accrued expenses | 296 |
| | 256 |
| Accrued expenses | 281 | | | 299 | | Payables to affiliates | 98 |
| | 94 |
| Payables to affiliates | 104 | | | 104 | | Borrowings from Exelon intercompany money pool | 12 |
| | — |
| Borrowings from Exelon intercompany money pool | 7 | | | 21 | | Customer deposits | 117 |
| | 116 |
| Customer deposits | 81 | | | 106 | | Regulatory liabilities | 70 |
| | 84 |
| Regulatory liabilities | 68 | | | 137 | | | Unamortized energy contract liabilities | 115 |
| | 119 |
| Unamortized energy contract liabilities | 89 | | | 92 | | | Other | 131 |
| | 123 |
| Other | 171 | | | 141 | | Total current liabilities | 1,612 |
| | 1,592 |
| Total current liabilities | 2,246 | | | 2,154 | | Long-term debt | 6,460 |
| | 6,134 |
| Long-term debt | 7,148 | | | 6,659 | | Deferred credits and other liabilities | | | | Deferred credits and other liabilities | | Deferred income taxes and unamortized investment tax credits | 2,278 |
| | 2,137 |
| Deferred income taxes and unamortized investment tax credits | 2,675 | | | 2,439 | | Asset retirement obligations | 57 |
| | 52 |
| Asset retirement obligations | 70 | | | 59 | | Non-pension postretirement benefit obligations | 93 |
| | 103 |
| Non-pension postretirement benefit obligations | 66 | | | 86 | | Regulatory liabilities | 1,707 |
| | 1,864 |
| Regulatory liabilities | 1,238 | | | 1,438 | | | Unamortized energy contract liabilities | 327 |
| | 442 |
| Unamortized energy contract liabilities | 146 | | | 235 | | Other | 577 |
| | 369 |
| Other | 570 | | | 622 | | Total deferred credits and other liabilities | 5,039 |
| | 4,967 |
| Total deferred credits and other liabilities | 4,765 | | | 4,879 | | Total liabilities(a) | 13,111 |
| | 12,693 |
| Total liabilities(a) | 14,159 | | | 13,692 | | Commitments and contingencies |
| |
| Commitments and contingencies | 0 | | 0 | | Member's equity | | | | Member's equity | | Membership interest | 9,618 |
| | 9,220 |
| Membership interest | 10,795 | | | 10,112 | | Undistributed (losses) gains | (10 | ) | | 39 |
| | | Undistributed losses | | Undistributed losses | (210) | | | (68) | | | Total member's equity | 9,608 |
| | 9,259 |
| Total member's equity | 10,585 | | | 10,044 | | Total liabilities and member's equity | $ | 22,719 |
| | $ | 21,952 |
| Total liabilities and member's equity | $ | 24,744 | | | $ | 23,736 | |
_____________ | | (a) | PHI’s consolidated total assets include $20 million and $33 million at December 31, 2019 and 2018, respectively, of PHI's consolidated VIE that can only be used to settle the liabilities of the VIE. PHI’s consolidated total liabilities include $44 million and $69 million at December 31, 2019 and 2018, respectively, of PHI's consolidated VIE for which the VIE creditors do not have recourse to PHI. See Note 22 - Variable Interest Entities for additional information. |
(a)PHI’s consolidated total assets include $0 million and $18 million as of December 31, 2021 and 2020, respectively, of PHI's consolidated VIE that can only be used to settle the liabilities of the VIE. PHI’s consolidated total liabilities include $0 million and $26 million as of December 31, 2021 and 2020, respectively, of PHI's consolidated VIE for which the VIE creditors do not have recourse to PHI. See Note 23 - Variable Interest Entities for additional information.
See the Combined Notes to Consolidated Financial Statements
206174
Pepco Holdings LLC and Subsidiary Companies Consolidated Statements of Changes in Equity | | | | | | | | | | | | | | | | | | | | (In millions) | Membership Interest | | Undistributed Gains/(Losses) | | | | Total Member's Equity | Balance, December 31, 2018 | $ | 9,220 | | | $ | 39 | | | | | $ | 9,259 | | Net income | — | | | 477 | | | | | 477 | | Distribution to member | — | | | (526) | | | | | (526) | | Contributions from member | 398 | | | — | | | | | 398 | | Balance, December 31, 2019 | $ | 9,618 | | | $ | (10) | | | | | $ | 9,608 | | Net Income | — | | | 495 | | | | | 495 | | Distribution to member | — | | | (553) | | | | | (553) | | Contributions from member | 494 | | | — | | | | | 494 | | Balance, December 31, 2020 | $ | 10,112 | | | $ | (68) | | | | | $ | 10,044 | | Net income | — | | | 561 | | | | | 561 | | Distribution to member | — | | | (703) | | | | | (703) | | Contributions from member | 683 | | | — | | | | | 683 | | Balance, December 31, 2021 | $ | 10,795 | | | $ | (210) | | | | | $ | 10,585 | |
| | | | | | | | | | | | | (In millions) | Membership Interest | | Undistributed (Losses)/Gains | | Total Member's Equity | Balance, December 31, 2016 | $ | 8,077 |
| | $ | (72 | ) | | $ | 8,005 |
| Net income | — |
| | 355 |
| | 355 |
| Distribution to member | — |
| | (311 | ) | | (311 | ) | Contributions from member | 758 |
| | — |
| | 758 |
| Balance, December 31, 2017 | $ | 8,835 |
|
| $ | (28 | ) |
| $ | 8,807 |
| Net Income | — |
| | 393 |
| | 393 |
| Distribution to member | — |
| | (326 | ) | | (326 | ) | Contributions from member | 385 |
| | — |
| | 385 |
| Balance, December 31, 2018 | $ | 9,220 |
|
| $ | 39 |
|
| $ | 9,259 |
| Net income | — |
| | 477 |
| | 477 |
| Distribution to member | — |
| | (526 | ) | | (526 | ) | Contributions from member | 398 |
| | — |
| | 398 |
| Balance, December 31, 2019 | $ | 9,618 |
|
| $ | (10 | ) |
| $ | 9,608 |
|
See the Combined Notes to Consolidated Financial Statements
207175
Potomac Electric Power Company Statements of Operations and Comprehensive Income | | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | (In millions) | 2021 | | 2020 | | 2019 | Operating revenues | | | | | | Electric operating revenues | $ | 2,216 | | | $ | 2,102 | | | $ | 2,258 | | Revenues from alternative revenue programs | 53 | | | 40 | | | (3) | | Operating revenues from affiliates | 5 | | | 7 | | | 5 | | Total operating revenues | 2,274 | | | 2,149 | | | 2,260 | | Operating expenses | | | | | | Purchased power | 353 | | | 324 | | | 401 | | Purchased power from affiliate | 271 | | | 278 | | | 264 | | Operating and maintenance | 258 | | | 248 | | | 273 | | Operating and maintenance from affiliates | 213 | | | 205 | | | 209 | | Depreciation and amortization | 403 | | | 377 | | | 374 | | Taxes other than income taxes | 373 | | | 367 | | | 378 | | Total operating expenses | 1,871 | | | 1,799 | | | 1,899 | | | | | | | | Gain on sales of assets | — | | | 9 | | | — | | | | | | | | Operating income | 403 | | | 359 | | | 361 | | Other income and (deductions) | | | | | | Interest expense, net | (140) | | | (138) | | | (133) | | | | | | | | Other, net | 48 | | | 38 | | | 31 | | Total other income and (deductions) | (92) | | | (100) | | | (102) | | Income before income taxes | 311 | | | 259 | | | 259 | | Income taxes | 15 | | | (7) | | | 16 | | | | | | | | Net income | $ | 296 | | | $ | 266 | | | $ | 243 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Comprehensive income | $ | 296 | | | $ | 266 | | | $ | 243 | |
| | | | | | | | | | | | | | For the Years Ended December 31, | (In millions) | 2019 | | 2018 | | 2017 | Operating revenues | | | | | | Electric operating revenues | $ | 2,258 |
| | $ | 2,233 |
| | $ | 2,126 |
| Revenues from alternative revenue programs | (3 | ) | | (7 | ) | | 19 |
| Operating revenues from affiliates | 5 |
| | 6 |
| | 6 |
| Total operating revenues | 2,260 |
| | 2,232 |
| | 2,151 |
| Operating expenses | | | | | | Purchased power | 401 |
| | 448 |
| | 359 |
| Purchased power from affiliates | 264 |
| | 206 |
| | 255 |
| Operating and maintenance | 273 |
| | 275 |
| | 396 |
| Operating and maintenance from affiliates | 209 |
| | 226 |
| | 58 |
| Depreciation and amortization | 374 |
| | 385 |
| | 321 |
| Taxes other than income taxes | 378 |
| | 379 |
| | 371 |
| Total operating expenses | 1,899 |
| | 1,919 |
| | 1,760 |
| Gain on sales of assets | — |
| | — |
| | 1 |
| Operating income | 361 |
| | 313 |
| | 392 |
| Other income and (deductions) | | | | | | Interest expense, net | (133 | ) | | (128 | ) | | (121 | ) | Other, net | 31 |
| | 31 |
| | 32 |
| Total other income and (deductions) | (102 | ) | | (97 | ) | | (89 | ) | Income before income taxes | 259 |
| | 216 |
| | 303 |
| Income taxes | 16 |
| | 11 |
| | 105 |
| Net income | $ | 243 |
| | $ | 205 |
| | $ | 198 |
| Comprehensive income | $ | 243 |
| | $ | 205 |
| | $ | 198 |
|
See the Combined Notes to Consolidated Financial Statements
208176
Potomac Electric Power Company Statements of Cash Flows | | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | (In millions) | 2021 | | 2020 | | 2019 | Cash flows from operating activities | | | | | | Net income | $ | 296 | | | $ | 266 | | | $ | 243 | | Adjustments to reconcile net income to net cash flows provided by operating activities: | | | | | | Depreciation and amortization | 403 | | | 377 | | | 374 | | | | | | | | | | | | | | Deferred income taxes and amortization of investment tax credits | (8) | | | (46) | | | 1 | | Other non-cash operating activities | (52) | | | (23) | | | 56 | | Changes in assets and liabilities: | | | | | | Accounts receivable | (28) | | | (67) | | | (22) | | Receivables from and payables to affiliates, net | 6 | | | (12) | | | 5 | | Inventories | (8) | | | 1 | | | (19) | | Accounts payable and accrued expenses | 16 | | | 41 | | | (39) | | | | | | | | Income taxes | 11 | | | (1) | | | 9 | | Pension and non-pension postretirement benefit contributions | (11) | | | (11) | | | (14) | | Other assets and liabilities | (163) | | | (24) | | | (82) | | Net cash flows provided by operating activities | 462 | | | 501 | | | 512 | | Cash flows from investing activities | | | | | | Capital expenditures | (843) | | | (773) | | | (626) | | | | | | | | | | | | | | | | | | | | Other investing activities | (1) | | | — | | | 3 | | Net cash flows used in investing activities | (844) | | | (773) | | | (623) | | Cash flows from financing activities | | | | | | Changes in short-term borrowings | 140 | | | (47) | | | 42 | | Issuance of long-term debt | 275 | | | 300 | | | 260 | | Retirement of long-term debt | — | | | (3) | | | (125) | | Dividends paid on common stock | (268) | | | (232) | | | (213) | | Contributions from parent | 244 | | | 262 | | | 160 | | Other financing activities | (6) | | | (6) | | | (3) | | Net cash flows provided by financing activities | 385 | | | 274 | | | 121 | | Increase in cash, restricted cash, and cash equivalents | 3 | | | 2 | | | 10 | | Cash, restricted cash, and cash equivalents at beginning of period | 65 | | | 63 | | | 53 | | Cash, restricted cash, and cash equivalents at end of period | $ | 68 | | | $ | 65 | | | $ | 63 | | | | | | | | Supplemental cash flow information | | | | | | Increase in capital expenditures not paid | $ | 30 | | | $ | 1 | | | $ | 39 | | | | | | | |
| | | | | | | | | | | | | | For the Years Ended December 31, | (In millions) | 2019 | | 2018 | | 2017 | Cash flows from operating activities | | | | | | Net income | $ | 243 |
| | $ | 205 |
| | $ | 198 |
| Adjustments to reconcile net income to net cash flows provided by operating activities: | | | | | | Depreciation and amortization | 374 |
| | 385 |
| | 321 |
| Impairment losses on regulatory assets | — |
| | — |
| | 14 |
| Deferred income taxes and amortization of investment tax credits | 1 |
| | (20 | ) | | 113 |
| Other non-cash operating activities | 56 |
| | 67 |
| | 1 |
| Changes in assets and liabilities: | | | | | | Accounts receivable | (22 | ) | | (5 | ) | | (20 | ) | Receivables from and payables to affiliates, net | 5 |
| | (17 | ) | | — |
| Inventories | (19 | ) | | (6 | ) | | (24 | ) | Accounts payable and accrued expenses | (39 | ) | | 59 |
| | (63 | ) | Income taxes | 9 |
| | (13 | ) | | 81 |
| Pension and non-pension postretirement benefit contributions | (14 | ) | | (17 | ) | | (72 | ) | Other assets and liabilities | (82 | ) | | (164 | ) | | (142 | ) | Net cash flows provided by operating activities | 512 |
| | 474 |
| | 407 |
| Cash flows from investing activities | | | | | | Capital expenditures | (626 | ) | | (656 | ) | | (628 | ) | Other investing activities | 3 |
| | 2 |
| | — |
| Net cash flows used in investing activities | (623 | ) | | (654 | ) | | (628 | ) | Cash flows from financing activities | | | | | | Changes in short-term borrowings | 42 |
| | 14 |
| | 3 |
| Issuance of long-term debt | 260 |
| | 200 |
| | 202 |
| Retirement of long-term debt | (125 | ) | | (14 | ) | | (13 | ) | Dividends paid on common stock | (213 | ) | | (169 | ) | | (133 | ) | Contributions from parent | 160 |
| | 166 |
| | 161 |
| Other financing activities | (3 | ) | | (4 | ) | | (1 | ) | Net cash flows provided by financing activities | 121 |
| | 193 |
| | 219 |
| Increase (decrease) in cash, cash equivalents and restricted cash | 10 |
| | 13 |
| | (2 | ) | Cash, cash equivalents and restricted cash at beginning of period | 53 |
| | 40 |
| | 42 |
| Cash, cash equivalents and restricted cash at end of period | $ | 63 |
| | $ | 53 |
| | $ | 40 |
| | | | | | | Supplemental cash flow information | | | | | | Increase in capital expenditures not paid | $ | 39 |
| | $ | 20 |
| | $ | 5 |
|
See the Combined Notes to Consolidated Financial Statements
209177
Potomac Electric Power Company Balance Sheets | | | | | | | | | | | | | December 31, | (In millions) | 2021 | | 2020 | ASSETS | | | | Current assets | | | | Cash and cash equivalents | $ | 34 | | | $ | 30 | | Restricted cash and cash equivalents | 34 | | | 35 | | Accounts receivable | | | | Customer accounts receivable | 277 | | 279 | Customer allowance for credit losses | (37) | | (32) | Customer accounts receivable, net | 240 | | | 247 | | Other accounts receivable | 160 | | 131 | Other allowance for credit losses | (16) | | (13) | Other accounts receivable, net | 144 | | | 118 | | | | | | Receivables from affiliates | — | | | 2 | | | | | | | | | | Inventories, net | 119 | | | 111 | | Regulatory assets | 213 | | | 214 | | | | | | Other | 25 | | | 13 | | Total current assets | 809 | | | 770 | | Property, plant, and equipment (net of accumulated depreciation and amortization of $3,875 and $3,697 as of December 31, 2021 and 2020, respectively) | 8,104 | | | 7,456 | | Deferred debits and other assets | | | | Regulatory assets | 532 | | | 570 | | Investments | 120 | | | 115 | | | | | | Prepaid pension asset | 279 | | | 284 | | Other | 59 | | | 69 | | Total deferred debits and other assets | 990 | | | 1,038 | | Total assets | $ | 9,903 | | | $ | 9,264 | |
| | | | | | | | | | December 31, | (In millions) | 2019 | | 2018 | ASSETS | | | | Current assets | | | | Cash and cash equivalents | $ | 30 |
| | $ | 16 |
| Restricted cash and cash equivalents | 33 |
| | 37 |
| Accounts receivable, net | | | | Customer (net of allowance for uncollectible accounts of $13 and $20 as of December 31, 2019 and 2018, respectively) | 231 |
| | 225 |
| Other (net of allowance for uncollectible accounts of $7 and $1 as of December 31, 2019 and 2018, respectively) | 91 |
| | 81 |
| Receivables from affiliates | — |
| | 1 |
| Inventories, net | 112 |
| | 93 |
| Regulatory assets | 188 |
| | 238 |
| Other | 11 |
| | 37 |
| Total current assets | 696 |
| | 728 |
| Property, plant and equipment (net of accumulated depreciation and amortization of $3,517 and $3,354 as of December 31, 2019 and 2018, respectively) | 6,909 |
| | 6,460 |
| Deferred debits and other assets | | | | Regulatory assets | 584 |
| | 643 |
| Investments | 110 |
| | 105 |
| Prepaid pension asset | 296 |
| | 316 |
| Other | 66 |
| | 15 |
| Total deferred debits and other assets | 1,056 |
|
| 1,079 |
| Total assets | $ | 8,661 |
| | $ | 8,267 |
|
See the Combined Notes to Consolidated Financial Statements
210178
Potomac Electric Power Company Balance Sheets | | | December 31, | | December 31, | (In millions) | 2019 | | 2018 | (In millions) | 2021 | | 2020 | LIABILITIES AND SHAREHOLDER'S EQUITY | | | | LIABILITIES AND SHAREHOLDER'S EQUITY | | | | Current liabilities | | | | Current liabilities | | Short-term borrowings | $ | 82 |
| | $ | 40 |
| Short-term borrowings | $ | 175 | | | $ | 35 | | Long-term debt due within one year | 2 |
| | 15 |
| Long-term debt due within one year | 313 | | | 3 | | Accounts payable | 195 |
| | 214 |
| Accounts payable | 272 | | | 226 | | Accrued expenses | 156 |
| | 126 |
| Accrued expenses | 160 | | | 164 | | Payables to affiliates | 66 |
| | 62 |
| Payables to affiliates | 59 | | | 55 | | | Customer deposits | 57 |
| | 54 |
| Customer deposits | 35 | | | 51 | | Regulatory liabilities | 8 |
| | 7 |
| Regulatory liabilities | 14 | | | 46 | | | Merger related obligation | 39 |
| | 38 |
| Merger related obligation | 27 | | | 33 | | Current portion of DC PLUG obligation | 30 |
| | 30 |
| | | Other | 22 |
| | 42 |
| Other | 55 | | | 61 | | Total current liabilities | 657 |
| | 628 |
| Total current liabilities | 1,110 | | | 674 | | Long-term debt | 2,862 |
| | 2,704 |
| Long-term debt | 3,132 | | | 3,162 | | | Deferred credits and other liabilities | | | | Deferred credits and other liabilities | | Deferred income taxes and unamortized investment tax credits | 1,131 |
| | 1,055 |
| Deferred income taxes and unamortized investment tax credits | 1,275 | | | 1,189 | | Asset retirement obligations | 41 |
| | 37 |
| Asset retirement obligations | 45 | | | 39 | | | Non-pension postretirement benefit obligations | 20 |
| | 29 |
| Non-pension postretirement benefit obligations | 3 | | | 13 | | | Regulatory liabilities | 746 |
| | 822 |
| Regulatory liabilities | 549 | | | 644 | | | Other | 297 |
| | 275 |
| Other | 314 | | | 340 | | Total deferred credits and other liabilities | 2,235 |
| | 2,218 |
| Total deferred credits and other liabilities | 2,186 | | | 2,225 | | Total liabilities | 5,754 |
| | 5,550 |
| Total liabilities | 6,428 | | | 6,061 | | Commitments and contingencies |
| |
| Commitments and contingencies | 0 | | 0 | Shareholder's equity | | | | Shareholder's equity | | Common stock ($0.01 par value, 200 shares authorized, 0 shares(a) outstanding at December 31, 2019 and 2018) | 1,796 |
| | 1,636 |
| | Common stock ($0.01 par value, 200 shares authorized, 0 shares(a) outstanding as of December 31, 2021 and 2020) | | Common stock ($0.01 par value, 200 shares authorized, 0 shares(a) outstanding as of December 31, 2021 and 2020) | 2,302 | | | 2,058 | | | Retained earnings | 1,111 |
| | 1,081 |
| Retained earnings | 1,173 | | | 1,145 | | | Total shareholder's equity | 2,907 |
| | 2,717 |
| Total shareholder's equity | 3,475 | | | 3,203 | | Total liabilities and shareholder's equity | $ | 8,661 |
|
| $ | 8,267 |
| Total liabilities and shareholder's equity | $ | 9,903 | | | $ | 9,264 | |
_____________ | | (a) | In millions, shares round to zero. Number of shares is 100 outstanding at December 31, 2019 and 2018. |
(a)In millions, shares round to zero. Number of shares is 100 outstanding as of December 31, 2021 and 2020.
See the Combined Notes to Consolidated Financial Statements
211179
Potomac Electric Power Company Statements of Changes in Shareholder's Equity | | | | | | | | | | | | | | | | | | (In millions) | Common Stock | | Retained Earnings | | Total Shareholder's Equity | Balance, December 31, 2018 | $ | 1,636 | | | $ | 1,081 | | | $ | 2,717 | | Net income | — | | | 243 | | | 243 | | Common stock dividends | — | | | (213) | | | (213) | | Contributions from parent | 160 | | | — | | | 160 | | Balance, December 31, 2019 | $ | 1,796 | | | $ | 1,111 | | | $ | 2,907 | | Net income | — | | | 266 | | | 266 | | Common stock dividends | — | | | (232) | | | (232) | | Contributions from parent | 262 | | | — | | | 262 | | Balance, December 31, 2020 | $ | 2,058 | | | $ | 1,145 | | | $ | 3,203 | | Net income | — | | | 296 | | | 296 | | Common stock dividends | — | | | (268) | | | (268) | | Contributions from parent | 244 | | | — | | | 244 | | Balance, December 31, 2021 | $ | 2,302 | | | $ | 1,173 | | | $ | 3,475 | |
| | | | | | | | | | | | | (In millions) | Common Stock | | Retained Earnings | | Total Shareholder's Equity | Balance, December 31, 2016 | $ | 1,309 |
| | $ | 980 |
| | $ | 2,289 |
| Net income | — |
| | 198 |
| | 198 |
| Common stock dividends | — |
| | (133 | ) | | (133 | ) | Contributions from parent | 161 |
| | — |
| | 161 |
| Balance, December 31, 2017 | $ | 1,470 |
| | $ | 1,045 |
| | $ | 2,515 |
| Net income | — |
| | 205 |
| | 205 |
| Common stock dividends | — |
| | (169 | ) | | (169 | ) | Contributions from parent | 166 |
| | — |
| | 166 |
| Balance, December 31, 2018 | $ | 1,636 |
| | $ | 1,081 |
| | $ | 2,717 |
| Net income | — |
| | 243 |
| | 243 |
| Common stock dividends | — |
| | (213 | ) | | (213 | ) | Contributions from parent | 160 |
| | — |
| | 160 |
| Balance, December 31, 2019 | $ | 1,796 |
| | $ | 1,111 |
| | $ | 2,907 |
|
See the Combined Notes to Consolidated Financial Statements
212180
Delmarva Power & Light Company Statements of Operations and Comprehensive Income | | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | (In millions) | 2021 | | 2020 | | 2019 | Operating revenues | | | | | | Electric operating revenues | $ | 1,191 | | | $ | 1,107 | | | $ | 1,143 | | Natural gas operating revenues | 168 | | | 162 | | | 167 | | Revenues from alternative revenue programs | 14 | | | (7) | | | (11) | | Operating revenues from affiliates | 7 | | | 9 | | | 7 | | Total operating revenues | 1,380 | | | 1,271 | | | 1,306 | | Operating expenses | | | | | | Purchased power | 387 | | | 359 | | | 381 | | Purchased fuel | 73 | | | 69 | | | 75 | | Purchased power from affiliates | 79 | | | 75 | | | 70 | | Operating and maintenance | 183 | | | 208 | | | 171 | | Operating and maintenance from affiliates | 162 | | | 153 | | | 152 | | Depreciation and amortization | 210 | | | 191 | | | 184 | | Taxes other than income taxes | 67 | | | 65 | | | 56 | | Total operating expenses | 1,161 | | | 1,120 | | | 1,089 | | | | | | | | Operating income | 219 | | | 151 | | | 217 | | Other income and (deductions) | | | | | | Interest expense, net | (61) | | | (61) | | | (61) | | Other, net | 12 | | | 10 | | | 13 | | Total other income and (deductions) | (49) | | | (51) | | | (48) | | Income before income taxes | 170 | | | 100 | | | 169 | | Income taxes | 42 | | | (25) | | | 22 | | Net income | $ | 128 | | | $ | 125 | | | $ | 147 | | Comprehensive income | $ | 128 | | | $ | 125 | | | $ | 147 | |
| | | | | | | | | | | | | | For the Years Ended December 31, | (In millions) | 2019 | | 2018 | | 2017 | Operating revenues | | | | | | Electric operating revenues | $ | 1,143 |
| | $ | 1,139 |
| | $ | 1,125 |
| Natural gas operating revenues | 167 |
| | 181 |
| | 161 |
| Revenues from alternative revenue programs | (11 | ) | | 4 |
| | 6 |
| Operating revenues from affiliates | 7 |
| | 8 |
| | 8 |
| Total operating revenues | 1,306 |
|
| 1,332 |
|
| 1,300 |
| Operating expenses | | | | | | Purchased power | 381 |
| | 352 |
| | 282 |
| Purchased fuel | 75 |
| | 89 |
| | 71 |
| Purchased power from affiliates | 70 |
| | 120 |
| | 179 |
| Operating and maintenance | 171 |
| | 182 |
| | 283 |
| Operating and maintenance from affiliates | 152 |
| | 162 |
| | 32 |
| Depreciation and amortization | 184 |
| | 182 |
| | 167 |
| Taxes other than income taxes | 56 |
| | 56 |
| | 57 |
| Total operating expenses | 1,089 |
|
| 1,143 |
|
| 1,071 |
| Gain on sales of assets | — |
| | 1 |
| | — |
| Operating income | 217 |
|
| 190 |
|
| 229 |
| Other income and (deductions) | | | | | | Interest expense, net | (61 | ) | | (58 | ) | | (51 | ) | Other, net | 13 |
| | 10 |
| | 14 |
| Total other income and (deductions) | (48 | ) |
| (48 | ) |
| (37 | ) | Income before income taxes | 169 |
|
| 142 |
|
| 192 |
| Income taxes | 22 |
| | 22 |
| | 71 |
| Net income | $ | 147 |
|
| $ | 120 |
|
| $ | 121 |
| Comprehensive income | $ | 147 |
|
| $ | 120 |
|
| $ | 121 |
|
See the Combined Notes to Consolidated Financial Statements
213181
Delmarva Power & Light Company Statements of Cash Flows | | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | (In millions) | 2021 | | 2020 | | 2019 | Cash flows from operating activities | | | | | | Net income | $ | 128 | | | $ | 125 | | | $ | 147 | | Adjustments to reconcile net income to net cash flows provided by operating activities: | | | | | | Depreciation and amortization | 210 | | | 191 | | | 184 | | | | | | | | | | | | | | Deferred income taxes and amortization of investment tax credits | 39 | | | (13) | | | (7) | | Other non-cash operating activities | 3 | | | 51 | | | 27 | | Changes in assets and liabilities: | | | | | | Accounts receivable | 15 | | | (34) | | | (5) | | Receivables from and payables to affiliates, net | (3) | | | 8 | | | (5) | | Inventories | (8) | | | (5) | | | (6) | | Accounts payable and accrued expenses | 16 | | | 4 | | | 3 | | | | | | | | Income taxes | 13 | | | (25) | | | 12 | | Pension and non-pension postretirement benefit contributions | (1) | | | — | | | (1) | | Other assets and liabilities | (27) | | | (30) | | | (55) | | Net cash flows provided by operating activities | 385 | | | 272 | | | 294 | | Cash flows from investing activities | | | | | | Capital expenditures | (429) | | | (424) | | | (348) | | | | | | | | | | | | | | Other investing activities | 4 | | | (3) | | | 1 | | Net cash flows used in investing activities | (425) | | | (427) | | | (347) | | Cash flows from financing activities | | | | | | Changes in short-term borrowings | 3 | | | 90 | | | 56 | | Issuance of long-term debt | 125 | | | 178 | | | 75 | | Retirement of long-term debt | — | | | (80) | | | (12) | | Dividends paid on common stock | (147) | | | (141) | | | (139) | | Contributions from parent | 120 | | | 112 | | | 63 | | Other financing activities | (5) | | | (2) | | | (1) | | Net cash flows provided by financing activities | 96 | | | 157 | | | 42 | | Increase (decrease) in cash and cash equivalents | 56 | | | 2 | | | (11) | | Cash and cash equivalents at beginning of period | 15 | | | 13 | | | 24 | | Cash and cash equivalents at end of period | $ | 71 | | | $ | 15 | | | $ | 13 | | | | | | | | Supplemental cash flow information | | | | | | (Decrease) increase in capital expenditures not paid | $ | (18) | | | $ | 20 | | | $ | (4) | | | | | | | |
| | | | | | | | | | | | | | For the Years Ended December 31, | (In millions) | 2019 | | 2018 | | 2017 | Cash flows from operating activities | | | | | | Net income | $ | 147 |
| | $ | 120 |
| | $ | 121 |
| Adjustments to reconcile net income (loss) to net cash flows provided by operating activities: | | | | | | Depreciation and amortization | 184 |
| | 182 |
| | 167 |
| Impairment losses on regulatory assets | — |
| | — |
| | 6 |
| Deferred income taxes and amortization of investment tax credits | (7 | ) | | 24 |
| | 89 |
| Other non-cash operating activities | 27 |
| | 24 |
| | 9 |
| Changes in assets and liabilities: | | | | | | Accounts receivable | (5 | ) | | 8 |
| | (22 | ) | Receivables from and payables to affiliates, net | (5 | ) | | (9 | ) | | 11 |
| Inventories | (6 | ) | | (3 | ) | | (5 | ) | Accounts payable and accrued expenses | 3 |
| | 11 |
| | (8 | ) | Income taxes | 12 |
| | 2 |
| | 26 |
| Pension and non-pension postretirement benefit contributions | (1 | ) | | — |
| | (2 | ) | Other assets and liabilities | (55 | ) | | (7 | ) | | (71 | ) | Net cash flows provided by operating activities | 294 |
|
| 352 |
|
| 321 |
| Cash flows from investing activities | | | | | | Capital expenditures | (348 | ) | | (364 | ) | | (428 | ) | Other investing activities | 1 |
| | 2 |
| | (1 | ) | Net cash flows used in investing activities | (347 | ) |
| (362 | ) |
| (429 | ) | Cash flows from financing activities | | | | | | Change in short-term borrowings | 56 |
| | (216 | ) | | 216 |
| Issuance of long-term debt | 75 |
| | 200 |
| | — |
| Retirement of long-term debt | (12 | ) | | (4 | ) | | (40 | ) | Dividends paid on common stock | (139 | ) | | (96 | ) | | (112 | ) | Contributions from parent | 63 |
| | 150 |
| | — |
| Other financing activities | (1 | ) | | (2 | ) | | — |
| Net cash flows provided by financing activities | 42 |
|
| 32 |
|
| 64 |
| (Decrease) increase in cash, cash equivalents and restricted cash | (11 | ) | | 22 |
| | (44 | ) | Cash, cash equivalents and restricted cash at beginning of period | 24 |
| | 2 |
| | 46 |
| Cash, cash equivalents and restricted cash at end of period | $ | 13 |
|
| $ | 24 |
|
| $ | 2 |
| | | | | | | Supplemental cash flow information | | | | | | (Decrease) increase in capital expenditures not paid | $ | (4 | ) | | $ | 22 |
| | $ | 4 |
|
See the Combined Notes to Consolidated Financial Statements
214182
Delmarva Power & Light Company Balance Sheets | | | | | | | | | | | | | December 31, | (In millions) | 2021 | | 2020 | ASSETS | | | | Current assets | | | | Cash and cash equivalents | $ | 28 | | | $ | 15 | | Restricted cash and cash equivalents | 43 | | | — | | Accounts receivable | | | | Customer accounts receivable | 149 | | 176 | Customer allowance for credit losses | (18) | | (22) | Customer accounts receivable, net | 131 | | | 154 | | Other accounts receivable | 58 | | 68 | Other allowance for credit losses | (8) | | (9) | Other accounts receivable, net | 50 | | | 59 | | Receivables from affiliates | 1 | | | 1 | | Inventories, net | | | | Fossil fuel | 11 | | | 6 | | Materials and supplies | 54 | | | 51 | | Prepaid utility taxes | 20 | | | 11 | | Regulatory assets | 68 | | | 58 | | | | | | | | | | Other | 16 | | | 13 | | Total current assets | 422 | | | 368 | | Property, plant, and equipment, (net of accumulated depreciation and amortization of $1,635 and $1,533 as of December 31, 2021 and 2020, respectively) | 4,560 | | | 4,314 | | Deferred debits and other assets | | | | Regulatory assets | 212 | | | 222 | | | | | | | | | | Prepaid pension asset | 157 | | | 162 | | Other | 61 | | | 74 | | Total deferred debits and other assets | 430 | | | 458 | | Total assets | $ | 5,412 | | | $ | 5,140 | | | | | |
| | | | | | | | | | December 31, | (In millions) | 2019 | | 2018 | ASSETS | | | | Current assets | | | | Cash and cash equivalents | $ | 13 |
| | $ | 23 |
| Restricted cash and cash equivalents | — |
| | 1 |
| Accounts receivable, net | | | | Customer (net of allowance for uncollectible accounts of $11 and $12 as of December 31, 2019 and 2018, respectively) | 141 |
| | 134 |
| Other (net of allowance for uncollectible accounts of $4 and $1 as of December 31, 2019 and 2018, respectively) | 38 |
| | 46 |
| Inventories, net | | | | Fossil Fuel | 8 |
| | 9 |
| Materials and supplies | 44 |
| | 37 |
| Prepaid utility taxes | 18 |
| | 17 |
| Regulatory assets | 52 |
| | 59 |
| Other | 11 |
| | 10 |
| Total current assets | 325 |
|
| 336 |
| Property, plant and equipment, (net of accumulated depreciation and amortization of $1,425 and $1,329 as of December 31, 2019 and 2018, respectively) | 4,035 |
| | 3,821 |
| Deferred debits and other assets | | | | Regulatory assets | 222 |
| | 231 |
| Goodwill | 8 |
| | 8 |
| Prepaid pension asset | 171 |
| | 186 |
| Other | 69 |
| | 6 |
| Total deferred debits and other assets | 470 |
|
| 431 |
| Total assets | $ | 4,830 |
|
| $ | 4,588 |
|
See the Combined Notes to Consolidated Financial Statements
215183
Delmarva Power & Light Company Balance Sheets | | | December 31, | | December 31, | (In millions) | 2019 | | 2018 | (In millions) | 2021 | | 2020 | | LIABILITIES AND SHAREHOLDER'S EQUITY | | | | LIABILITIES AND SHAREHOLDER'S EQUITY | | | | Current liabilities | | | | Current liabilities | | Short-term borrowings | $ | 56 |
| | $ | — |
| Short-term borrowings | $ | 149 | | | $ | 146 | | Long-term debt due within one year | 80 |
| | 91 |
| Long-term debt due within one year | 83 | | | 82 | | Accounts payable | 112 |
| | 111 |
| Accounts payable | 131 | | | 126 | | Accrued expenses | 46 |
| | 39 |
| Accrued expenses | 40 | | | 46 | | Payables to affiliates | 32 |
| | 33 |
| Payables to affiliates | 33 | | | 36 | | Customer deposits | 36 |
| | 35 |
| Customer deposits | 28 | | | 32 | | Regulatory liabilities | 37 |
| | 59 |
| Regulatory liabilities | 25 | | | 47 | | | Other | 15 |
| | 7 |
| Other | 59 | | | 20 | | Total current liabilities | 414 |
|
| 375 |
| Total current liabilities | 548 | | | 535 | | Long-term debt | 1,487 |
| | 1,403 |
| Long-term debt | 1,727 | | | 1,595 | | Deferred credits and other liabilities | | | | Deferred credits and other liabilities | | Deferred income taxes and unamortized investment tax credits | 655 |
| | 628 |
| Deferred income taxes and unamortized investment tax credits | 803 | | | 715 | | Asset retirement obligations | | Asset retirement obligations | 16 | | | 14 | | Non-pension postretirement benefit obligations | 16 |
| | 17 |
| Non-pension postretirement benefit obligations | 11 | | | 15 | | Regulatory liabilities | 574 |
| | 606 |
| Regulatory liabilities | 441 | | | 493 | | Other | 104 |
| | 50 |
| Other | 89 | | | 97 | | Total deferred credits and other liabilities | 1,349 |
|
| 1,301 |
| Total deferred credits and other liabilities | 1,360 | | | 1,334 | | Total liabilities | 3,250 |
|
| 3,079 |
| Total liabilities | 3,635 | | | 3,464 | | Commitments and contingencies | | |
|
| Commitments and contingencies | 0 | | 0 | Shareholder's equity | | | | Shareholder's equity | | Common stock ($2.25 par value, 0 shares(a) authorized, 0 shares(a) outstanding at December 31, 2019 and 2018, respectively) | 977 |
| | 914 |
| | Common stock ($2.25 par value, 0 shares(a) authorized, 0 shares(a) outstanding as of December 31, 2021 and 2020, respectively) | | Common stock ($2.25 par value, 0 shares(a) authorized, 0 shares(a) outstanding as of December 31, 2021 and 2020, respectively) | 1,209 | | | 1,089 | | Retained earnings | 603 |
| | 595 |
| Retained earnings | 568 | | | 587 | | Total shareholder's equity | 1,580 |
|
| 1,509 |
| Total shareholder's equity | 1,777 | | | 1,676 | | Total liabilities and shareholder's equity | $ | 4,830 |
|
| $ | 4,588 |
| Total liabilities and shareholder's equity | $ | 5,412 | | | $ | 5,140 | | |
_____________ | | (a) | In millions, shares round to zero. Number of shares is 1,000 authorized and 1,000 outstanding at December 31, 2019 and 2018. |
(a)In millions, shares round to zero. Number of shares is 1,000 authorized and 1,000 outstanding as of December 31, 2021 and 2020.
See the Combined Notes to Consolidated Financial Statements
216184
Delmarva Power & Light Company Statements of Changes in Shareholder's Equity | | | | | | | | | | | | | | | | | | (In millions) | Common Stock | | Retained Earnings | | Total Shareholder's Equity | Balance, December 31, 2018 | $ | 914 | | | $ | 595 | | | $ | 1,509 | | Net income | — | | | 147 | | | 147 | | Common stock dividends | — | | | (139) | | | (139) | | Contributions from parent | 63 | | | — | | | 63 | | Balance, December 31, 2019 | $ | 977 | | | $ | 603 | | | $ | 1,580 | | Net income | — | | | 125 | | | 125 | | Common stock dividends | — | | | (141) | | | (141) | | Contributions from parent | 112 | | | — | | | 112 | | Balance, December 31, 2020 | $ | 1,089 | | | $ | 587 | | | $ | 1,676 | | Net income | — | | | 128 | | | 128 | | Common stock dividends | — | | | (147) | | | (147) | | Contributions from parent | 120 | | | — | | | 120 | | Balance, December 31, 2021 | $ | 1,209 | | | $ | 568 | | | $ | 1,777 | |
| | | | | | | | | | | | | (In millions) | Common Stock | | Retained Earnings | | Total Shareholder's Equity | Balance, December 31, 2016 | $ | 764 |
| | $ | 562 |
| | $ | 1,326 |
| Net income | — |
| | 121 |
| | 121 |
| Common stock dividends | — |
| | (112 | ) | | (112 | ) | Balance, December 31, 2017 | $ | 764 |
| | $ | 571 |
|
| $ | 1,335 |
| Net income | — |
| | 120 |
| | 120 |
| Common stock dividends | — |
| | (96 | ) | | (96 | ) | Contributions from parent | 150 |
| | — |
| | 150 |
| Balance, December 31, 2018 | $ | 914 |
| | $ | 595 |
|
| $ | 1,509 |
| Net income | — |
| | 147 |
| | 147 |
| Common stock dividends | — |
| | (139 | ) | | (139 | ) | Contributions from parent | 63 |
| | — |
| | 63 |
| Balance, December 31, 2019 | $ | 977 |
| | $ | 603 |
|
| $ | 1,580 |
|
See the Combined Notes to Consolidated Financial Statements
217185
Atlantic City Electric Company and Subsidiary Company Consolidated Statements of Operations and Comprehensive Income | | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | (In millions) | 2021 | | 2020 | | 2019 | Operating revenues | | | | | | Electric operating revenues | $ | 1,362 | | | $ | 1,253 | | | $ | 1,237 | | Revenues from alternative revenue programs | 24 | | | (12) | | | — | | Operating revenues from affiliates | 2 | | | 4 | | | 3 | | Total operating revenues | 1,388 | | | 1,245 | | | 1,240 | | Operating expenses | | | | | | Purchased power | 677 | | | 596 | | | 589 | | Purchased power from affiliate | 17 | | | 13 | | | 19 | | Operating and maintenance | 179 | | | 192 | | | 187 | | Operating and maintenance from affiliates | 141 | | | 134 | | | 133 | | Depreciation and amortization | 179 | | | 180 | | | 157 | | Taxes other than income taxes | 8 | | | 8 | | | 4 | | Total operating expenses | 1,201 | | | 1,123 | | | 1,089 | | Gain on sales of assets | — | | | 2 | | | — | | | | | | | | | | | | | | Operating income | 187 | | | 124 | | | 151 | | Other income and (deductions) | | | | | | Interest expense, net | (58) | | | (59) | | | (58) | | Other, net | 4 | | | 6 | | | 6 | | Total other income and (deductions) | (54) | | | (53) | | | (52) | | Income before income taxes | 133 | | | 71 | | | 99 | | Income taxes | (13) | | | (41) | | | — | | | | | | | | Net income | $ | 146 | | | $ | 112 | | | $ | 99 | | Comprehensive income | $ | 146 | | | $ | 112 | | | $ | 99 | |
| | | | | | | | | | | | | | For the Years Ended December 31, | (In millions) | 2019 | | 2018 | | 2017 | Operating revenues | | | | | | Electric operating revenues | $ | 1,237 |
| | $ | 1,237 |
| | $ | 1,176 |
| Revenues from alternative revenue programs | — |
| | (4 | ) | | 8 |
| Operating revenues from affiliates | 3 |
| | 3 |
| | 2 |
| Total operating revenues | 1,240 |
|
| 1,236 |
|
| 1,186 |
| Operating expenses | | | | | | Purchased power | 589 |
| | 587 |
| | 541 |
| Purchased power from affiliates | 19 |
| | 29 |
| | 29 |
| Operating and maintenance | 187 |
| | 188 |
| | 279 |
| Operating and maintenance from affiliates | 133 |
| | 142 |
| | 28 |
| Depreciation and amortization | 157 |
| | 136 |
| | 146 |
| Taxes other than income taxes | 4 |
| | 5 |
| | 6 |
| Total operating expenses | 1,089 |
|
| 1,087 |
|
| 1,029 |
| Operating income | 151 |
|
| 149 |
|
| 157 |
| Other income and (deductions) | | | | | | Interest expense, net | (58 | ) | | (64 | ) | | (61 | ) | Other, net | 6 |
| | 2 |
| | 7 |
| Total other income and (deductions) | (52 | ) |
| (62 | ) |
| (54 | ) | Income before income taxes | 99 |
|
| 87 |
|
| 103 |
| Income taxes | — |
| | 12 |
| | 26 |
| Net income | $ | 99 |
|
| $ | 75 |
|
| $ | 77 |
| Comprehensive income | $ | 99 |
|
| $ | 75 |
|
| $ | 77 |
|
See the Combined Notes to Consolidated Financial Statements
218186
Atlantic City Electric Company and Subsidiary Company Consolidated Statements of Cash Flows | | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | (In millions) | 2021 | | 2020 | | 2019 | Cash flows from operating activities | | | | | | Net income | $ | 146 | | | $ | 112 | | | $ | 99 | | Adjustments to reconcile net income to net cash from operating activities: | | | | | | Depreciation and amortization | 179 | | | 180 | | | 157 | | | | | | | | Deferred income taxes and amortization of investment tax credits | (15) | | | (37) | | | 3 | | Other non-cash operating activities | — | | | 36 | | | 22 | | Changes in assets and liabilities: | | | | | | Accounts receivable | (37) | | | (55) | | | (13) | | Receivables from and payables to affiliates, net | 4 | | | 6 | | | (6) | | Inventories | 1 | | | (3) | | | (1) | | Accounts payable and accrued expenses | 3 | | | 5 | | | 26 | | | | | | | | Income taxes | — | | | (1) | | | 2 | | Pension and non-pension postretirement benefit contributions | (3) | | | (2) | | | (1) | | Other assets and liabilities | 17 | | | (42) | | | (27) | | Net cash flows provided by operating activities | 295 | | | 199 | | | 261 | | Cash flows from investing activities | | | | | | Capital expenditures | (445) | | | (401) | | | (375) | | | | | | | | | | | | | | Other investing activities | 1 | | | 6 | | | (1) | | Net cash flows used in investing activities | (444) | | | (395) | | | (376) | | Cash flows from financing activities | | | | | | Changes in short-term borrowings | (43) | | | 117 | | | 56 | | | | | | | | Repayments of short-term borrowings with maturities greater than 90 days | — | | | — | | | (125) | | Issuance of long-term debt | 425 | | | 123 | | | 150 | | Retirement of long-term debt | (260) | | | (44) | | | (18) | | | | | | | | Dividends paid on common stock | (288) | | | (114) | | | (124) | | Contributions from parent | 319 | | | 117 | | | 175 | | Other financing activities | (5) | | | (1) | | | (1) | | Net cash flows provided by financing activities | 148 | | | 198 | | | 113 | | (Decrease) increase in cash, restricted cash, and cash equivalents | (1) | | | 2 | | | (2) | | Cash, restricted cash, and cash equivalents at beginning of period | 30 | | | 28 | | | 30 | | Cash, restricted cash, and cash equivalents at end of period | $ | 29 | | | $ | 30 | | | $ | 28 | | | | | | | | Supplemental cash flow information | | | | | | (Decrease) increase in capital expenditures not paid | $ | (18) | | | $ | 33 | | | $ | (29) | | | | | | | |
| | | | | | | | | | | | | | For the Years Ended December 31, | (In millions) | 2019 | | 2018 | | 2017 | Cash flows from operating activities | | | | | | Net income | $ | 99 |
| | $ | 75 |
| | $ | 77 |
| Adjustments to reconcile net income (loss) to net cash from operating activities: | | | | | | Depreciation and amortization | 157 |
| | 136 |
| | 146 |
| Impairment losses on regulatory assets | — |
| | — |
| | 7 |
| Deferred income taxes and amortization of investment tax credits | 3 |
| | 25 |
| | 32 |
| Other non-cash operating activities | 22 |
| | 24 |
| | 17 |
| Changes in assets and liabilities: | | | | | | Accounts receivable | (13 | ) | | (8 | ) | | 14 |
| Receivables from and payables to affiliates, net | (6 | ) | | 1 |
| | — |
| Inventories | (1 | ) | | (4 | ) | | (7 | ) | Accounts payable and accrued expenses | 26 |
| | (7 | ) | | (2 | ) | Income taxes | 2 |
| | (2 | ) | | (11 | ) | Pension and non-pension postretirement benefit contributions | (1 | ) | | (6 | ) | | (20 | ) | Other assets and liabilities | (27 | ) | | (6 | ) | | (47 | ) | Net cash flows provided by operating activities | 261 |
|
| 228 |
|
| 206 |
| Cash flows from investing activities | | | | | | Capital expenditures | (375 | ) | | (335 | ) | | (312 | ) | Other investing activities | (1 | ) | | 1 |
| | (1 | ) | Net cash flows used in investing activities | (376 | ) |
| (334 | ) |
| (313 | ) | Cash flows from financing activities | | | | | | Change in short-term borrowings | 56 |
| | (94 | ) | | 108 |
| Proceeds from short-term borrowings with maturities greater than 90 days | — |
| | 125 |
| | — |
| Repayments of short-term borrowings with maturities greater than 90 days | (125 | ) | | — |
| | — |
| Issuance of long-term debt | 150 |
| | 350 |
| | — |
| Retirement of long-term debt | (18 | ) | | (281 | ) | | (35 | ) | Dividends paid on common stock | (124 | ) | | (59 | ) | | (68 | ) | Contributions from parent | 175 |
| | 67 |
| | — |
| Other financing activities | (1 | ) | | (3 | ) | | — |
| Net cash flows provided by financing activities | 113 |
|
| 105 |
|
| 5 |
| Decrease in cash, cash equivalents and restricted cash | (2 | ) |
| (1 | ) |
| (102 | ) | Cash, cash equivalents and restricted cash at beginning of period | 30 |
| | 31 |
| | 133 |
| Cash, cash equivalents and restricted cash at end of period | $ | 28 |
|
| $ | 30 |
|
| $ | 31 |
| | | | | | | Supplemental cash flow information | | | | | | (Decrease) increase in capital expenditures not paid | $ | (29 | ) | | $ | 46 |
| | $ | (13 | ) |
See the Combined Notes to Consolidated Financial Statements
219187
Atlantic City Electric Company and Subsidiary Company Consolidated Balance Sheets | | | | | | | | | | | | | December 31, | (In millions) | 2021 | | 2020 | ASSETS | | | | Current assets | | | | Cash and cash equivalents | $ | 29 | | | $ | 17 | | Restricted cash and cash equivalents | — | | | 3 | | Accounts receivable | | | | Customer accounts receivable | 190 | | 156 | Customer allowance for credit losses | (49) | | (32) | Customer accounts receivable, net | 141 | | | 124 | | Other accounts receivable | 76 | | 72 | Other allowance for credit losses | (15) | | (11) | Other accounts receivable, net | 61 | | | 61 | | | | | | Receivables from affiliates | 2 | | | 6 | | | | | | Inventories, net | 36 | | | 37 | | | | | | | | | | | | | | Regulatory assets | 61 | | | 75 | | Other | 3 | | | 3 | | Total current assets | 333 | | | 326 | | Property, plant, and equipment, (net of accumulated depreciation and amortization of $1,420 and $1,303 as of December 31, 2021 and 2020, respectively) | 3,729 | | | 3,475 | | Deferred debits and other assets | | | | Regulatory assets | 430 | | | 395 | | | | | | | | | | | | | | Prepaid pension asset | 27 | | | 40 | | | | | | Other | 37 | | | 50 | | Total deferred debits and other assets | 494 | | | 485 | | Total assets(a) | $ | 4,556 | | | $ | 4,286 | |
| | | | | | | | | | December 31, | (In millions) | 2019 | | 2018 | ASSETS | | | | Current assets | | | | Cash and cash equivalents | $ | 12 |
| | $ | 7 |
| Restricted cash and cash equivalents | 2 |
| | 4 |
| Accounts receivable, net | | | | Customer (net of allowance for uncollectible accounts of $13 and $18 as of December 31, 2019 and 2018, respectively) | 108 |
| | 95 |
| Other (net of allowance for uncollectible accounts of $5 and $1 as of December 31, 2019 and 2018, respectively) | 48 |
| | 55 |
| Receivables from affiliates | 4 |
| | 1 |
| Inventories, net | 34 |
| | 33 |
| Regulatory assets | 57 |
| | 40 |
| Other | 5 |
| | 5 |
| Total current assets | 270 |
|
| 240 |
| Property, plant and equipment, (net of accumulated depreciation and amortization of $1,210 and $1,137 as of December 31, 2019 and 2018, respectively) | 3,190 |
| | 2,966 |
| Deferred debits and other assets | | | | Regulatory assets | 368 |
| | 386 |
| Prepaid pension asset | 52 |
| | 67 |
| Other | 53 |
| | 40 |
| Total deferred debits and other assets | 473 |
|
| 493 |
| Total assets(a) | $ | 3,933 |
|
| $ | 3,699 |
|
See the Combined Notes to Consolidated Financial Statements
220188
Atlantic City Electric Company and Subsidiary Company Consolidated Balance Sheets | | | December 31, | | December 31, | (In millions) | 2019 | | 2018 | (In millions) | 2021 | | 2020 | LIABILITIES AND SHAREHOLDER'S EQUITY | | | | LIABILITIES AND SHAREHOLDER'S EQUITY | | | | Current liabilities | | | | Current liabilities | | Short-term borrowings | $ | 70 |
| | $ | 139 |
| Short-term borrowings | $ | 144 | | | $ | 187 | | Long-term debt due within one year | 20 |
| | 18 |
| Long-term debt due within one year | 3 | | | 261 | | Accounts payable | 144 |
| | 154 |
| Accounts payable | 165 | | | 177 | | Accrued expenses | 42 |
| | 35 |
| Accrued expenses | 44 | | | 46 | | Payables to affiliates | 25 |
| | 28 |
| Payables to affiliates | 31 | | | 31 | | | Customer deposits | 25 |
| | 26 |
| Customer deposits | 18 | | | 23 | | Regulatory liabilities | 25 |
| | 18 |
| Regulatory liabilities | 28 | | | 44 | | | Other | 9 |
| | 4 |
| Other | 12 | | | 11 | | Total current liabilities | 360 |
|
| 422 |
| Total current liabilities | 445 | | | 780 | | Long-term debt | 1,307 |
| | 1,170 |
| Long-term debt | 1,579 | | | 1,152 | | Deferred credits and other liabilities | | | | Deferred credits and other liabilities | | Deferred income taxes and unamortized investment tax credits | 577 |
| | 535 |
| Deferred income taxes and unamortized investment tax credits | 679 | | | 624 | | | Non-pension postretirement benefit obligations | 17 |
| | 17 |
| Non-pension postretirement benefit obligations | 12 | | | 17 | | | Regulatory liabilities | 357 |
| | 402 |
| Regulatory liabilities | 224 | | | 274 | | | Other | 39 |
| | 27 |
| Other | 49 | | | 48 | | Total deferred credits and other liabilities | 990 |
|
| 981 |
| Total deferred credits and other liabilities | 964 | | | 963 | | Total liabilities(a) | 2,657 |
|
| 2,573 |
| Total liabilities(a) | 2,988 | | | 2,895 | | Commitments and contingencies |
| |
| Commitments and contingencies | 0 | | 0 | Shareholder's equity | | | | Shareholder's equity | | Common stock ($3 par value, 25 shares authorized, 9 shares outstanding at December 31, 2019 and 2018) | 1,154 |
| | 979 |
| | Retained earnings | 122 |
| | 147 |
| | Common stock ($3 par value, 25 shares authorized, 9 shares outstanding as of December 31, 2021 and 2020) | | Common stock ($3 par value, 25 shares authorized, 9 shares outstanding as of December 31, 2021 and 2020) | 1,590 | | | 1,271 | | Retained (deficit) earnings | | Retained (deficit) earnings | (22) | | | 120 | | | Total shareholder's equity | 1,276 |
|
| 1,126 |
| Total shareholder's equity | 1,568 | | | 1,391 | | Total liabilities and shareholder's equity | $ | 3,933 |
|
| $ | 3,699 |
| Total liabilities and shareholder's equity | $ | 4,556 | | | $ | 4,286 | |
_____________ | | (a) | (a)ACE’s consolidated assets include $0 million and $13 million as of December 31, 2021 and 2020, respectively, of ACE’s consolidated VIE that can only be used to settle the liabilities of the VIE. ACE’s consolidated liabilities include $0 million and $21 millionas of December 31, 2021 and 2020, respectively, of ACE’s consolidated VIE for which the VIE creditors do not have recourse to ACE. See Note 23 - Variable Interest Entities for additional information. ACE’s consolidated assets include $17 million and $23 million at December 31, 2019 and 2018, respectively, of ACE’s consolidated VIE that can only be used to settle the liabilities of the VIE. ACE’s consolidated liabilities include $41 million and $59 millionat December 31, 2019 and 2018, respectively, of ACE’s consolidated VIE for which the VIE creditors do not have recourse to ACE. See Note 22 - Variable Interest Entities for additional information.
|
See the Combined Notes to Consolidated Financial Statements
221189
Atlantic City Electric Company and Subsidiary Company Consolidated Statements of Changes in Shareholder's Equity | | | | | | | | | | | | | | | | | | (In millions) | Common Stock | | Retained Earnings (Deficit) | | Total Shareholder's Equity | Balance, December 31, 2018 | $ | 979 | | | $ | 147 | | | $ | 1,126 | | Net income | — | | | 99 | | | 99 | | Common stock dividends | — | | | (124) | | | (124) | | Contributions from parent | 175 | | | — | | | 175 | | Balance, December 31, 2019 | $ | 1,154 | | | $ | 122 | | | $ | 1,276 | | Net income | — | | | 112 | | | 112 | | Common stock dividends | — | | | (114) | | | (114) | | Contributions from parent | 117 | | | — | | | 117 | | Balance, December 31, 2020 | $ | 1,271 | | | $ | 120 | | | $ | 1,391 | | Net income | — | | | 146 | | | 146 | | | | | | | | | | | | | | Common stock dividends | — | | | (288) | | | (288) | | Contributions from parent | 319 | | | — | | | 319 | | Balance, December 31, 2021 | $ | 1,590 | | | $ | (22) | | | $ | 1,568 | |
| | | | | | | | | | | | | (In millions) | Common Stock | | Retained Earnings | | Total Shareholder's Equity | Balance, December 31, 2016 | $ | 912 |
| | $ | 122 |
| | $ | 1,034 |
| Net income | — |
| | 77 |
| | 77 |
| Common stock dividends | — |
| | (68 | ) | | (68 | ) | Balance, December 31, 2017 | $ | 912 |
|
| $ | 131 |
| | $ | 1,043 |
| Net income | — |
| | 75 |
| | 75 |
| Common stock dividends | — |
| | (59 | ) | | (59 | ) | Contributions from parent | 67 |
| | — |
| | 67 |
| Balance, December 31, 2018 | $ | 979 |
|
| $ | 147 |
| | $ | 1,126 |
| Net income | — |
| | 99 |
| | 99 |
| Common stock dividends | — |
| | (124 | ) | | (124 | ) | Contributions from parent | 175 |
| | — |
| | 175 |
| Balance, December 31, 2019 | $ | 1,154 |
|
| $ | 122 |
| | $ | 1,276 |
|
See the Combined Notes to Consolidated Financial Statements
222190
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted) 1. Significant Accounting Policies (All Registrants) Description of Business (All Registrants) As of December 31, 2021, Exelon iswas 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, creating two publicly traded companies. The separation was completed on February 1, 2022. See Note 26 – Separation of the Combined Notes to Consolidated Financial Statements for additional information. | | | | | | | | | | | | | | | Name of Registrant / Subsidiary | | Business | | Service Territories | Commonwealth Edison Company (registrant) | | 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 (registrant) | | 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 (registrant) | | 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 (registrant) | | Utility services holding company engaged, through its reportable segments Pepco, DPL, and ACE | | Service Territories of Pepco, DPL, and ACE | | | | | | NamePotomac Electric Power Company (registrant) | | Purchase and regulated retail sale of Registrantelectricity | | Business | | Service TerritoriesDistrict 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 (registrant) | | 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 (registrant) | | Purchase and regulated retail sale of electricity | | Portions of Southern New Jersey | | | Transmission and distribution of electricity to retail customers | | | Constellation Energy Generation, LLC (formerly Exelon Generation Company, LLCLLC) (subsidiary) | | 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 annual report of all Registrants. The Notes to the Consolidated Financial Statements apply to the Registrants as indicated above in the Index to Combined Notes to Consolidated Financial Statements and 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. The accounts of Generation are included within Exelon's Consolidated Financial Statements. For activities and disclosures associated with Generation included in the Notes to the Exelon Consolidated Financial Statements, Generation is specifically named. All intercompany transactions have been eliminated. 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
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 1 — Significant Accounting Policies PHISCO are directly charged or allocated to the applicable subsidiaries. The results of Exelon’s corporate operations are presented as “Other” within the consolidated financial statements and include intercompany eliminations unless otherwise disclosed.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 1 — Significant Accounting Policies
December 31, 2021 and 2020, Exelon ownsowned 100% of Generation, PECO, BGE, and PHI and more than 99% of ComEd. PHI owns 100% of Pepco, DPL, and ACE. Generation owns 100% of its significant consolidated subsidiaries, either directly or indirectly, except for certain consolidated VIEs, including CENG and EGRP,CRP, of which Generation holds a 50.01% and 51% interest, respectively.interest. The remaining interests in thesethe consolidated VIEs are included in noncontrolling interests on Exelon’s and Generation’s Consolidated Balance Sheets.Sheet. See Note 2223 — Variable Interest Entities for additional information on VIEs. As of Exelon’s and Generation’s consolidated VIEs.February 1, 2022, as a result of the completion of the separation, Exelon no longer owns any interest in Generation. See Note 26 — Separation for additional information. The Registrants consolidate the accounts of entities in which a Registrant has a controlling financial interest, after the elimination of intercompany transactions. Where the Registrants do not have a controlling financial interest in an entity, proportionate consolidation, equity method accounting, or accounting for investments in equity securities with or without readily determinable fair value is applied. The Registrants apply proportionate consolidation when they have an undivided interest in an asset and are proportionately liable for their share of each liability associated with the asset. The Registrants proportionately consolidate their undivided ownership interests in jointly owned electric plants and transmission facilities. Under proportionate consolidation, the Registrants separately record their proportionate share of the assets, liabilities, revenues, and expenses related to the undivided interest in the asset. The Registrants apply equity method accounting when they have significant influence over an investee through an ownership in common stock, which generally approximates a 20% to 50% voting interest. The Registrants apply equity method accounting to certain investments and joint ventures, including certain financing trusts of ComEd and PECO.ventures. Under equity method accounting, the Registrants report their interest in the entity as an investment and the Registrants’ percentage share of the earnings from the entity as single line items in their financial statements. The Registrants use accounting for investments in equity securities with or without readily determinable fair values if they lack significant influence, which generally results when they hold less than 20% of the common stock of an entity. Under accounting for investments in equity securities with readily determinable fair values, the Registrants report their investment values based on quoted prices in active markets and realized and unrealized gains and losses are included in earnings. Under accounting for investments in equity securities without readily determinable fair values, the Registrants report their investments at cost adjusted for changes from observable transactions for identical or similar investments of the same issuer, less impairment. Changesimpairment, and changes in measurement are reported in earnings. The accompanying consolidated financial statements have been prepared in accordance with GAAP for annual financial statements and in accordance with the instructions to Form 10-K and Regulation S-X promulgated by the SEC. COVID-19 (All Registrants) The Registrants have taken steps to mitigate the potential risks posed by the global outbreak (pandemic) of the 2019 novel coronavirus (COVID-19). The Registrants provide a critical service to their customers and have taken measures to keep employees who operate the business safe and minimize unnecessary risk of exposure to the virus, including extra precautions for employees who work in the field. The Registrants have implemented work from home policies where appropriate and imposed travel limitations on employees.
Management makes estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements and accompanying notes, and the amounts of revenues and expenses reported during the periods covered by those financial statements and accompanying notes. As of December 31, 2021 and 2020, and through the date of this report, management assessed certain accounting matters that require consideration of forecasted financial information, including, but not limited to, allowance for credit losses and the carrying value of goodwill and other long-lived assets, in context with the information reasonably available and the unknown future impacts of COVID-19. The Registrants' future assessment of the magnitude and duration of COVID-19, as well as other factors, could result in material impacts to their consolidated financial statements in future reporting periods.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 1 — Significant Accounting Policies Use of Estimates (All Registrants) The preparation of financial statements of each of the Registrants in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Areas in which significant estimates have been made include, but are not limited to, the accounting for nuclear decommissioning costs and other AROs, pension and OPEB, the application of purchase accounting, inventory reserves, allowance for uncollectible accounts,credit losses, goodwill and long-lived asset impairments,impairment assessments, derivative instruments, unamortized energy contracts, fixed asset depreciation, environmental costs and other loss contingencies, taxes, and unbilled energy revenues. Actual results could differ from those estimates. Prior Period Adjustments and Reclassifications (Exelon, PHI and Pepco)
In the fourth quarter 2019, management identified an error related to an overstatement of the regulatory asset associated with Pepco’s decoupling mechanism for Maryland that originated in 2007 upon the inception of the program. Management has concluded that the error was not material to previously issued consolidated financial statements and the error was corrected through a revision to Exelon’s, PHI’s and Pepco’s consolidated financial statements contained herein for the years ended December 31, 2018 and 2017. The impact of the error correction was an $11 million reduction to Exelon’s, PHI’s and Pepco’s opening Retained earnings as of January 1, 2017 with a corresponding reduction to current Regulatory assets of $18 million and Deferred income taxes and unamortized investment tax credits of $7 million. In addition, Exelon’s, PHI’s and Pepco’s Total operating revenues decreased by $7 million for the years ended December 31, 2018 and 2017 and Net income decreased by $5 million and $7 million for the years ended December 31, 2018 and 2017, respectively, from originally reported amounts. The error did not impact net cash flows provided by operating activities, net cash flows used in investing activities or net cash flows provided by financing activities for the years ended December 31, 2018 and 2017 for Exelon, PHI and Pepco. Exelon’s diluted earnings per share of common stock remained unchanged from the originally reported amount for the year ended December 31, 2018. Exelon’s basic earnings per share of common stock for the year ended December 31, 2018 and basic and diluted earnings per share of common stock for the year ended December 31, 2017 decreased by $0.01 from the originally reported amount.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 1 — Significant Accounting Policies
Accounting for the Effects of Regulation (Exelon and the Utility(All Registrants) For their regulated electric and gas operations, Exelon and the Utility Registrants reflect the effects of cost-based rate regulation in their financial statements, which is required for entities with regulated operations that meet the following criteria: 1) rates are established or approved by a third-party regulator; (2) rates are designed to recover the entities’ cost of providing services or products; and (3) there is a reasonable expectation that rates designed to recover costs can be charged to and collected from customers. Exelon and the UtilityThe Registrants account for their regulated operations in accordance with regulatory and legislative guidance from the regulatory authorities having jurisdiction, principally the ICC, PAPUC, MDPSC, DCPSC, DPSCDEPSC, and NJBPU, under state public utility laws and the FERC under various Federal laws. Regulatory assets and liabilities are amortized and the related expense or revenue is recognized in the Consolidated Statements of Operations consistent with the recovery or refund included in customer rates. Exelon'sThe Registrants' regulatory assets and liabilities as of the balance sheet date are probable of being recovered or settled in future rates. If a separable portion of the Registrants' business was no longer able to meet the criteria discussed above, the affected entities would be required to eliminate from their consolidated financial statements the effects of regulation for that portion, which could have a material impact on their financial statements. See Note 3 — Regulatory Matters for additional information. With the exception of income tax-related regulatory assets and liabilities, Exelon and the Utility Registrants classify regulatory assets and liabilities with a recovery or settlement period greater than one year as both current and non-current in their Consolidated Balance Sheets, with the current portion representing the amount expected to be recovered from or settledrefunded to customers over the next twelve-month period as of the balance sheet date. Income tax-related regulatory assets and liabilities are classified entirely as non-current in Exelon's and the Utility Registrants’ Consolidated Balance Sheets to align with the classification of the related deferred income tax balances. Exelon and the UtilityThe Registrants treat the impacts of a final rate order received after the balance sheet date but prior to the issuance of the financial statements as a non-recognized subsequent event, as the receipt of a final rate order is a separate and distinct event that has future impacts on the parties affected by the order.
Revenues (All Registrants) Operating Revenues. The Registrants’ operating revenues generally consist of revenues from contracts with customers involving the sale and delivery of energy commodities and related products and services, utility revenues from ARP, and realized and unrealized revenues recognized under mark-to-market energy commodity derivative contracts. The Registrants recognize revenue from contracts with customers to depict the transfer of goods or services to customers in 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 natural gas tariff sales, distribution, and transmission services. At the end of each month, the Registrants accrue an estimate for the unbilled amount of energy delivered or services provided to customers. ComEd records ARP revenue for its best estimate of the electric distribution, energy efficiency, and transmission revenue impacts resulting from future changes in rates that ComEd believes are probable of approval by the ICC and FERC in accordance with its formula rate mechanisms. BGE, Pepco, DPL, and DPLACE record ARP revenue for their best estimate of the electric and natural gas distribution revenue impacts resulting from future changes in rates that they believe are probable of approval by the MDPSC, DCPSC, and/or DCPSCNJBPU in accordance with their revenue decoupling mechanisms. PECO, BGE, Pepco, DPL, and ACE record ARP revenue for their best estimate of the transmission revenue impacts resulting from future changes in rates that they believe are probable of approval by FERC in accordance with their formula rate mechanisms. See Note 3 — Regulatory Matters for additional information.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 1 — Significant Accounting Policies Option Contracts, Swaps, and Commodity Derivatives. Certain option contracts and swap arrangements that meet the definition of derivative instruments are recorded at fair value with subsequent changes in fair value recognized as revenue or expense. The classification of revenue or expense is based on the intent of the transaction. To the extent a Utility Registrant receives full cost recovery for energy procurement and related costs from retail customers, it records the fair value of its energy swap contracts with unaffiliated suppliers as well as an offsetting regulatory asset or liability in its Consolidated Balance Sheets. See Note 3 — Regulatory Matters and Note 1516 — Derivative Financial Instruments for additional information. Taxes Directly Imposed on Revenue-Producing Transactions. The Registrants collect certain taxes from customers such as sales and gross receipts taxes, along with other taxes, surcharges, and fees, that are levied by
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 1 — Significant Accounting Policies
state or local governments on the sale or distribution of gaselectricity and electricity.gas. Some of these taxes are imposed on the customer, but paid by the Registrants, while others are imposed on the Registrants. Where these taxes are imposed on the customer, such as sales taxes, they are reported on a net basis with no impact to the Consolidated Statements of Operations and Comprehensive Income. However, where these taxes are imposed on the Registrants, such as gross receipts taxes or other surcharges or fees, they are reported on a gross basis. Accordingly, revenues are recognized for the taxes collected from customers along with an offsetting expense. See Note 2324 — Supplemental Financial Information for Generation’s, ComEd’s, PECO’s, BGE’s, Pepco's, DPL's and ACE's utility taxes that are presented on a gross basis. Leases (All Registrants) The Registrants recognize a ROU asset and lease liability for operating and finance leases with a term of greater than one year. TheOperating lease ROU asset isassets are included in Other deferred debits and other assets and theoperating lease liability isliabilities are included in Other current liabilities and Other deferred credits and other liabilities on the Consolidated Balance Sheets. Finance lease ROU assets are included in Plant, property, and equipment, net and finance lease liabilities are included in Long-term debt due within one year and Long-term debt on the Consolidated Balance Sheets. The ROU asset is measured as the sum of (1) the present value of all remaining fixed and in-substance fixed payments using the rate implicit in the lease whenever that is readily determinable or each Registrant’s incremental borrowing rate, (2) any lease payments made at or before the commencement date (less any lease incentives received), and (3) any initial direct costs incurred. The lease liability is measured the same as the ROU asset, but excludes any payments made before the commencement date and initial direct costs incurred. Lease terms include options to extend or terminate the lease if it is reasonably certain they will be exercised. The Registrants include non-lease components for most asset classes, which are service-related costs that are not integral to the use of the asset, in the measurement of the ROU asset and lease liability. Expense for operating leases and leases with a term of one year or less is recognized on a straight-line basis over the term of the lease, unless another systematic and rational basis is more representative of the derivation of benefit from use of the leased property. Variable lease payments are recognized in the period in which the related obligation is incurred and consist primarily of payments for purchases of electricity under contracted generation andthat are based on the electricity produced by those generating assets. Operating lease expense and variable lease payments are recorded to Purchased power and fuel expense for contracted generation or Operating and maintenance expense for all other lease agreements on the Registrants’ Statements of Operations and Comprehensive Income. Expense for finance leases is primarily recorded to Operating and maintenance on the Registrants’ Statements of Operations and Comprehensive Income. Income from operating leases, including subleases, is recognized on a straight-line basis over the term of the lease, unless another systematic and rational basis is more representative of the pattern in which income is earned over the term of the lease. Variable lease payments are recognized in the period in which the related obligation is performed and consist primarily of payments received from sales of electricity under contracted generation andthat are based on the electricity produced by those generating assets. Operating lease income and variable lease payments are recorded to Operating revenues on the Registrants’ Statements of Operations and Comprehensive Income. The Registrants’ operating and finance leases consist primarily of contracted generation, real estate including office buildings, and vehicles and equipment. The Registrants generally account for contracted generation in which the generating asset is not renewable as a lease if the customer has dispatch rights and obtains substantially all of the economic benefits. For new agreements entered after January 1, 2019, theThe Registrants generally do not account for contracted generation in which the generating asset is renewable as a lease if the customer does not design the generating asset. The Registrants account for land right arrangements that provide for exclusive use as leases while shared use land
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 1 — Significant Accounting Policies arrangements are generally not leases. The Registrants do not account for secondary use pole attachments as leases. See Note 1011 — Leases for additional information. Income Taxes (All Registrants) Deferred Federalfederal and state income taxes are recorded on significant temporary differences between the book and tax basis of assets and liabilities and for tax benefits carried forward. Investment tax credits have been deferred in the Registrants’ Consolidated Balance Sheets and are recognized in book income over the life of the related property. The Registrants account for uncertain income tax positions using a benefit recognition model with a two-step approach; a more-likely-than-not recognition criterion; and a measurement approach that measures the position as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. If it is not more-likely-than-not that the benefit of the tax position will be sustained on its technical merits, no benefit is recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold. The Registrants recognize accrued interest related to unrecognized tax
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 1 — Significant Accounting Policies
benefits in Interest expense, net or Other, income and deductionsnet (interest income) and recognize penalties related to unrecognized tax benefits in Other, net in their Consolidated Statements of Operations and Comprehensive Income. Cash and Cash Equivalents (All Registrants) The Registrants consider investments purchased with an original maturity of three months or less to be cash equivalents. Restricted Cash and Cash Equivalents (All Registrants) Restricted cash and cash equivalents represent funds that are restricted to satisfy designated current liabilities. As of December 31, 20192021 and 2018,2020, the Registrants' restricted cash and cash equivalents primarily represented the following items: | | | | | | Registrant | Description | Exelon | Payment of medical, dental, vision, and long-term disability benefits in addition to the items listed forand Generation and the Utility Registrants. | Generation | Project-specificproject-specific nonrecourse financing structures for debt service and financing of operations of the underlying entities.entities, in addition to the items listed below for the Utility Registrants. | ComEd | Collateral held from suppliers associated with energy and REC procurement contracts, any over-recovered RPS costs and alternative compliance payments received from RES pursuant to FEJA, and costs for the remediation of an MGP site. | PECO | Proceeds from the sales of assets that were subject to PECO’s mortgage indenture. | BGE | Proceeds from the loan program for the completion of certain energy efficiency measures and collateral held from energy suppliers. | PHI | Payment of merger commitments, collateral held from its energy suppliers associated with procurement contracts, and repayment of transition bonds.Transition Bonds. | Pepco | Payment of merger commitments and collateral held from energy suppliers. | DPL | Collateral held from energy suppliers. | ACE | Repayment of transition bondsTransition Bonds and collateral held from energy suppliers. |
Restricted cash and cash equivalents not available to satisfy current liabilities are classified as noncurrent assets. As of December 31, 20192021 and 2018,2020, the Registrants' noncurrent restricted cash and cash equivalents primarily represented ComEd’s over-recovered RPS costs and alternative compliance payments received from RES pursuant to FEJA and costs for the remediation of an MGP site, and ACE’s repayment of transition bonds.Transition Bonds. See Note 2317 — Debt and Credit Agreements and Note 24 — Supplemental Financial Information for additional information. Allowance for UncollectibleCredit Losses on Accounts Receivables (All Registrants) The allowance for uncollectible accountscredit losses reflects the Registrants’ best estimates of losses on the customers' accounts receivable balances. For Generation, thebalances based on historical experience, current information, and reasonable and supportable forecasts.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 1 — Significant Accounting Policies The allowance for credit losses for Generation’s retail customers is based on accounts receivable aging historical experience coupled with specific identification through a credit monitoring process, which considers current conditions and other currentlyforward-looking information such as industry trends, macroeconomic factors, changes in the regulatory environment, external credit ratings, publicly available information. Utility Registrants estimatenews, payment status, payment history, and the exercise of collateral calls. The allowance for credit losses for Generation wholesale customers is developed using a credit monitoring process, like that used for retail customers. When a wholesale customer’s risk characteristics are no longer aligned with the pooled population, Generation uses specific identification to develop an allowance for credit losses. Adjustments to the allowance for credit losses are recorded in Operating and maintenance expense in Exelon’s Consolidated Statements of Operations and Comprehensive Income.
The allowance for credit losses for the Utility Registrants’ customers is developed by applying loss rates developed specifically for each companyUtility Registrant, based on historical loss experience, current conditions, and forward-looking risk factors, to the outstanding receivable balance by customer risk segment. Utility Registrants' customer accounts are written off consistent with approved regulatory requirements. Adjustments to the allowance for credit losses are primarily recorded to Operating and maintenance expense on the Utility Registrants' Consolidated Statements of Operations and Comprehensive Income or Regulatory assets and liabilities on the Utility Registrants' Consolidated Balance Sheets. See Note 3 —- Regulatory Matters for additional information regarding the regulatory recovery of uncollectiblecredit losses on customer accounts receivable at ComEdreceivable.
The Registrants have certain non-customer receivables in Other deferred debits and ACE.other assets which primarily are with governmental agencies and other high-quality counterparties with no history of default. As such, the allowance for credit losses related to these receivables is not material. The Registrants monitor these balances and will record an allowance if there are indicators of a decline in credit quality. Variable Interest Entities (Exelon, Generation, PHI, and ACE) Exelon accounts for its investments in and arrangements with VIEs based on the following specific requirements: requires an entity to qualitatively assess•qualitative assessment of factors determinant in whether it should consolidate a VIE based on whether the entity has a controlling financial interest,
requires an •ongoing reconsideration of this assessment, instead of only upon certain triggering events, and
requires the entity that•where it consolidates a VIE (the(as primary beneficiary) to disclose, disclosure of (1) the assets of the consolidated VIE, if they can be used to only settle specific obligations of the consolidated VIE, and (2) the
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 1 — Significant Accounting Policies
liabilities of a consolidated VIE for which creditors do not have recourse to the general credit of the primary beneficiary. See Note 2223 — Variable Interest Entities for additional information. Inventories (All Registrants) Inventory is recorded at the lower of weighted average cost or net realizable value. Provisions are recorded for excess and obsolete inventory. Fossil fuel, materials and supplies, and emissions allowances are generally included in inventory when purchased. Fossil fuel and emissions allowances are expensed to purchasedPurchased power and fuel expense when used or sold. Materials and supplies generally includes transmission, distribution, and generating plant materials and are expensed to operatingOperating and maintenance or capitalized to property,Property, plant, and equipment, as appropriate, when installed or used. Debt and Equity Security Investments (Exelon and Generation)(Exelon) Debt Security Investments. Debt securities are reported at fair value and classified as available-for-sale securities. Unrealized gains and losses, net of tax, are reported in OCI. Equity Security Investments without Readily Determinable Fair Values. Exelon has certain equity securities without readily determinable fair values. Exelon has elected to use the practicability exceptionmeasurement alternative to measure these investments, defined as cost adjusted for changes from observable transactions for identical or similar investments of the same issuer, less impairment. Changes in measurement are reported in earnings. Equity Security Investments with Readily Determinable Fair Values. Equity securities held in the NDT funds are classified asExelon has certain equity securities with readily determinable fair values. RealizedFor equity securities held in NDT funds, realized and unrealized gains and losses, net of tax, on Generation’s NDT funds associated with the Regulatory Agreement Units are included in regulatory liabilities at Exelon,
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 1 — Significant Accounting Policies ComEd, and PECO in Noncurrent payables to affiliates at Generation and in Noncurrent receivables from affiliates at ComEd and PECO. Realized and unrealized gains and losses, net of tax, on Generation’s NDT funds associated with the Non-Regulatory Agreement Units are included in earnings at Exelon and Generation. Exelon's and Generation'sExelon. NDT funds are classified as current or noncurrent assets, depending on the timing of the decommissioning activities and income taxes on trust earnings. For all other equity securities with readily determinable fair values, realized and unrealized gains and losses are included in earnings at Exelon. See Note 3 — Regulatory Matters for additional information regarding ComEd’s and PECO’s regulatory assets and liabilities and Note 1718 — Fair Value of Financial Assets and Liabilities and Note 910 — Asset Retirement Obligations for additional information regarding marketable securities held by NDT funds.information. Property, Plant, and Equipment (All Registrants) Property, plant, and equipment is recorded at original cost. Original cost includes construction-related direct labor and material costs. The Utility Registrants also include indirect construction costs including labor and related costs of departments associated with supporting construction activities. When appropriate, original cost also includes capitalized interest for Generation, Exelon Corporate, and PHI and AFUDC for regulated property at the Utility Registrants. The cost of repairs and maintenance including planned major maintenance activities and minor replacements of property, is charged to Operating and maintenance expense as incurred. Third parties reimburse the Utility Registrants for all or a portion of expenditures for certain capital projects. Such contributions in aid of construction costs (CIAC) are recorded as a reduction to Property, plant, and equipment, net. DOE SGIG and other funds reimbursed to the Utility Registrants have been accounted for as CIAC. For Generation, upon retirement, the cost of property is generally charged to accumulated depreciation in accordance with the composite and group methods of depreciation. Upon replacement of an asset, the costs to remove the asset, net of salvage, are capitalized to gross plant when incurred as part of the cost of the newly-installed asset and recorded to depreciation expense over the life of the new asset. Removal costs, net of salvage, incurred for property that will not be replaced is charged to Operating and maintenance expense as incurred. For the Utility Registrants, upon retirement, the cost of property, net of salvage, is charged to accumulated depreciation consistent with the composite and group methods of depreciation. Depreciation expense at ComEd, BGE, Pepco, DPL, and ACE includes the estimated cost of dismantling and removing plant from service upon retirement. Actual incurred removal costs are applied against a related regulatory liability or recorded to a regulatory asset if in excess of previously collected removal costs. PECO’s removal costs are capitalized to accumulated
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 1 — Significant Accounting Policies
depreciation when incurred and recorded to depreciation expense over the life of the new asset constructed consistent with PECO’s regulatory recovery method. Capitalized Software. Certain costs, such as design, coding, and testing incurred during the application development stage of software projects that are internally developed or purchased for operational use are capitalized within Property, plant, and equipment. Similar costs incurred for cloud-based solutions treated as service arrangements are capitalized within Other Current Assets and Deferred Debits and Other Assets. Such capitalized amounts are amortized ratably over the expected lives of the projects when they become operational, generally not to exceed five years. Certain other capitalized software costs are being amortized over longer lives based on the expected life or pursuant to prescribed regulatory requirements. Capitalized Interest and AFUDC. During construction, Exelon and Generation capitalizecapitalizes the costs of debt funds used to finance non-regulated construction projects. Capitalization of debt funds is recorded as a charge to construction work in progress and as a non-cash credit to interest expense. AFUDC is the cost, during the period of construction, of debt and equity funds used to finance construction projects for regulated operations. AFUDC is recorded to construction work in progress and as a non-cash credit to an allowance that is included in interest expense for debt-related funds and other income and deductions for equity-related funds. The rates used for capitalizing AFUDC are computed under a method prescribed by regulatory authorities. See Note 78 — Property, Plant, and Equipment, Note 89 — Jointly Owned Electric Utility Plant and Note 2324 — Supplemental Financial Information for additional information regarding property, plant and equipment.information.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 1 — Significant Accounting Policies Nuclear Fuel (Exelon and Generation)(Exelon) The cost of nuclear fuel is capitalized withinin Property, plant, and equipment and charged to Purchased power and fuel expense using the unit-of-production method. Any potential future SNF disposal fees will also be expensed through Purchased power and fuel expense. Additionally, certain on-site SNF storage costs are being reimbursed by the DOE since a DOE (or government-owned) long-term storage facility has not been completed. See Note 1819 — Commitments and Contingencies for additional information regarding the cost of SNF storage and disposal. Nuclear Outage Costs (Exelon and Generation)(Exelon) Costs associated with nuclear outages, including planned major maintenance activities, are expensed to Operating and maintenance expense or capitalized to Property, plant, and equipment (based on the nature of the activities) in the period incurred. Depreciation and Amortization (All Registrants) Except for the amortization of nuclear fuel, depreciation is generally recorded over the estimated service lives of property, plant, and equipment on a straight-line basis using the group, composite or unitary methods of depreciation. The group approach is typically for groups of similar assets that have approximately the same useful lives and the composite approach is used for dissimilar assets that have different lives. Under both methods, a reporting entity depreciates the assets over the average life of the assets in the group. The Utility Registrants'ComEd, BGE, Pepco, DPL, and ACE's depreciation expense includes the estimated cost of dismantling and removing plant from service upon retirement, which is consistent with each utility's regulatory recovery method. PECO's removal costs are capitalized to accumulated depreciation when incurred and recorded to depreciation expense over the life of the new asset constructed consistent with PECO's regulatory recovery method. The estimated service lives for the Registrants are based on a combination of depreciation studies, historical retirements, site licenses, and management estimates of operating costs and expected future energy market conditions. See Note 67 — Early Plant Retirements for additional information on the impacts of expected and potential early plant retirements. See Note 78 — Property, Plant, and Equipment for additional information regarding depreciation. Amortization of regulatory assets and liabilities are recorded over the recovery or refund period specified in the related legislation or regulatory order or agreement. When the recovery or refund period is less than one year, amortization is recorded to the line item in which the deferred cost or income would have originally been recorded in the Utility Registrants’ Consolidated Statements of Operations and Comprehensive Income. Amortization of ComEd’s electric distribution and energy efficiency formula rate regulatory assets and the Utility Registrants' transmission formula rate regulatory assets is recorded to Operating revenues.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 1 — Significant Accounting Policies
Amortization of income tax related regulatory assets and liabilities is generally recorded to Income tax expense. With the exception ofExcept for the regulatory assets and liabilities discussed above, when the recovery period is more than one year, the amortization is generally recorded to Depreciation and amortization in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.Income when the recovery period is more than one year. See Note 3 — Regulatory Matters and Note 2324 — Supplemental Financial Information for additional information regarding Generation’s nuclear fuel and ARC, and the amortization of the Utility Registrants' regulatory assets.assets and Generation's nuclear fuel and ARC, respectively. Asset Retirement Obligations (All Registrants) Generation estimatesThe Registrants estimate and recognizesrecognize a liability for itstheir legal obligation to perform asset retirement activities even though the timing and/or methods of settlement may be conditional on future events. Generation generally updates its nuclear decommissioning ARO annually, unless circumstances warrant more frequent updates, based on its annual evaluation of cost escalation factors and probabilities assigned to the multiple outcome scenarios within its probability-weighted discounted cash flow models. Generation’s multiple outcome scenarios are generally based on decommissioning cost studies which are updated, on a rotational basis, for each of Generation’s nuclear units at least every five years, unless circumstances warrant more frequent updates. The Utility Registrants update their AROs either annually or on a rotational basis at least once every three years, based on a risk profile, unless circumstances warrant more frequent updates. The updates factor in new cost estimates, credit-adjusted, risk-free rates (CARFR) and escalation rates, and the timing of cash flows. AROs are accreted throughout each year to reflect the time value of money for these present value obligations through a
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 1 — Significant Accounting Policies charge to Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income for Non-Regulatory Agreement Units and through a decrease to regulatory liabilities for Regulatory Agreement Units or, in the case of the Utility Registrants' accretion, through an increase to regulatory assets. See Note 910 — Asset Retirement Obligations for additional information. Guarantees (All Registrants) TheIf necessary, the Registrants recognize a liability at the inceptiontime of issuance of a guarantee a liability for the fair market value of the obligations they have undertaken by issuing the guarantee, including the ongoing obligation to perform over the term of the guarantee in the event that the specified triggering events or conditions occur.
guarantee. The liability that is initially recognized at the inception of the guarantee is reduced or eliminated as the Registrants are released from risk under the guarantee. Depending on the nature of the guarantee, the release from risk of the Registrant may be recognized only upon the expiration or settlement of the guarantee or by a systematic and rational amortization method over the term of the guarantee. See Note 1819 — Commitments and Contingencies for additional information. Asset Impairments Long-Lived Assets (All Registrants). The Registrants regularly monitor and evaluate the carrying value of long-lived assets andor 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 andor asset groups are potentially impaired by comparing the undiscounted expected future cash flows to the carrying value.value when indicators of impairment exist. When the undiscounted cash flow analysis indicates a long-lived asset or asset group ismay not be 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. See Note 1112 — Asset Impairments for additional information. Goodwill (Exelon, ComEd, and PHI). Goodwill represents the excess of the purchase price paid over the estimated fair value of the net assets acquired and liabilities assumed in the acquisition of a business. Goodwill is not amortized but is testedassessed for impairment at least annually or on an interim basis if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. See Note 1213 — Intangible Assets for additional information. Equity Method Investments (Exelon and Generation)(Exelon). Exelon regularly monitors and Generation regularly monitor and evaluateevaluates equity method investments to determine whether they are impaired. An impairment is recorded when the investment has experienced a decline in value that is other-than-temporary in nature. Additionally, if the entity in which GenerationExelon holds an investment recognizes an impairment loss, Exelon and Generation would record their proportionate share of that impairment loss and evaluate the investment for an other-than-temporary decline in value.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 1 — Significant Accounting Policies
Debt Security Investments (Exelon and Generation)(Exelon). Declines in the fair value of debt security investments below the cost basis are reviewed to determine if such decline isdeclines are other-than-temporary. If the decline is determined to be other-than-temporary, the amount of the impairment loss is included in earnings. Equity Security Investments (Exelon and Generation)(Exelon). Equity investments with readily determinable fair values are measured and recorded at fair value with any changes in fair value recorded throughin earnings. Investments in equity securities without readily determinable fair values are qualitatively assessed for impairment each reporting period. If it is determined that the equity security is impaired, on the basis of the qualitative assessment, an impairment loss will be recognized in earnings to the amount by which the security’s carrying amount exceeds its fair value. Derivative Financial Instruments (All Registrants) All derivatives are recognized on the balance sheet at their fair value unless they qualify for certain exceptions, including the NPNS. For derivatives intended to serve as economic hedges, changes in fair value are recognized in earnings each period. Amounts classified in earnings are included in Operating revenue, Purchased power and fuel, Interest expense, or Other, net in the Consolidated Statements of Operations and Comprehensive Income based on the activity the transaction is economically hedging. While the majoritymost of the derivatives serve as economic hedges, there are also derivatives entered into for proprietary trading purposes, subject to Exelon’s Risk Management Policy,RMP, and changes in the fair value of those derivatives are recorded in revenue or expense in the Consolidated Statements of Operations and Comprehensive Income. At the Utility Registrants, changes in fair value may be recorded as a regulatory asset or liability if there is an ability to recover or return the associated costs. Cash inflows and
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 1 — Significant Accounting Policies outflows related to derivative instruments are included as a component of operating, investing, or financing cash flows in the Consolidated Statements of Cash Flows, depending on the nature of each transaction. On July 1, 2018, Exelon and Generation de-designated its fair value and cash flow hedges. See Note 3 — Regulatory Matters and Note 1516 — Derivative Financial Instruments for additional information. As part of Generation’s energy marketing business, Generation enters into contracts to buy and sell energy to meet the requirements of its customers. These contracts include short-term and long-term commitments to purchase and sell energy and energy-related products in the energy markets with the intent and ability to deliver or take delivery of the underlying physical commodity. NPNS are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable period of time and will not be financially settled. Revenues and expenses on derivative contracts that qualify, and are designated, as NPNS are recognized when the underlying physical transaction is completed. While these contracts are considered derivative financial instruments, they are not required to be recorded at fair value, but rather are recorded on an accrual basis of accounting.value. See Note 1516 — Derivative Financial Instruments for additional information. Retirement Benefits (All Registrants) Exelon sponsors defined benefit pension plans and OPEB plans for essentiallysubstantially all current employees. The plan obligations and costs of providing benefits under these plans are measured as of December 31. The measurement involves various factors, assumptions, and accounting elections. The impact of assumption changes or experience different from that assumed on pension and OPEB obligations is recognized over time rather than immediately recognized in the Consolidated Statements of Operations and Comprehensive Income. Gains or losses in excess of the greater of ten percent of the projected benefit obligation or the MRV of plan assets are amortized over the expected average remaining service period of plan participants. See Note 1415 — Retirement Benefits for additional information. New Accounting Standards (All Registrants)
New Accounting Standards Adopted in 2019: In 2019, the Registrants adopted the following new authoritative accounting guidance issued by the FASB.
Cloud Computing Arrangements (Issued August 2018). Aligns the requirements for capitalizing costs incurred to implement a cloud computing arrangement with the internal-use software guidance. As a result, certain implementation costs incurred in a cloud computing arrangement that are currently expensed as incurred will be deferred and amortized over the non-cancellable term of the arrangement plus any reasonably certain renewal periods. The standard was effective January 1, 2020 and can be applied using either a prospective or retrospective transition approach. A retrospective approach requires a cumulative-effect adjustment to retained earnings as of
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 1 — Significant Accounting Policies
the beginning of the period of adoption. The Registrants early adopted this standard using a prospective approach as of January 1, 2019. The new guidance did not have a material impact on the Registrants' financial statements.
Leases (Issued February 2016). The Registrants applied the new guidance with the following transition practical expedients:
a "package of three" expedients that must be taken together and allow entities to (1) not reassess whether existing contracts contain leases, (2) carry forward the existing lease classification, and (3) not reassess initial direct costs associated with existing leases,
an implementation expedient which allows the requirements of the standard in the period of adoption with no restatement of prior periods, and
a land easement expedient which allows entities to not evaluate land easements under the new standard at adoption if they were not previously accounted for as leases.
The standard resulted in the Registrants recording ROU assets and lease liabilities for operating leases in their Consolidated Balance Sheets but did not have a material impact in the Registrants' Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and Consolidated Statements of Changes in Shareholders' Equity. The operating ROU assets and lease liabilities recognized upon adoption are materially consistent with the balances presented in the Combined Notes to the Consolidated Financial Statements, excluding 2019 expense and payment activity. See Note 10 — Leases for additional information.
New Accounting Standards Adopted as of January 1, 2020: The following new authoritative accounting guidance issued by the FASB was adopted as of January 1, 2020 and will be reflected by the Registrants in their consolidated financial statements beginning in the first quarter of 2020.
Impairment of Financial Instruments (Issued June 2016). Provides for a new Current Expected Credit Loss (CECL) impairment model for specified financial instruments including loans, trade receivables, debt securities classified as held-to-maturity investments and net investments in leases recognized by a lessor. Under the new guidance, on initial recognition and at each reporting period, an entity is required to recognize an allowance that reflects its current estimate of credit losses expected to be incurred over the life of the financial instrument based on historical experience, current conditions and reasonable and supportable forecasts. The standard was effective January 1, 2020 and requires a modified retrospective transition approach through a cumulative-effect adjustment to retained earnings as of the beginning of the period of adoption. This standard is primarily applicable to Generation's and the Utility Registrants' trade accounts receivables balances. The guidance did not have a significant impact on the Registrants' consolidated financial statements.
Goodwill Impairment (Issued January 2017). Simplifies the accounting for goodwill impairment by removing Step 2 of the current test, which requires calculation of a hypothetical purchase price allocation. Under the revised guidance, goodwill impairment will be measured as the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill (currently Step 1 of the two-step impairment test). Entities will continue to have the option to perform a qualitative assessment to determine if a quantitative impairment test is necessary. The standard was effective January 1, 2020 and must be applied on a prospective basis. Exelon, Generation, ComEd, PHI and DPL will apply the new guidance for their goodwill impairment assessments in 2020 and do not expect the updated guidance to have a material impact to their financial statements.
2. Mergers, Acquisitions, and Dispositions (Exelon and Generation)(Exelon) CENG Put Option (Exelon and Generation) Prior to August 6, 2021, Generation ownsowned a 50.01% membership interest in CENG, a joint venture with EDF, which wholly owns the Calvert Cliffs and Ginna nuclear stations 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. See Note 2223 — Variable Interest Entities for additional information. On April 1, 2014, Generation and EDF entered into various agreements including a Nuclear Operating Services Agreement,NOSA, an amended LLC Operating Agreement, an Employee Matters Agreement, and a Put Option Agreement, among others. Under the amended LLC Operating Agreement, CENG made a $400 million special distribution to EDF
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 2 — Mergers, Acquisitions and Dispositions
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 hashad 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. Under the terms of the Put Option Agreement, the purchase price is to be determined by agreement of the parties, or absent such agreement, by a third-party arbitration process. The third parties determining fair market value of EDF’s 49.99% interest are to take into consideration all rights and obligations under the LLC Operating Agreement and Employee Matters Agreement including but not limited to Generation’s rights with respect to any unpaid aggregate preferred distributions and the related return. As of December 31, 2019, the total unpaid aggregate preferred distributions and related return owed to Generation is $571 million. At this time, Generation cannot reasonably predict the ultimate purchase price that will be paid to EDF for its interest in CENG. The transaction will requirerequired approval by the NYPSC, the FERC and the NRC. The processNYPSC, which approvals were received on July 30, 2020 and regulatory approvals could take oneApril 15, 2021, respectively. On August 6, 2021, Generation and EDF entered into a settlement agreement pursuant to two years or more to complete.
Acquisition of James A. FitzPatrick Nuclear Generating Station (Exelon and Generation)
On March 31, 2017,which Generation acquired the single-unit James A. FitzPatrick (FitzPatrick) nuclear generating station locatedpurchased EDF’s equity interest in Scriba, New York from Entergy Nuclear FitzPatrick LLC (Entergy)CENG for a totalnet purchase price of $289$885 million, which consistedincludes, 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. As a result of the transaction, Exelon recorded deferred tax liabilities of $290 million in Common stock in the Consolidated Balance Sheet. See Note 14 — Income Taxes for additional information.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 2 — Mergers, Acquisitions, and Dispositions The following table summarizes the effects of the changes in Generation's ownership interest in CENG in Exelon's Shareholders' Equity:
| | | | | | | | | | | For the Year Ended December 31, 2021 | Net income attributable to Exelon's common shareholders | | $ | 1,706 | | Pre-tax increase in Exelon's common stock for purchase of EDF's 49.99% equity interest(a) | | 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) | | Change from net income attributable to common stock and transfers from noncontrolling interest | | $ | 2,496 | | | | | | | | | | | | | | | | | | | |
_________ (a)Represents non-cash activity in Exelon’s consolidated financial statements. Agreement for Sale of Generation’s Solar Business On December 8, 2020, Generation entered into an agreement with an affiliate of Brookfield Renewable, for the sale of a cashsignificant 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 $110$810 million. Exelon 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 recognized a net cost reimbursement to andpre-tax gain of $68 million which is included in Gain on behalfsales of Entergy of $179 million. As part of the transaction, Generation received the FitzPatrick NDT fund assets and assumedbusinesses in the obligation to decommission FitzPatrick. The NRC license for FitzPatrick expires in 2034. An after-tax bargain purchase gain of $233 million was included within Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income which primarily reflects differences in strategies between Generation and Entergy for the intended use and ultimate decommissioning of the plant. Exelon and Generation incurred $57 million of merger and integration related costs for FitzPatrick for the year ended December 31, 2017 which are included within Operating and maintenance expense in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income.
See Note 17 — Debt and Credit Agreements for additional information on the SolGen nonrecourse debt included as part of the transaction. 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 recorded a pre-tax impairment charge of $140 million in Operating and maintenance expense in the Consolidated Statement of Operations and Comprehensive Income. Completion of the transaction was subject to the satisfaction of various customary closing conditions which were satisfied in the second quarter of 2021. The sale was completed on June 30, 2021 for a net purchase price of $36 million. Disposition of Oyster Creek (Exelon and Generation) On July 31, 2018, Generation entered into an agreement with Holtec International (Holtec) and its indirect wholly owned subsidiary, Oyster Creek Environmental Protection, LLC (OCEP),OCEP, for the sale and decommissioning of Oyster Creek located in Forked River, New Jersey, which permanently ceased generation operations on September 17, 2018. Completion of the transaction contemplated by the sale agreement was subject to the satisfaction of several closing conditions, including approval of the license transfer from the NRC and other regulatory approvals, and a private letter ruling from the IRS, which were satisfied in the second quarter of 2019. The sale was completed on July 1, 2019. Exelon and Generation recognized a loss on the sale in the third quarter of 2019, which was immaterial. Under the terms of the transaction, Generation transferred to OCEP substantially all the assets associated with Oyster Creek, including assets held in NDT funds, along with the assumption of liability for all responsibility for the site, including full decommissioning and ongoing management of spent fuelthe SNF until the spent fuelit is moved offsite. The terms of the transaction also include various forms of performance assurance for the obligations of OCEP to timely complete the required decommissioning, including a parental guaranty from Holtec for all performance and payment obligations of OCEP, and a requirement for Holtec to deliver a letter of credit to Generation upon the occurrence of specified events. As a result of the transaction, in the third quarter of 2018, Exelon and Generation reclassified certain Oyster Creek assets and liabilities in Exelon’s and Generation’s Consolidated Balance Sheets as held for sale at their respective fair values. Exelon and Generation had $897 million and $777 million of Assets and Liabilities held for sale, respectively, at December 31, 2018. Upon remeasurement of the Oyster Creek ARO, Exelon and Generation recognized an $84 million and a $9 million pre-tax charge to Operating and maintenance expense in the third quarter of 2018 and in the second quarter of 2019, respectively. See Note 9 — Asset Retirement Obligations for additional information.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 2 — Mergers, Acquisitions, and Dispositions
Disposition of EGTP and Acquisition of Handley Generating Station (Exelon and Generation)
EGTP, a Delaware limited liability company, was formed in 2014 with the purpose of financing a portfolio of assets comprised of two combined-cycle gas turbines (CCGTs) and three peaking/simple cycle facilities consisting of approximately 3.4 GW of generation capacity in ERCOT North and Houston Zones. EGTP was an indirect wholly owned subsidiary of Exelon and Generation.
EGTP’s operating cash flows were negatively impacted by certain market conditions and the seasonality of its cash flows. On May 2, 2017, as a result of the negative impacts of certain market conditions and the seasonality of its cash flows, EGTP entered into a consent agreement with its lenders to permit EGTP to draw on its revolving credit facility and initiate an orderly sales process to sell the assets of its wholly owned subsidiaries. As a result, Exelon and Generation classified certain of EGTP assets and liabilities as held for sale at their respective fair values less costs to sell and recorded a $460 million pre-tax impairment loss. See Note 16 — Debt and Credit Agreements for details regarding the nonrecourse debt associated with EGTP and Note 11 — Asset Impairments for additional information.
On November 7, 2017, EGTP and all of its wholly owned subsidiaries filed voluntary petitions for relief under Chapter 11 of Title 11 of the United States Code in the United States Bankruptcy Court for the District of Delaware, which resulted in Exelon and Generation deconsolidating EGTP's assets and liabilities from their consolidated financial statements in the fourth quarter of 2017 that resulted in a pre-tax gain upon deconsolidation of $213 million. Concurrently with the Chapter 11 filings, Generation entered into an asset purchase agreement to acquire one of EGTP's generating plants, the Handley Generating Station, subject to a potential adjustment for fuel oil and assumption of certain liabilities. In the Chapter 11 Filings, EGTP requested that the proposed acquisition of the Handley Generating Station be consummated through a court-approved and supervised sales process. The acquisition closed on April 4, 2018 for a purchase price of $62 million. The Chapter 11 bankruptcy proceedings were finalized on April 17, 2018, resulting in the ownership of EGTP assets (other than the Handley Generating Station) being transferred to EGTP's lenders.
Disposition of Electrical Contracting Business (Exelon and Generation)
On February 28, 2018, Generation completed the sale of its interest in an electrical contracting business that primarily installs, maintains and repairs underground and high-voltage cable transmission and distribution systems for $87 million, resulting in a pre-tax gain which is included within Gain on sales of assets and businesses in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2018.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
3. Regulatory Matters (All Registrants) The following matters below discuss the status of material regulatory and legislative proceedings of the Registrants. Utility Regulatory Matters (Exelon and the Utility(All Registrants) Distribution Base Rate Case Proceedings The following tables show the completed and pending distribution base rate case proceedings in 2019.2021. Completed Distribution Base Rate Case Proceedings | | | | | | | | | | | | | | | | Registrant/Jurisdiction | Filing Date | Requested Revenue Requirement (Decrease) Increase | | Approved Revenue Requirement (Decrease) Increase | | Approved ROE | | Approval Date | Rate Effective Date | ComEd - Illinois (Electric)(a) | April 16, 2018 | $ | (23 | ) | | $ | (24 | ) | | 8.69 | % | | December 4, 2018 | January 1, 2019 | ComEd - Illinois (Electric)(a) | April 8, 2019 | (6 | ) | | (17 | ) | | 8.91 | % | | December 4, 2019 | January 1, 2020 | PECO - Pennsylvania (Electric) | March 29, 2018 | 82 |
| | 25 |
| | N/A |
| (b) | December 20, 2018 | January 1, 2019 | BGE - Maryland (Natural Gas) | June 8, 2018 (amended October 12, 2018) | 61 |
| | 43 |
| | 9.8 | % | | January 4, 2019 | January 4, 2019 | BGE - Maryland (Electric) | May 24, 2019 (amended December 17, 2019) | 74 |
| | 18 |
| | 9.7 | % | (d) | December 17, 2019 | December 17, 2019 | BGE - Maryland (Natural Gas) | May 24, 2019 (amended December 17, 2019) | 59 |
| | 45 |
| | 9.75 | % | (d) | December 17, 2019 | December 17, 2019 | ACE - New Jersey (Electric) | August 21, 2018 (amended November 19, 2018) | 122 |
| (c) | 70 |
| (c) | 9.6 | % | | March 13, 2019 | April 1, 2019 | Pepco - Maryland (Electric) | January 15, 2019 (amended May 16, 2019) | 27 |
| | 10 |
| | 9.6 | % | | August 12, 2019 | August 13, 2019 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Registrant/Jurisdiction | | Filing Date | | Service | | Requested Revenue Requirement (Decrease) Increase | | Approved Revenue Requirement (Decrease) Increase | | Approved ROE | | Approval Date | | Rate Effective Date | ComEd - Illinois(a) | | April 16, 2020 | | Electric | | $ | (11) | | | $ | (14) | | | 8.38 | % | | December 9, 2020 | | January 1, 2021 | | April 16, 2021 | | Electric | | 51 | | | 46 | | | 7.36 | % | | December 1, 2021 | | January 1, 2022 | PECO - Pennsylvania | | September 30, 2020 | | Natural Gas | | 69 | | | 29 | | | 10.24 | % | | June 22, 2021 | | July 1, 2021 | | March 30, 2021 | | Electric | | 246 | | | 132 | | | N/A(b) | | November 18, 2021 | | January 1, 2022 | BGE - Maryland(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 | % | | | Pepco - District of Columbia(d) | | May 30, 2019 (amended June 1, 2020) | | Electric | | 136 | | | 109 | | | 9.275 | % | | June 8, 2021 | | July 1, 2021 | Pepco - Maryland(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 | | | | | | | | | | | | | | | | ACE - New Jersey(f) | | December 9, 2020 (amended February 26, 2021) | | Electric | | 67 | | | 41 | | | 9.60 | % | | July 14, 2021 | | January 1, 2022 |
__________ | | (a) | (a)Pursuant to EIMA and FEJA, ComEd’s electric distribution rates are established through a performance-based formula, which sunsets at the end of 2022. See discussion of the Clean Energy Law below for details on the transition away from the electric distribution formula rate. The electric distribution formula rate includes decoupling provisions and, as a result, ComEd's electric distribution formula rate revenues are not impacted by abnormal weather, usage per customer, or number of customers. ComEd is required to file an annual update to its electric distribution formula rate on or before May 1st, with resulting rates effective in January of the following year. ComEd’s annual electric distribution formula rate update is based on prior year actual costs and current year projected capital additions (initial year revenue requirement). The update also reconciles any differences between the revenue requirement in effect for the prior year and actual costs incurred from the year (annual reconciliation).
st, with resulting rates effective in January of the following year. ComEd’s annual electric distribution formula rate update is based on prior year actual costs and current year projected capital additions (initial year revenue requirement). The update also reconciles any differences between the revenue requirement in effect for the prior year and actual costs incurred from the year (annual reconciliation).
|
ComEd’s 20182021 approved revenue requirement above reflects a decreasean increase of $58$50 million for the initial year revenue requirement for 20182021 and an increasea decrease of $34$64 million related to the annual reconciliation for 2017.2019. The revenue requirement for 2018 and the annual reconciliation for 2017 provides for a weighted average debt and equity return on distribution rate base of 6.52%2021
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
and the revenue requirement for 2019 provide for a weighted average debt and equity return on distribution rate base of 6.28% inclusive of an allowed ROE of 8.69%8.38%, reflecting the monthly average rate onyields for 30-year treasury notesbonds plus 580 basis points. points.
ComEd’s 20192022 approved revenue requirement above reflects an increase of $51$37 million for the initial year revenue requirement for 20192022 and a decreasean increase of $68$9 million related to the annual reconciliation for 2018.2020. The revenue requirement for 2019 and the annual reconciliation for 20182022 provides for a weighted average debt and equity return on distribution rate base of 6.51%5.72% inclusive of an allowed ROE of 8.91%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 average ratemonthly yields on 30-year treasury notesbonds plus 580 basis points less a performance metrics penalty of 7 basis points. See table below (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 ComEd's regulatory assets associated2021 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 utilized the tax benefits to fully offset the increases in 2021 and January 2022 such that customer rates remained unchanged. For the remainder of 2022, the MDPSC chose to offset 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 2023 has not been decided, and BGE cannot predict the outcome. (d)Reflects a cumulative multi-year plan with its18-months remaining in 2021 through 2022. The DCPSC awarded Pepco electric distribution formula rate.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.
(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. On February 23, 2022, the MDPSC chose to offset 25% of the cumulative revenue requirement increase through March 31, 2023. Whether certain tax benefits will be used to offset the customer rate increases for the twelve months ended March 31, 2024 has not been decided, and Pepco cannot predict the outcome.
During(f)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 firstthird quarter of 2018, ComEd revised its electric distribution formula rate to implement revenue decoupling provisions provided for under FEJA. As a result of this revision, ComEd’s electric distribution formula rate revenues are not impacted by abnormal weather, usage per customer or numbers of customers. ComEd began reflecting the impacts of this change in its Operating revenues and electric distribution formula rate regulatory asset in the first quarter of 2017.2021.
| | (b) | The PECO rate case proceeding was resolved through a settlement agreement, which did not specify an approved ROE. |
| | (c) | Requested and approved increases are before New Jersey sales and use tax. |
| | (d) | ROEs in approved settlement are for the purpose of calculating AFUDC and carrying charges. |
Pending Distribution Base Rate Case Proceedings | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Registrant/Jurisdiction | | Filing Date | | Service | | Requested Revenue Requirement Increase | | Requested ROE | | Expected Approval Timing | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | DPL - Delaware | | January 14, 2022 | | Natural Gas | | $ | 14 | | | 10.30 | % | | First quarter of 2023 | DPL - Maryland(a) | | September 1, 2021 (amended December 23, 2021) | | Electric | | 27 | | | 10.10 | % | | First quarter of 2022 | | | | | | | | | | | | __________ | | | | | | | | | Registrant/Jurisdiction | Filing Date | Requested Revenue Requirement Increase | Requested ROE | Expected Approval Timing | Pepco - District of Columbia (Electric)(a) | May 30, 2019 (amended September 16, 2019) | $ | 160 |
| 10.3 | % | Fourth quarter of 2020 | DPL - Maryland (Electric) | December 5, 2019 | 19 |
| 10.3 | % | Third quarter of 2020 |
(a)On January 24, 2022, DPL filed a settlement agreement with the MDPSC. The settlement provides for a revenue requirement increase of $13 million. The 9.60% ROE in the agreement is solely for the purposes of calculating AFUDC and regulatory asset carrying costs. On February 15, 2021, the Chief Public Utility Law Judge issued a proposed order approving the settlement agreement without modification. The proposed order will become a final order of the MDPSC on March 2, 2022, subject to modification or reversal by the MDPSC._________
| | (a) | Reflects a three-year cumulative multi-year plan and total requested revenue requirement increases of $84 million, $40 million and $36 million for years 2020, 2021, and 2022, respectively, to recover capital investments made in 2018 and 2019 and planned capital investments from 2020 to 2022. |
Transmission Formula Rates Transmission Formula Rate (Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE). ComEd’s, BGE’s, Pepco's, DPL's and ACE'sThe 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 formula rate update for ComEd is based on prior year actual costs and current year projected capital
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters additions (initial year revenue requirement). The annual update for PECO is based on prior year actual costs and current year projected capital additions, (initialaccumulated depreciation, and accumulated deferred income taxes. The annual update for BGE, Pepco, DPL, and ACE is based on prior year revenue requirement).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).
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
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 2019,2021, the following total increases/(decreases) were included in ComEd’s, BGE’s, Pepco's, DPL's and ACE'sthe Utility Registrants' electric transmission formula rate filings:updates: | | Registrant | Initial Revenue Requirement Increase/(Decrease) | Annual Reconciliation (Decrease)/Increase | Total Revenue Requirement Increase/(Decrease) |
| Allowed Return on Rate Base(c) | Allowed ROE(d) | | ComEd(a) | $ | 21 |
| $ | (16 | ) | $ | 5 |
|
| 8.21 | % | 11.50 | % | | Registrant(a) | | 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 | | ComEd | | $ | 33 | | | $ | 12 | | | $ | 45 | | | 8.20 | % | | 11.50 | % | PECO | | PECO | | (2) | | | 26 | | | 24 | | | 7.37 | % | | 10.35 | % | BGE(a) | (10 | ) | (23 | ) | (19 | ) | (b) | 7.35 | % | 10.50 | % | | 38 | | | 27 | | | 65 | | | 7.35 | % | | 10.50 | % | Pepco | 15 |
| 11 |
| 26 |
|
| 7.75 | % | 10.50 | % | Pepco | | (9) | | | 21 | | | 12 | | | 7.68 | % | | 10.50 | % | DPL | 17 |
| (1 | ) | 16 |
|
| 7.14 | % | 10.50 | % | DPL | | 19 | | | 33 | | | 52 | | | 7.20 | % | | 10.50 | % | ACE | 11 |
| (2 | ) | 9 |
|
| 7.79 | % | 10.50 | % | ACE | | 27 | | | 24 | | | 51 | | | 7.45 | % | | 10.50 | % |
__________ | | (a) | The time period for any formal challenges to the annual transmission formula rate update filings expired with no formal challenges submitted |
| | (b) | The change in BGE's transmission revenue requirement includes a FERC approved dedicated facilities charge of $14 million to recover the costs of providing transmission service to specifically designated load by BGE. |
| | (c) | Represents the weighted average debt and equity return on transmission rate bases. |
| | (d) | As part of the FERC-approved settlement of ComEd’s 2007 transmission rate case,(a)All rates are effective June 1, 2021 - May 31, 2022, subject to review by interested parties pursuant to review protocols of each Utility Registrant's 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 transmission 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 transmission formula rate is currently capped at 55%. As part of the FERC-approved settlement of the ROE complaint against BGE, Pepco, DPL and ACE, the rate of return on common equity is 10.50%, inclusive of a 50-basis-point incentive adder for being a member of a RTO. |
Transmission Formula Rate (Exelon and PECO). On May 1, 2017, PECO filed a request with FERC seeking approval to update its transmission rates and change the manner in which PECO’s transmission rate is determined from a fixed rate to a formula rate. The formula rate will be updated annually to ensure that under this rate customers pay the actual costs of providing transmission services. PECO’s initial formula rate filing included a requested increase of $22 million to PECO’s annual transmission revenue requirement, which reflected a ROE of 11%, inclusive of a 50 basis point adder for being a member of a RTO. On June 27, 2017, FERC issued an Order acceptingRTO, and the filingcommon equity component of the ratio used to calculate the weighted average debt and suspendingequity return for the proposed rates until December 1, 2017, subject to refund,transmission formula rate is currently capped at 55% and set55.75%, respectively. As part of the matter for hearingFERC-approved settlement of the ROE complaint against BGE, Pepco, DPL, and settlement judge procedures.
On December 5, 2019, FERC issued an Order accepting without modificationACE, the settlement agreement filed by PECO and other parties in July 2019. The settlement results in an increaserate of approximately $14 million with a return on rate base of 7.62% compared to PECO's initial formula rate filing and allows for an ROE of 10.35%common equity is 10.50%, inclusive of a 50 basis point50-basis-point incentive adder for being a member of thea RTO. The settlement did not have a material impact on PECO's 2017, 2018, or 2019 annual transmission revenue requirements. PECO will update its rates in 2020 and refund estimated overcollections totaling approximately $28 million related to the amounts billed under the proposed rates in effect since 2017.
Pursuant to the transmission formula rate request discussed above, PECO made its annual formula rate updates in May 2018 and 2019, which included a decrease of $6 million and an increase of $8 million, respectively, to the annual transmission revenue requirement. The updated transmission formula rates were effective on June 1, 2018 and 2019, respectively, subject to refund.
Other State Regulatory Matters Illinois Regulatory Matters Clean Energy Law (Exelon and ComEd). 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 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 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 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 Law are possible and Exelon and ComEd cannot reasonably predict the outcome of any such challenges. Carbon Mitigation Credit 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
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters authorized 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 participated in the CMC procurement process and were awarded contracts that commit each plant to operate through May 31, 2027. Pursuant to these contracts, ComEd will procure CMCs based upon the number of MWhs produced annually by each plant, subject to minimum performance requirements. 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 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 law 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 is required to purchase CMCs pursuant to these contracts and all its costs of doing so will be recovered through a new rider. That rider will provide for an annual reconciliation and true-up to actual costs incurred by ComEd to purchase CMCs, with any difference 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 Exelon’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 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 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. On February 3, 2022, the ICC approved a tariff that establishes the process under which ComEd will reconcile its 2022 and 2023 rate year revenue requirements with actual costs. Those reconciliation amounts will be determined using the same process as were used for prior reconciliations under the performance-based electric distribution formula rate. Using that process, for the years 2022 and 2023 ComEd will ultimately collect revenues from customers reflecting each year’s actual recoverable costs, year-end rate base, and a weighted average debt and equity return on distribution rate base, with the ROE component based on the annual average of the monthly yields of the 30-year United States Treasury bonds plus 580 basis points. 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. That reconciliation is subject to adjustment for certain expenses and, unless the plan is modified, to a 5% cap on increases in certain costs over the costs in 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. 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 initiate a docket to accelerate and fully credit to customers unprotected property related TCJA excess deferred income taxes no later than December 31, 2025. Energy Efficiency
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters The Clean Energy Law extends ComEd’s current cumulative annual energy efficiency MWh savings goals through 2040, adds expanded electrification measures to those goals, increases low-income commitments and adds a new performance adjustment to the energy efficiency formula rate. 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 rate over the weighted average useful life, as approved by the ICC, of the related energy efficiency measures. Energy Efficiency Formula Rate (Exelon and ComEd). FEJA allows ComEd to defer energy efficiency costs (except for any voltage optimization costs which are recovered through the electric distribution formula rate) as a separate regulatory asset that is recovered through the energy efficiency formula rate over the weighted average useful life, as approved by the ICC, of the related energy efficiency measures. ComEd earns a return on the energy efficiency regulatory asset at a rate equal to its weighted average cost of capital, which is based on a year-end capital structure and calculated using the same methodology applicable to ComEd’s electric distribution formula rate. Beginning January 1, 2018 through December 31, 2030, the return on equityROE that ComEd earns on its energy efficiency regulatory asset is subject to a maximum downward or upward adjustment of 200 basis points if ComEd’s
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
cumulative persisting annual MWh savings falls short of or exceeds specified percentage benchmarks of its annual incremental savings goal. ComEd is required to file an update to its energy efficiency formula rate on or before June 1st each year, with resulting rates effective in January of the following year. The annual update is based on projected current year energy efficiency costs, PJM capacity revenues, and the projected year-end regulatory asset balance less any related deferred income taxes (initial year revenue requirement). The update also reconciles any differences between the revenue requirement in effect for the prior year and actual costs incurred from the year (annual reconciliation). The approved energy efficiency formula rate also provides for revenue decoupling provisions similar to those in ComEd’s electric distribution formula rate. During 2019,2021, the ICC approved the following total increases in ComEd's requested energy efficiency revenue requirement: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Filing Date | | Requested Revenue Requirement Increase | | Approved Revenue Requirement Increase(a) | | Approved ROE | | Approval Date | | Rate Effective Date | June 1, 2021 | | $ | 54 | | | $ | 54 | | | 7.36 | % | | November 18, 2021 | | January 1, 2022 |
| | | | | | | | | | | | | Filing Date | Requested Revenue Requirement Increase | Approved Revenue Requirement Increase | | Approved ROE | Approval Date | Rate Effective Date | May 23, 2019 | $ | 51 |
| $ | 50 |
| (a) | 8.91 | % | November 26, 2019 | January 1, 2020 |
__________________(a)ComEd’s 2022 approved revenue requirement above reflects an increase of $55 million for the initial year revenue requirement for 2022 and a decrease of $1 million related to the annual reconciliation for 2020. The revenue requirement for 2022 provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 5.72% inclusive of an allowed ROE of 7.36%, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points. The revenue requirement for the 2020 reconciliation year provides for a weighted average debt and equity return on the energy efficiency asset and rate base of 6.26% inclusive of an allowed ROE of 8.46%, which includes an upward performance adjustment that increased the ROE. The performance adjustment can either increase or decrease the ROE based upon the achievement of energy efficiency savings goals. See table below for ComEd's regulatory assets associated with its energy efficiency formula rate.
| | (a) | ComEd’s 2020 approved revenue requirement above reflects an increase of $53 million for the initial year revenue requirement for 2020 and a decrease of $3 million related to the annual reconciliation for 2018. The revenue requirement for 2020 provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 6.51% inclusive of an allowed ROE of 8.91%, reflecting the average rate on 30-year treasury notes plus 580 basis points. See table below for ComEd's regulatory assets associated with its energy efficiency formula rate. |
Maryland Regulatory Matters Maryland Alternative Rate Plans RulemakingRevenue Decoupling (Exelon, BGE, PHI, Pepco, and DPL). In 1998, the MDPSC approved natural gas monthly rate adjustments for BGE and in 2007, the MDPSC approved electric monthly rate adjustments for BGE and BSAs for Pepco and DPL, all of which are decoupling mechanisms. As a result of the decoupling mechanisms, certain Operating revenues from electric and natural gas distribution at BGE and Operating revenues from electric distribution at Pepco Maryland (see also District of Columbia Revenue Decoupling below for Pepco District of Columbia) and DPL are not impacted by abnormal weather or usage per customer. For BGE, Pepco, and DPL, the decoupling mechanism eliminates the impacts of abnormal weather or customer usage by recognizing revenues based on an authorized distribution amount per customer by customer class. Operating revenues from electric and natural gas distribution at BGE and Operating revenues from electric distribution at Pepco Maryland and DPL are, however, impacted by changes in the number of customers. Maryland Order Directing the Distribution of Energy Assistance Funds (Exelon, BGE, PHI, Pepco, and DPL). On August 9, 2019,June 15, 2021, the MDPSC issued an order authorizing the disbursal of funds to utilities in which the MDPSC determined that it is now appropriate to move forward to implement alternative rate plans in Maryland. The MDPSC found that a multi-year rate plan, based on a historic test year and allowing up to three future test years, can produce just and reasonable rates. A working group was convened and submitted a detailed implementation report related to multi-year rate plans to the MDPSC on December 20, 2019. In response to the working group report, the MDPSC issued anaccordance with Maryland COVID-19 relief legislation. Under this order, on February 4, 2020 establishing a multi-year rate plan pilot and an associated framework for a Maryland utility to use in the pilot multi-year rate plan filing. The working group was required to continue and discuss how best to integrate performance-based measures into a multi-year rate plan. The working group is currently discussing performance-based measures which could be combined with future multi-year rate plans and will submit its report to the MDPSC by April 1, 2020. BGE, Pepco, and DPL cannot predict the outcomereceived funds of $50 million, $12 million, and $8 million, respectively, in July 2021. The funds have been used to reduce or the potential financial impact, if any, on BGE, Pepco or DPL.eliminate certain qualifying past-due residential customer receivables. The Maryland Strategic Infrastructure Development and Enhancement Program (Exelon and BGE). On December 1, 2017 (as amended on January 22, 2018), BGE filed an application with the MDPSC seeking approval for a new gas infrastructure replacement plan and associated surcharge, effective for the five-year period from 2019 through 2023. On May 30, 2018, the MDPSC approved with modifications a new infrastructure plan and associated surcharge, subject to BGE's acceptance of the Order. On June 1, 2018, BGE accepted the MDPSC Order and the associated surcharge became effective January 2019. The five-year plan calls for capital expenditures over the 2019-2023 timeframe of $732 million with an associated revenue requirement of $200 million.
Cash Working Capital Order (Exelon and BGE). On November 17, 2016, the MDPSC rendered a decision in the proceeding to review BGE’s request to recover its cash working capital (CWC) requirement for its Provider of Last Resort service, also known as Standard Offer Service (SOS), as well as other components that make up the Administrative Charge, the mechanism that enables BGE to recover its SOS-related costs. The Administrative Charge is comprised of five components: CWC, uncollectibles, incremental costs, return, and an administrative adjustment, which acts as a proxy for retail suppliers’ costs. The MDPSC accepted BGE's positions on recovery of CWC and pass-through recovery of BGE’s actual uncollectibles and incremental costs. The order also grants BGE a return on the SOS. Subsequently, the MDPSC Staff and residential consumer advocate sought clarification and appealed the amount of return awarded to BGE on the SOS. The appeal currently resides with the Maryland Court of Special Appeals. Also, in BGE’s 2019 electric and gas distribution base rate proceeding, the MDPSC established a normalized administrative adjustment. However, a group of electric suppliers appealed the MDPSC’s decision to the Circuit Court for Baltimore City. BGE cannot predict the outcome of these appeals.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
District of Columbia Regulatory Matters
District of Columbia Revenue Decoupling (Exelon, PHI, and Pepco). In 2009, the DCPSC approved a BSA, which is a decoupling mechanism. As a result of the decoupling mechanism, Operating revenues from electric distribution at Pepco District of Columbia (see also Maryland Revenue Decoupling above for Pepco Maryland) are not impacted by abnormal weather or usage per customer. The decoupling mechanism eliminates the impacts of abnormal weather or customer usage by recognizing revenues based on an authorized distribution amount per customer by customer class. Operating revenues from electric distribution at Pepco District of Columbia are, however, impacted by changes in the number of customers. New Jersey Regulatory Matters Conservation Incentive Program (CIP) (Exelon, PHI, and ACE). On September 25, 2020, ACE filed an application with the NJBPU as was required seeking approval to implement a portfolio of energy efficiency programs pursuant to New Jersey’s clean energy legislation. The filing included a request to implement a CIP that would eliminate the favorable and unfavorable impacts 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. 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. ACE Infrastructure Investment Program Filing (Exelon, PHI, and ACE). On February 28, 2018, ACE filed with the NJBPU the company’s Infrastructure Investment Program (IIP)IIP proposing to seek recovery of a series of investments through a new rider mechanism, totaling $338 million, between 2019-2022 to provide safe and reliable service for its customers. The IIP will allow for more timely recovery of investments made to modernize and enhance ACE’s electric system. On April 15, 2019, ACE entered into a settlement agreement with other parties, which allows for a recovery totaling $96 million of reliability related capital investments from July 1, 2019 through June 30, 2023. On April 18, 2019, the NJBPU approved the settlement agreement. 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. New Jersey Clean Energy Legislation (Exelon, PHI, and ACE). On May 23, 2018, New Jersey enacted legislation that established and modified New Jersey’s clean energy and energy efficiency programs and solar and renewable energy portfolio standards.RPS. On the same day, New Jersey enacted legislation that established a ZEC program that provides compensation for nuclear plants that demonstrate to the NJBPU that they meet certain requirements, including that they make a significant contribution to air quality in the state and that their revenues are insufficient to cover their costs and risks. Electric distribution utilities in New Jersey, including ACE, began collecting from retail distribution customers, through a non-bypassable charge, all costs associated with the utility’s procurement of the ZECs effective April 18, 2019. See Generation Regulatory Matters below for additional information.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters Other Federal Regulatory Matters Transmission-Related Income Tax Regulatory Assets (Exelon, ComEd, BGE, PHI, Pepco, DPL, and ACE). On December 13, 2016 (and as amended on March 13, 2017), BGE filed with FERC to begin recovering certain existing and future transmission-related income tax regulatory assets through its transmission formula rate. BGE’s existing regulatory assets included (1) amounts that, if BGE’s transmission formula rate provided for recovery, would have been previously amortized and (2) amounts that would be amortized and recovered prospectively. ComEd, Pepco, DPL and ACE had similar transmission-related income tax regulatory liabilities and assets also requiring FERC approval. On November 16, 2017, FERC issued an order rejecting BGE’s proposed revisions to its transmission formula rate to recover these transmission-related income tax regulatory assets. As a resultIn the fourth quarter of the FERC's order,2017, ComEd, BGE, Pepco, DPL, and ACE took a charge to Income tax expense within their Consolidated Statements of Operations and Comprehensive Income in the fourth quarter of 2017, reducingfully impaired their associated transmission-related income tax regulatory assets for the portion of the total transmission-related income tax regulatory assets that would have been previously amortized and recovered through rates. Similar regulatory assets and liabilities at PECO are not subject to the same FERC transmission rate recovery formula. See above for additional information regarding PECO's transmission formula rate filing.amortized. On December 18, 2017, BGE filed for clarification and rehearing of FERC’s November 16, 2017 order and on February 23, 2018 (as amended on July 9, 2018), ComEd, Pepco, DPL, and ACE each filed with FERC to revise their transmission formula rate mechanisms to permit recovery of transmission-related income tax regulatory assets, including those amounts that would have been previously amortized and recovered through rates had the transmission formula rate provided for such recovery. On September 7, 2018, FERC issued orders rejecting 1) BGE’s December 18,rehearing request of FERC's November 16, 2017 request for rehearingorder and clarification and ComEd's, Pepco's, DPL's and ACE's2) the February 23, 2018 (as amended on July 9, 2018) filings, citingfiling by ComEd, Pepco, DPL, and ACE for similar recovery. On November 2, 2018, BGE filed an appeal of FERC's September 7, 2018 order to the lackU.S. Court of timelinessAppeals for the D.C. Circuit. On March 27, 2020, the U.S. Court of Appeals for the requests to recover amounts that would have been previously amortized, but indicating that ongoing recovery of certain transmission-related income tax regulatory assets would provide for a more accurate revenue requirement, consistent with itsD.C. Circuit Court denied BGE’s November 16, 2017 order.2, 2018 appeal. On October 1, 2018, ComEd, BGE, Pepco, DPL, and ACE submitted filings to recover ongoing non-TCJA amortization amounts and refundcredit TCJA transmission-related income tax regulatory liabilities to customers for the prospective period starting on October 1, 2018. In addition, on October 9, 2018, ComEd, Pepco, DPL, and ACE sought rehearing of FERC's September 7, 2018 order. On November 2, 2018, BGE filed an appeal of FERC's September 7, 2018 order to the Court of Appeals for the D.C. Circuit. On April 26, 2019, FERC issued an order accepting ComEd's, BGE's, Pepco's, DPL's, and ACE's October 1, 2018 filings, effective October 1, 2018, subject to refund and established hearing and settlement judge procedures. On April 24, 2020, ComEd, BGE, Pepco, DPL, ACE, and ACE cannot predictother parties filed a settlement agreement with FERC, which FERC approved on September 24, 2020. The settlement agreement provides for the outcomerecovery of these proceedings. If FERC ultimately rules thatongoing transmission-related income tax regulatory assets and establishes the future, ongoing non-TCJAamount and amortization amounts are not recoverable, Exelon, ComEd, BGE, PHI, Pepco, DPLperiod for excess deferred income taxes resulting from TCJA. The settlement resulted in a reduction to Operating revenues and ACE would record additional chargesan offsetting reduction to Income tax expense which could be
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
up to approximately $79 million, $51 million, $17 million, $11 million, $4 million, $5 million and $2 million, respectively, as of December 31, 2019.
PJM Transmission Rate Design (All Registrants). On June 15, 2016, several parties, including the Utility Registrants, filed a proposed settlement with FERC to resolve outstanding issues related to cost responsibility for charges to transmission customers for certain transmission facilities that operate at or above 500 kV. The settlement included provisions for monthly credits or charges related to the periods prior to January 1, 2016 that are expected to be refunded or recovered through PJM wholesale transmission rates through December 2025. On May 31, 2018, FERC issued an order approving the settlement. Pursuant to the order, similar charges for the period January 1, 2016 through June 30, 2018 would also be refunded or recovered through PJM wholesale transmission rates over the subsequent 12-month period. PJM commenced billing the refunds and charges associated with this settlement in August 2018.
The Utility Registrants recorded the following payables to/receivables from PJM and related regulatory assets/liabilities in 2018 and have been refunding or recovering these amounts through electric distribution customer rates. Generation recorded a $41 million net payable to PJM and a pre-tax charge within Purchased power and fuel expense in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income.
| | | | | | | | | | | | | | | PJM Receivable | PJM Payable | Regulatory Asset | Regulatory Liability | Exelon | $ | 220 |
| $ | 176 |
| $ | 136 |
| $ | 221 |
| Generation(a) | — |
| 41 |
| — |
| — |
| ComEd | 122 |
| — |
| — |
| 122 |
| PECO | 85 |
| — |
| — |
| 85 |
| BGE | — |
| 51 |
| 51 |
| — |
| PHI | 13 |
| 84 |
| 85 |
| 14 |
| Pepco | — |
| 84 |
| 84 |
| — |
| DPL | 10 |
| — |
| — |
| 10 |
| ACE | 3 |
| — |
| 1 |
| 4 |
|
__________
| | (a) | Does not include an offsetting receivable from New Jersey Utilities of $16 million as of December 31, 2018. |
Regulatory Assets and Liabilities Regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent the excess recovery of costs or accrued credits that have been deferred because it is probable such amounts will be returned to customers through future regulated rates or represent billings in advance of expenditures for approved regulatory programs.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
The following tables provide information about the regulatory assets and liabilities of Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACEthe Registrants as of December 31, 20192021 and December 31, 2018:2020: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2021 | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Regulatory assets | | | | | | | | | | | | | | | | Pension and OPEB | $ | 2,409 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | Pension and OPEB - merger related | 893 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Deferred income taxes | 883 | | | — | | | 873 | | | — | | | 10 | | | 10 | | | — | | | — | | AMI programs - deployment costs | 145 | | | — | | | — | | | 89 | | | 56 | | | 30 | | | 26 | | | — | | AMI programs - legacy meters | 186 | | | 69 | | | — | | | 29 | | | 88 | | | 60 | | | 21 | | | 7 | | | | | | | | | | | | | | | | | | Electric distribution formula rate annual reconciliations | 44 | | | 44 | | | — | | | — | | | — | | | — | | | — | | | — | | Electric distribution formula rate significant one-time events | 104 | | | 104 | | | — | | | — | | | — | | | — | | | — | | | — | | Energy efficiency costs | 1,181 | | | 1,181 | | | — | | | — | | | — | | | — | | | — | | | — | | Fair value of long-term debt | 557 | | | — | | | — | | | — | | | 443 | | | — | | | — | | | — | | Fair value of PHI's unamortized energy contracts | 236 | | | — | | | — | | | — | | | 236 | | | — | | | — | | | — | | Asset retirement obligations | 145 | | | 99 | | | 21 | | | 19 | | | 6 | | | 5 | | | — | | | 1 | | MGP remediation costs | 283 | | | 266 | | | 8 | | | 9 | | | — | | | — | | | — | | | — | | Renewable energy | 219 | | | 219 | | | — | | | — | | | — | | | — | | | — | | | — | | Electric energy and natural gas costs | 96 | | | — | | | — | | | 49 | | | 47 | | | 29 | | | 13 | | | 5 | | Transmission formula rate annual reconciliations | 43 | | | — | | | 14 | | | 1 | | | 28 | | | — | | | 8 | | | 20 | | Energy efficiency and demand response programs | 564 | | | — | | | — | | | 283 | | | 281 | | | 199 | | | 79 | | | 3 | | | | | | | | | | | | | | | | | | Under-recovered revenue decoupling | 157 | | | — | | | — | | | 32 | | | 125 | | | 125 | | | — | | | — | | | | | | | | | | | | | | | | | | Removal costs | 758 | | | — | | | — | | | 143 | | | 615 | | | 147 | | | 109 | | | 360 | | DC PLUG charge | 70 | | | — | | | — | | | — | | | 70 | | | 70 | | | — | | | — | | Deferred storm costs | 49 | | | — | | | — | | | — | | | 49 | | | 3 | | | 3 | | | 43 | | COVID-19 | 82 | | | 28 | | | 33 | | | 8 | | | 13 | | | 10 | | | 3 | | | — | | Under-recovered credit loss expense | 89 | | | 60 | | | — | | | — | | | 29 | | | — | | | — | | | 29 | | Other | 327 | | | 135 | | | 42 | | | 30 | | | 130 | | | 57 | | | 18 | | | 23 | | Total regulatory assets | 9,520 | | | 2,205 | | | 991 | | | 692 | | | 2,226 | | | 745 | | | 280 | | | 491 | | Less: current portion | 1,296 | | | 335 | | | 48 | | | 215 | | | 432 | | | 213 | | | 68 | | | 61 | | Total noncurrent regulatory assets | $ | 8,224 | | | $ | 1,870 | | | $ | 943 | | | $ | 477 | | | $ | 1,794 | | | $ | 532 | | | $ | 212 | | | $ | 430 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2019 | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Regulatory assets | | | | | | | | | | | | | | | | Pension and other postretirement benefits | $ | 2,784 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| Pension and other postretirement benefits - Merger related | 1,138 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Deferred income taxes | 528 |
| | — |
| | 518 |
| | — |
| | 10 |
| | 10 |
| | — |
| | — |
| AMI programs - Deployment costs | 207 |
| | — |
| | — |
| | 129 |
| | 78 |
| | 43 |
| | 35 |
| | — |
| AMI programs - Legacy Meters | 276 |
| | 113 |
| | 12 |
| | 45 |
| | 106 |
| | 79 |
| | 27 |
| | — |
| Electric distribution formula rate annual reconciliations | 34 |
| | 34 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Electric distribution formula rate significant one-time events | 66 |
| | 66 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Energy efficiency costs | 746 |
| | 746 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Fair value of long-term debt | 650 |
| | — |
| | — |
| | — |
| | 523 |
| | — |
| | — |
| | — |
| Fair value of PHI's unamortized energy contracts | 443 |
| | — |
| | — |
| | — |
| | 443 |
| | — |
| | — |
| | — |
| Asset retirement obligations | 127 |
| | 85 |
| | 23 |
| | 16 |
| | 3 |
| | 2 |
| | — |
| | 1 |
| MGP remediation costs | 302 |
| | 287 |
| | 11 |
| | 4 |
| | — |
| | — |
| | — |
| | — |
| Renewable energy | 301 |
| | 301 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Electric Energy and Natural Gas Costs | 110 |
| | — |
| | 6 |
| | 36 |
| | 68 |
| | 43 |
| | 5 |
| | 20 |
| Transmission formula rate annual reconciliations | 11 |
| | — |
| | — |
| | 1 |
| | 10 |
| | 1 |
| | 2 |
| | 7 |
| Energy efficiency and demand response programs | 572 |
| | — |
| | — |
| | 303 |
| | 269 |
| | 196 |
| | 73 |
| | — |
| Merger integration costs | 32 |
| | — |
| | — |
| | 2 |
| | 30 |
| | 15 |
| | 8 |
| | 7 |
| Under-recovered revenue decoupling | 37 |
| | — |
| | — |
| | 8 |
| | 29 |
| | 29 |
| | — |
| | — |
| Securitized stranded costs | 37 |
| | — |
| | — |
| | — |
| | 37 |
| | — |
| | — |
| | 37 |
| Removal costs | 641 |
| | — |
| | — |
| | 67 |
| | 574 |
| | 152 |
| | 100 |
| | 324 |
| DC PLUG charge | 126 |
| | — |
| | — |
| | — |
| | 126 |
| | 126 |
| | — |
| | — |
| Other | 337 |
| | 129 |
| | 25 |
| | 26 |
| | 167 |
| | 76 |
| | 24 |
| | 29 |
| Total regulatory assets | 9,505 |
| | 1,761 |
| | 595 |
| | 637 |
| | 2,473 |
| | 772 |
| | 274 |
| | 425 |
| Less: current portion | 1,170 |
| | 281 |
| | 41 |
| | 183 |
| | 412 |
| | 188 |
| | 52 |
| | 57 |
| Total noncurrent regulatory assets | $ | 8,335 |
| | $ | 1,480 |
| | $ | 554 |
| | $ | 454 |
| | $ | 2,061 |
| | $ | 584 |
| | $ | 222 |
| | $ | 368 |
|
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2021 | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Regulatory liabilities | | | | | | | | | | | | | | | | Deferred income taxes | $ | 4,005 | | | $ | 2,105 | | | $ | — | | | $ | 819 | | | $ | 1,081 | | | $ | 525 | | | $ | 354 | | | $ | 202 | | Nuclear decommissioning | 3,357 | | | 2,760 | | | 597 | | | — | | | — | | | — | | | — | | | — | | Removal costs | 1,694 | | | 1,541 | | | — | | | 39 | | | 114 | | | 20 | | | 94 | | | — | | Electric energy and natural gas costs | 113 | | | 25 | | | 71 | | | — | | | 17 | | | 9 | | | 3 | | | 5 | | Transmission formula rate annual reconciliations | 8 | | | 7 | | | — | | | — | | | 1 | | | 1 | | | — | | | — | | Renewable portfolio standards costs | 500 | | | 500 | | | — | | | — | | | — | | | — | | | — | | | — | | Stranded costs | 35 | | | — | | | — | | | — | | | 35 | | | — | | | — | | | 35 | | Other | 292 | | | 6 | | | 61 | | | 102 | | | 58 | | | 8 | | | 15 | | | 10 | | Total regulatory liabilities | 10,004 | | | 6,944 | | | 729 | | | 960 | | | 1,306 | | | 563 | | | 466 | | | 252 | | Less: current portion | 376 | | | 185 | | | 94 | | | 26 | | | 68 | | | 14 | | | 25 | | | 28 | | Total noncurrent regulatory liabilities | $ | 9,628 | | | $ | 6,759 | | | $ | 635 | | | $ | 934 | | | $ | 1,238 | | | $ | 549 | | | $ | 441 | | | $ | 224 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2019 | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Regulatory liabilities | | | | | | | | | | | | | | | | Deferred income taxes | $ | 4,944 |
| | $ | 2,297 |
| | $ | — |
| | $ | 1,089 |
| | $ | 1,558 |
| | $ | 725 |
| | $ | 477 |
| | $ | 356 |
| Nuclear decommissioning | 3,102 |
| | 2,622 |
| | 480 |
| | ��� |
| | — |
| | — |
| | — |
| | — |
| Removal costs | 1,621 |
| | 1,435 |
| | — |
| | 58 |
| | 128 |
| | 20 |
| | 108 |
| | — |
| Electric Energy and Natural Gas Costs | 109 |
| | 45 |
| | 56 |
| | — |
| | 8 |
| | — |
| | 8 |
| | — |
| Transmission formula rate annual reconciliations | 34 |
| | 6 |
| | 28 |
| | — |
| | — |
| | — |
| | — |
| | — |
| Other | 582 |
| | 337 |
| | 37 |
| | 81 |
| | 83 |
| | 9 |
| | 18 |
| | 26 |
| Total regulatory liabilities | 10,392 |
| | 6,742 |
| | 601 |
| | 1,228 |
|
| 1,777 |
| | 754 |
| | 611 |
| | 382 |
| Less: current portion | 406 |
| | 200 |
| | 91 |
| | 33 |
| | 70 |
| | 8 |
| | 37 |
| | 25 |
| Total noncurrent regulatory liabilities | $ | 9,986 |
| | $ | 6,542 |
| | $ | 510 |
| | $ | 1,195 |
|
| $ | 1,707 |
| | $ | 746 |
| | $ | 574 |
| | $ | 357 |
|
210
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2020 | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Regulatory assets | | | | | | | | | | | | | | | | Pension and OPEB | $ | 3,010 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | Pension and OPEB - merger related | 1,014 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Deferred income taxes | 715 | | | — | | | 705 | | | — | | | 10 | | | 10 | | | — | | | — | | AMI programs - deployment costs | 174 | | | — | | | — | | | 109 | | | 65 | | | 35 | | | 30 | | | — | | AMI programs - legacy meters | 219 | | | 90 | | | — | | | 37 | | | 92 | | | 68 | | | 24 | | | — | | Electric distribution formula rate annual reconciliations | (14) | | | (14) | | | — | | | — | | | — | | | — | | | — | | | — | | Electric distribution formula rate significant one-time events | 117 | | | 117 | | | — | | | — | | | — | | | — | | | — | | | — | | Energy efficiency costs | 982 | | | 982 | | | — | | | — | | | — | | | — | | | — | | | — | | Fair value of long-term debt | 598 | | | — | | | — | | | — | | | 478 | | | — | | | — | | | — | | Fair value of PHI's unamortized energy contracts | 328 | | | — | | | — | | | — | | | 328 | | | — | | | — | | | — | | Asset retirement obligations | 135 | | | 92 | | | 21 | | | 18 | | | 4 | | | 3 | | | — | | | 1 | | MGP remediation costs | 285 | | | 271 | | | 10 | | | 4 | | | — | | | — | | | — | | | — | | Renewable energy | 301 | | | 301 | | | — | | | — | | | — | | | — | | | — | | | — | | Electric energy and natural gas costs | 95 | | | — | | | — | | | 23 | | | 72 | | | 37 | | | 5 | | | 30 | | Transmission formula rate annual reconciliations | 5 | | | — | | | — | | | 2 | | | 3 | | | — | | | 2 | | | 1 | | Energy efficiency and demand response programs | 572 | | | — | | | — | | | 289 | | | 283 | | | 203 | | | 80 | | | — | | | | | | | | | | | | | | | | | | Under-recovered revenue decoupling | 113 | | | — | | | — | | | 20 | | | 93 | | | 93 | | | — | | | — | | Stranded costs | 25 | | | — | | | — | | | — | | | 25 | | | — | | | — | | | 25 | | Removal costs | 701 | | | — | | | — | | | 107 | | | 594 | | | 151 | | | 105 | | | 339 | | DC PLUG charge | 100 | | | — | | | — | | | — | | | 100 | | | 100 | | | — | | | — | | Deferred storm costs | 50 | | | — | | | — | | | — | | | 50 | | | 5 | | | 4 | | | 41 | | COVID-19 | 81 | | | 22 | | | 38 | | | 10 | | | 11 | | | 7 | | | 4 | | | — | | Under-recovered credit loss expense | 107 | | | 89 | | | — | | | — | | | 18 | | | — | | | — | | | 18 | | Other | 274 | | | 78 | | | 27 | | | 30 | | | 147 | | | 72 | | | 26 | | | 15 | | Total regulatory assets | 9,987 | | | 2,028 | | | 801 | | | 649 | | | 2,373 | | | 784 | | | 280 | | | 470 | | Less: current portion | 1,228 | | | 279 | | | 25 | | | 168 | | | 440 | | | 214 | | | 58 | | | 75 | | Total noncurrent regulatory assets | $ | 8,759 | | | $ | 1,749 | | | $ | 776 | | | $ | 481 | | | $ | 1,933 | | | $ | 570 | | | $ | 222 | | | $ | 395 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2018 | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Regulatory assets | | | | | | | | | | | | | | | | Pension and other postretirement benefits | $ | 2,553 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| Pension and other postretirement benefits - Merger related | 1,266 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Deferred income taxes | 414 |
| | — |
| | 404 |
| | — |
| | 10 |
| | 10 |
| | — |
| | — |
| AMI programs - Deployment costs | 234 |
| | — |
| | — |
| | 145 |
| | 89 |
| | 50 |
| | 39 |
| | — |
| AMI programs - Legacy Meters | 328 |
| | 136 |
| | 24 |
| | 48 |
| | 120 |
| | 90 |
| | 30 |
| | — |
| Electric distribution formula rate annual reconciliations | 158 |
| | 158 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Electric distribution formula rate significant one-time events | 81 |
| | 81 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Energy efficiency costs | 472 |
| | 472 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Fair value of long-term debt | 702 |
| | — |
| | — |
| | — |
| | 569 |
| | — |
| | — |
| | — |
| Fair value of PHI's unamortized energy contracts | 561 |
| | — |
| | — |
| | — |
| | 561 |
| | — |
| | — |
| | — |
| Asset retirement obligations | 118 |
| | 79 |
| | 22 |
| | 16 |
| | 1 |
| | 1 |
| | — |
| | — |
| MGP remediation costs | 326 |
| | 309 |
| | 17 |
| | — |
| | — |
| | — |
| | — |
| | — |
| Renewable energy | 249 |
| | 249 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Electric Energy and Natural Gas Costs | 193 |
| | — |
| | 49 |
| | 51 |
| | 93 |
| | 84 |
| | — |
| | 9 |
| Transmission formula rate annual reconciliations | 41 |
| | 6 |
| | — |
| | 4 |
| | 31 |
| | 10 |
| | 14 |
| | 7 |
| Energy efficiency and demand response programs | 545 |
| | — |
| | 1 |
| | 289 |
| | 255 |
| | 188 |
| | 67 |
| | — |
| Merger integration costs | 42 |
| | — |
| | — |
| | 3 |
| | 39 |
| | 18 |
| | 11 |
| | 10 |
| Under-recovered revenue decoupling | 27 |
| | — |
| | — |
| | 2 |
| | 25 |
| | 25 |
| | — |
| | — |
| Securitized stranded costs | 50 |
| | — |
| | — |
| | — |
| | 50 |
| | — |
| | — |
| | 50 |
| Removal costs | 564 |
| | — |
| | — |
| | — |
| | 564 |
| | 158 |
| | 97 |
| | 309 |
| DC PLUG charge | 159 |
| | — |
| | — |
| | — |
| | 159 |
| | 159 |
| | — |
| | — |
| Deferred storm costs | 41 |
| | — |
| | — |
| | — |
| | 41 |
| | 9 |
| | 4 |
| | 28 |
| Other | 303 |
| | 110 |
| | 24 |
| | 17 |
| | 162 |
| | 79 |
| | 28 |
| | 13 |
| Total regulatory assets | 9,427 |
| | 1,600 |
| | 541 |
| | 575 |
|
| 2,769 |
| | 881 |
| | 290 |
| | 426 |
| Less: current portion | 1,190 |
| | 293 |
| | 81 |
| | 177 |
| | 457 |
| | 238 |
| | 59 |
| | 40 |
| Total noncurrent regulatory assets | $ | 8,237 |
| | $ | 1,307 |
| | $ | 460 |
| | $ | 398 |
|
| $ | 2,312 |
| | $ | 643 |
| | $ | 231 |
| | $ | 386 |
|
211
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2018 | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Regulatory liabilities | | | | | | | | | | | | | | | | Deferred income taxes | $ | 5,228 |
| | $ | 2,394 |
| | $ | — |
| | $ | 1,132 |
| | $ | 1,702 |
| | $ | 798 |
| | $ | 510 |
| | $ | 394 |
| Nuclear decommissioning | 2,606 |
| | 2,217 |
| | 389 |
| | — |
| | — |
| | — |
| | — |
| | — |
| Removal costs | 1,547 |
| | 1,368 |
| | — |
| | 52 |
| | 127 |
| | 20 |
| | 107 |
| | — |
| Electric Energy and Natural Gas Costs | 294 |
| | 137 |
| | 132 |
| | 6 |
| | 19 |
| | — |
| | 18 |
| | 1 |
| Other | 528 |
| | 227 |
| | 75 |
| | 79 |
| | 100 |
| | 11 |
| | 30 |
| | 25 |
| Total regulatory liabilities | 10,203 |
| | 6,343 |
| | 596 |
| — |
| 1,269 |
|
| 1,948 |
| | 829 |
| | 665 |
| | 420 |
| Less: current portion | 644 |
| | 293 |
| | 175 |
| | 77 |
| | 84 |
| | 7 |
| | 59 |
| | 18 |
| Total noncurrent regulatory liabilities | $ | 9,559 |
| | $ | 6,050 |
| | $ | 421 |
| | $ | 1,192 |
|
| $ | 1,864 |
| | $ | 822 |
| | $ | 606 |
| | $ | 402 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2020 | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Regulatory liabilities | | | | | | | | | | | | | | | | Deferred income taxes | $ | 4,502 | | | $ | 2,205 | | | $ | — | | | $ | 1,001 | | | $ | 1,296 | | | $ | 621 | | | $ | 404 | | | $ | 271 | | Nuclear decommissioning | 3,016 | | | 2,541 | | | 475 | | | — | | | — | | | — | | | — | | | — | | Removal costs | 1,649 | | | 1,482 | | | — | | | 47 | | | 120 | | | 20 | | | 100 | | | — | | | | | | | | | | | | | | | | | | Electric energy and natural gas costs | 175 | | | 34 | | | 97 | | | 6 | | | 38 | | | 24 | | | 10 | | | 4 | | Transmission formula rate annual reconciliations | 52 | | | 2 | | | 12 | | | — | | | 38 | | | 23 | | | 9 | | | 6 | | | | | | | | | | | | | | | | | | Renewable portfolio standards costs | 427 | | | 427 | | | — | | | — | | | — | | | — | | | — | | | — | | Stranded costs | 24 | | | — | | | — | | | — | | | 24 | | | — | | | — | | | 24 | | Other | 221 | | | 1 | | | 40 | | | 85 | | | 59 | | | 2 | | | 17 | | | 13 | | Total regulatory liabilities | 10,066 | | | 6,692 | | | 624 | | | 1,139 | | | 1,575 | | | 690 | | | 540 | | | 318 | | Less: current portion | 581 | | | 289 | | | 121 | | | 30 | | | 137 | | | 46 | | | 47 | | | 44 | | Total noncurrent regulatory liabilities | $ | 9,485 | | | $ | 6,403 | | | $ | 503 | | | $ | 1,109 | | | $ | 1,438 | | | $ | 644 | | | $ | 493 | | | $ | 274 | |
Descriptions of the regulatory assets and liabilities included in the tables above are summarized below, including their recovery and amortization periods. | | | | | | | | | | | | Line Item | Description | End Date of Remaining Recovery/Refund Period | Return | Pension and Other Postretirement BenefitsOPEB | Primarily reflects the Utility Registrants' and PHI's portion of deferred costs, including unamortized actuarial losses (gains) and prior service costs (credits), associated with Exelon's pension and other postretirement benefitOPEB plans, which are recovered through customer rates once amortized through net periodic benefit cost. Also, includes the Utility Registrants' and PHI's non–service cost components capitalized in Property, plant and equipment, net on their Consolidated Balance Sheets. | The deferred costs are amortized over the plan participants' average remaining service periods subject to applicable pension and other postretirementOPEB cost recognition policies. See Note 14 –15 — Retirement Benefits for additional information. The capitalized non–service cost components are amortized over the lives of the underlying assets. | No | Pension and Other Postretirement BenefitsOPEB - Merger Relatedmerger related | The deferred costs are amortized over the plan participants' average remaining service periods subject to applicable pension and other postretirementOPEB cost recognition policies. See Note 14 –15 — Retirement Benefits for additional information. The capitalized non–service cost components are amortized over the lives of the underlying assets. | Legacy Constellation - 2038 Legacy PHI - 2032 | No |
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
| | | | | | | | | | | | Line Item | Description | End Date of Remaining Recovery/Refund Period | Return | Deferred Income Taxesincome taxes | Deferred income taxes that are recoverable or refundable through customer rates, primarily associated with accelerated depreciation, the equity component of AFUDC, and the effects of income tax rate changes, including those resulting from the TCJA. These amounts include transmission-related regulatory liabilities that require FERC approval separate from the transmission formula rate. See Transmission-Related Income Tax Regulatory Assets section above for additional information. | Over the period in which the related deferred income taxes reverse, which is generally based on the expected life of the underlying assets. For TCJA, generally refunded over the remaining depreciable life of the underlying assets, except in certain jurisdictions where the commissions have approved a shorter refund period for certain assets not subject to IRS normalization rules. | No | AMI Programsprograms - Deployment Costs deployment costs
| Installation and ongoing incremental costs of new smart meters, including implementation costs at Pepco and DPL of dynamic pricing for energy usage resulting from smart meters.
| BGE - 2026 Pepco - 2027 DPL - 2030 ACE - To be determined in next distribution rate case filed with NJBPU | BGE, Pepco, DPL - Yes
ACE - Yes, on incremental costs of new smart meters | AMI Programsprograms - Legacy Meterslegacy meters | Early retirement costs of legacy meters. | ComEd - 2028 PECO - 2020
BGE - 2026 Pepco - 2027 DPL - 2030 ACE - To be determined in next distribution rate case filed with NJBPU | ComEd, Pepco (District of Columbia), DPL (Delaware), ACE - Yes PECO, BGE, Pepco (Maryland), DPL (Maryland) - No
| Electric distribution formula rate annual reconciliations
| Under-recoveriesUnder/(Over)-recoveries related to electric distribution service costs recoverable through ComEd's performance-based formula rate, which is updated annually with rates effective on January 1st.
| 2021
2023
| Yes | Electric distribution formula rate significant one-time events
| Under-recoveries of electricDeferred distribution service costs related to ComEd's significant one-time events (e.g., storm costs), which are recovered over 5 years from date of the event. | 20232025 | Yes |
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters | | | | | | | | | | | | Line Item | Description | End Date of Remaining Recovery/Refund Period | Return | Energy Efficiency Costsefficiency costs
| ComEd's costs recovered through the energy efficiency formula rate tariff and the reconciliation of the difference of the revenue requirement in effect for the prior year and the revenue requirement based on actual prior year costs. Deferred energy efficiency costs are recovered over the weighted average useful life of the related energy measure. | 20292032 | Yes
|
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
| | | | | Line Item | Description | End DateFair value of Remaining Recovery/Refund Period | Return | Fair Value of Long-Term Debt
long-term debt
| Represents the difference between the carrying value and fair value of long-term debt of BGE and PHI and BGE of $523$114 million and $127$443 million, respectively, as of December 30, 201931, 2021, and $569$120 million and $133$478 million, respectively, as of December 30, 2018,31, 2020, as of the PHI and Constellation merger dates. | BGE - 2043 2036 PHI - 2045 | No | Fair Valuevalue of PHI’s Unamortized Energy Contracts unamortized energy contracts
| Represents the regulatory assets recorded at Exelon and PHI offsetting the fair value adjustment related to Pepco's, DPL's, and ACE's electricity and natural gas energy supply contracts recorded at PHI as of the PHI merger date. | 2036 | No | Asset Retirement Obligationsretirement obligations | Future legally required removal costs associated with existing asset retirement obligations.AROs. | Over the life of the related assets. | Yes, once the removal activities have been performed. | MGP Remediation Costs remediation costs
| Environmental remediation costs for MGP sites. sites recorded at ComEd, PECO, and BGE.
| Over the expected remediation period. See Note 18 -19 — Commitments and Contingencies for additional information. | ComEd, PECO - No | Renewable Energyenergy | Represents the change in fair value of ComEd‘s 20-year floating-to-fixed long-term renewable energy swap contracts. | 2032
| No | Electric Energyenergy and Natural Gas Costsnatural gas costs | Under (over) recoveries-recoveries related to energy and gas supply related costs recoverable (refundable) under approved rate riders. | 2025 | DPL (Delaware), ACE - Yes ComEd, PECO, BGE, Pepco, DPL (Maryland) - No | Transmission formula rate annual reconciliations
| Under (over)-recoveries related to transmission service costs recoverable through the Utility Registrants’ FERC formula rates, which are updated annually with rates effective each June 1st.
| 20212023 | Yes | Energy efficiency and demand response programs
| Includes under (over)-recoveries of costs incurred related to energy efficiency programs and demand response programs and recoverable costs associated with customer direct load control and energy efficiency and conservation programs that are being recovered from customers.
| PECO - 20212025 BGE - 20242026 Pepco, DPL - 20342036 ACE - 2031 | BGE, Pepco, DPL, ACE - Yes PECO - Yes on capital investment recovered through this mechanism
| | | | |
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
| | | | | | | | | | | | Line Item | Description | End Date of Remaining Recovery/Refund Period | Return | Merger Integration CostsUnder-recovered revenue decoupling
| Integration costs to achieve distribution synergies related to the Constellation merger and PHI acquisition. Costs for Pepco (Maryland) and Pepco (District of Columbia) were $6 million and $9 million, respectively as of December 31, 2019 and $9 million each as of December 31, 2018. | BGE - 2021
Pepco - 2021
DPL- 2023
ACE - 2022
| BGE, Pepco (Maryland), DPL - Yes
Pepco (District of Columbia), ACE - No
| Under (Over)-Recovered Revenue Decoupling
| Electric and / or gas distribution costs recoverable from or (refundable) to customers under decoupling mechanisms. | BGE - 2022 Pepco (Maryland) - $22 million - 2022 Pepco (District of Columbia) - $103 million: $66 million to be recovered via monthly surcharge by 2024; $37 million to be recovered via monthly surcharge, estimated to be fully recovered by 2028 | BGE and Pepco and DPL - 2020 | BGE, Pepco, DPL- No | Securitized Stranded Costs
costs
| RepresentsThe regulatory asset represents certain stranded costs associated with ACE's former electricity generation business.
The regulatory liability represents overcollection of a customer surcharge collected by ACE to fund principal and interest payments on Transition Bonds of ACE Transition Funding that securitized such costs. | Stranded costs - 2022
Overcollection - To be determined by refund mechanism filing with NJBPU | Stranded costs - Yes
Overcollection - No | Removal Costs costs
| For BGE, PHI, Pepco, DPL, and ACE, the regulatory asset represents costs incurred to remove property, plant and equipment in excess of amounts received from customers through depreciation rates. For ComEd, BGE, PHI, Pepco, and DPL, the regulatory liability represents amounts received from customers through depreciation rates to cover the future non–legally required cost to remove property, plant and equipment, which reduces rate base for ratemaking purposes. | BGE, PHI, Pepco, DPL, and ACE - Asset is generally recovered over the life of the underliningunderlying assets.
ComEd, BGE, PHI, Pepco, and DPL - The liabilityLiability is reduced as costs are incurred.
| Yes | DC PLUG Charge charge
| Costs associated with the District of Columbia Power Line Undergrounding (DC PLUG),DC PLUG, which is a projected six year,six-year, $500 million project to place underground some of the District of Columbia’s most outage-prone power lines with $250 million of the project costs funded by Pepco and $250 million funded by the District of Columbia. Rates for the DC PLUG initiative went into effect on February 7, 2018. | 2020 - $30M
$67 million to be determined based on future biennial plans filed with the DCPSC. 2024 | Portion of asset funded by Pepco-Yes
|
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
| | | | | | | | | | | | Line Item | Description | End Date of Remaining Recovery/Refund Period | Return | Deferred Storm Costsstorm costs | For Pepco, DPL, and ACE amounts represent total incremental storm restoration costs incurred due to major storm events recoverable from customers in the Maryland and New Jersey jurisdictions. | Pepco - 2024
DPL - 2023$1 million - 2025; $2 million to be determined in pending distribution rate case filed with MDPSC
ACE - 2022$36 million - 2024; $7 million to be determined in next distribution rate case filed with NJBPU | Pepco, DPL - Yes
ACE - No
| Nuclear Decommissioning decommissioning
| Estimated future decommissioning costs for the Regulatory Agreement Units that are less than the associated NDT fund assets. See Note 9 -10 — Asset Retirement Obligations for additional information. | Not currently being refunded.
| No | COVID-19 | Incremental credit losses and direct costs related to COVID-19 incurred primarily in 2020 at the Utility Registrants, partially offset by a decrease in travel costs at BGE, Pepco and DPL. Direct costs consisted 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. | ComEd - 2025
BGE - 2025
PECO - 2024
Pepco (District of Columbia) - $8 million to be determined in next distribution rate case filed with DCPSC
Pepco (Maryland) - $1 million - 2026; $1 million to be determined in next distribution rate case filed with MDPSC
DPL (Maryland) - $1 million to be determined in pending distribution rate case filed with MDPSC
DPL (Delaware) - $2 million to be determined in next distribution rate case filed with DEPSC | ComEd and BGE - Yes
PECO, Pepco, and DPL - No |
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters | | | | | | | | | | | | Line Item | Description | End Date of Remaining Recovery/Refund Period | Return | Under-recovered credit loss expense | For ComEd and ACE, amounts represent the difference between annual credit loss expense and revenues collected in rates through ICC and NJBPU-approved riders. The difference between net credit loss expense and revenues collected through the rider each calendar year for ComEd is recovered over a twelve-month period beginning in June of the following calendar year. ACE intends to recover from June through May of each respective year, subject to approval of the NJBPU. | ComEd - 2024
ACE - To be determined in next Societal Benefits Rider filing with NJBPU | No | Renewable portfolio standards costs | Represents an overcollection of funds from both ComEd customers and alternative retail electricity suppliers to be spent on future renewable energy procurements. | $432 million to be determined in the ICC annual reconciliation for 2023
$68 million to be determined based on the LTRRPP developed by the IPA | No |
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's and the Utility Registrant'sRegistrants' Consolidated Balance Sheets. These amounts will be recognized as revenues in the related Consolidated Statements of Operations and Comprehensive Income in the periods they are billable to ourthe Utility Registrants' customers. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exelon | | ComEd(a) | | PECO | | BGE(b) | | PHI | | Pepco(c) | | DPL(c) | | ACE | December 31, 2019 | $ | 63 |
| | $ | 3 |
| | $ | — |
| | $ | 53 |
| | $ | 7 |
| | $ | 4 |
| | $ | 3 |
| | $ | — |
| | | | | | | | | | | | | | | | | December 31, 2018 | $ | 65 |
| | $ | 8 |
| | $ | — |
| | $ | 49 |
| | $ | 8 |
| | $ | 5 |
| | $ | 3 |
| | $ | — |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exelon | | ComEd(a) | | PECO | | BGE(b) | | PHI | | Pepco(c) | | DPL(c) | | ACE | December 31, 2021 | $ | 43 | | | $ | 1 | | | $ | — | | | $ | 37 | | | $ | 5 | | | $ | 3 | | | $ | 2 | | | $ | — | | December 31, 2020 | 51 | | | (1) | | | — | | | 45 | | | 7 | | | 4 | | | 3 | | | — | |
__________ | | (a) | Reflects ComEd's unrecognized equity returns earned 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 Programs and Energy Efficiency and Demand Response Programs. The earnings on energy efficiency are on Pepco DC and DPL DE programs only. |
(a)Reflects ComEd's unrecognized 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 Programs and Energy Efficiency and Demand Response Programs. The earnings on energy efficiency are on Pepco DC and DPL DE programs only. Generation Regulatory Matters (Exelon(Exelon) Impacts of the February 2021 Extreme Cold Weather Event and Generation)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. In response to the high demand and significantly reduced total generation on the system, the PUCT directed ERCOT to use an administrative price cap of $9,000 per MWh during firm load shedding events. The estimated impact to Exelon's Net Income for the year ended December 31, 2021 arising from these market and weather conditions was a reduction of approximately $800 million. The ultimate impact to Exelon's
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters consolidated financial statements may be affected by a number of factors, including the impacts of customer and counterparty defaults and recoveries, any additional solutions to address the financial challenges caused 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 with 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 notice 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 and reply brief on November 5, 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 cannot reasonably predict the outcome of these proceedings or the potential financial statement impact. Due to the event, a number of ERCOT market participants experienced bankruptcies or defaulted on payments to ERCOT, resulting in approximately a $3.0 billion payment shortfall in collections, which is allocated to the remaining ERCOT market participants. As of December 31, 2021, Exelon has recorded Generation's estimated portion of this obligation, net of legislative solutions, of approximately $17 million on a discounted basis, which is to be paid over a term of 83 years. ERCOT rules historically have limited recovery of default from market participants to $2.5 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 as to the imposition of uplift charges. On March 8, 2021, a third party filed a notice of appeal in the Court of Appeals for the Third District of Texas challenging the validity of the PUCT's order to ERCOT in February 2021. Generation intervened in that appeal and filed its initial brief on July 7, 2021. The case has been stayed until March 3, 2022 to afford time for the PUCT to respond to ERCOT's November 18, 2021 request that the PUCT withdraw its February 2021 order. On May 7, 2021, Generation filed a declaratory action and request for judicial review 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 cannot reasonably predict the outcome of these proceedings or the potential financial statement impact. 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 per 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 a 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, which Generation completed timely, and will be followed by a second phase consisting of a year-round set of weather preparedness standards to be informed by a weather study conducted by ERCOT and submitted to the PUCT on December 15, 2021. 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. Throughout 2021, Exelon and others submitted various proposals to the PUCT with respect to a range of potential market reforms,
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters 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 December 2, 2021, the PUCT reduced ERCOT’s high system-wide offer cap to $5,000 per MWh. 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, and on December 6, 2021 the related D.C. Circuit petition for review was withdrawn. 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 January 20, 2022, a unanimous settlement that was filed with the KCC that amended previously filed October 8, 2021 and November 30, 2021 nonunanimous settlements that, if approved, would resolve this matter. Exelon cannot predict the outcome of the KCC proceeding. Illinois Regulatory Matters Zero Emission Standard.Clean Energy Law. Pursuant to FEJA, on January 25, 2018, the ICC announced that Generation’s Clinton Unit 1, Quad Cities Unit 1 and Quad Cities Unit 2 nuclear plants were selected as the winning bidders through the IPA's ZEC procurement event.
Generation executed the ZEC procurement contracts with Illinois utilities, including ComEd, effective January 26, 2018 and began recognizing revenue with compensationSee Clean Energy Law above for the sale of ZECs retroactive to the June 1, 2017 effective date of FEJA. The ZEC price was initially established at $16.50 per MWh of production, subject to annual future adjustments determined by the IPA for specified escalation and pricing adjustment mechanisms designed to lower the ZEC price based on increases in underlying energy and capacity prices. Illinois utilities are required to purchase all ZECs delivered by the zero-emissions nuclear-powered generating facilities, subject to annual cost caps. For the initial delivery year, June 1, 2017 to May 31, 2018, and subsequent delivery year, June 1, 2018 to May 31, 2019, the ZEC annual cost cap was set at $235 million (ComEd’s share is approximately $170 million). For subsequent delivery years, the IPA-approved targeted ZEC procurement amounts will change based on forward energy and capacity prices. ZECs delivered to Illinois utilities in excess of the annual cost cap may be paid in subsequent years if the payments do not exceed the prescribed annual cost cap for that year. During the first quarter of 2018, Generation recognized $150 million of revenueadditional information related to ZECs generated from June 1, 2017 through December 31, 2017.
On February 14, 2017, two lawsuits were filed in the Northern District ofGeneration. See Note 7 – Early Plant Retirements for additional information on Generation’s Illinois against the IPA alleging that the state’s ZEC program violates certain provisions of the U.S. Constitution. Both lawsuits argued that the Illinois ZEC program would distort PJM's FERC-approved energy and capacity market auction system of setting wholesale prices and sought a permanent injunction preventing the implementation of the program. The lawsuits were dismissed by the district court on July 14, 2017. On September 13, 2018, the U.S. Circuit Court of Appeals for the Seventh Circuit affirmed the lower court's dismissal of both lawsuits. On January 7, 2019, plaintiffs filed a petition seeking U.S. Supreme Court review of the case, which was denied on April 15, 2019.nuclear plants.
New Jersey Regulatory Matters New Jersey Clean Energy Legislation. On May 23, 2018, New Jersey enacted legislation that established a ZEC program that will provideprovides compensation for nuclear plants that demonstrate to the NJBPU that they meet certain requirements, including that they make a significant contribution to air quality in the state and that their revenues are insufficient to cover their costs and risks. Under the legislation, the NJBPU will issue ZECs to qualifying nuclear power plants and the electric distribution utilities in New Jersey, including ACE, will be required to purchase those ZECs. Selected nuclear plants will receive annual ZEC payments for each energy year (12-month period from June 1 through May 31) within 90 days after the completion of such energy year. The quantity of ZECs issued will be
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
determined based on the greater of 40% of the total number of MWh of electricity distributed by the public electric distribution utilities in New Jersey in the prior year, or the total number of MWh of electricity generated in the prior year by the selected nuclear power plants. The ZEC price is approximately $10 per MWh during the first 3-year eligibility period. For eligibility periods following the first 3-year eligibility period, the NJBPU has discretion to reduce the ZEC price.
On November 19, 2018, NJBPU issued an order providing for the method and application process for determining the eligibility of nuclear power plants, a draft method and process for ranking and selecting eligible nuclear power plants, and the establishment of a mechanism for each regulated utility to purchase ZECs from selected nuclear power plants. On December 19, 2018, PSEG filed complete applications seeking NJBPU approval for Salem 1 and Salem 2, of which Generation owns a 42.59% ownership interest, to participate in the ZEC program. On April 18, 2019, the NJBPU approved the award of ZECs to Salem 1 and Salem 2. Upon approval, Generation began recognizing revenue for the sale of New Jersey ZECs in the month they are generated and has recognized $53 milliongenerated. 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 year ended December 31, 2019.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 15, 2019,11, 2021, the New Jersey Rate Counsel appealed the NJBPU’sApril 27, 2021 decision to the Superior Court of New Jersey Superior Court. TheAppellate Division. Briefing on the appeal does not prevent implementationis expected to conclude in the first half of the ZEC program.2022. Exelon and Generation cannot reasonably predict the outcome of the appeal. See Note 6 - Early Plant Retirements for additional information related to Salem.
New York Regulatory Matters
New York Clean Energy Standard. On August 1, 2016, the NYPSC issued an order establishing the New York CES, a component of which is a Tier 3 ZEC program targeted at preserving the environmental attributes of zero-emissions nuclear-powered generating facilities that meet the criteria demonstrating public necessity as determined by the NYPSC to be Generation's FitzPatrick, Ginna and Nine Mile Point nuclear facilities. The New York State Energy Research and Development Authority (NYSERDA) centrally procures the ZECs through a 12-year contract extending from April 1, 2017 through March 31, 2029, administered in six two-year tranches. ZEC payments are made based upon the number of MWh produced by each facility, subject to specified caps and minimum performance requirements. The ZEC price for the first tranche was set at $17.48 per MWh of production and is administratively determined using a formula based on the social cost of carbon as determined in 2016 by the federal government, subject to pricing adjustments designed to lower the ZEC price based on increases in underlying energy and capacity prices. Following the first tranche, the price will be updated bi-annually. Each Load Serving Entity (LSE) is required to purchase an amount of ZECs from NYSERDA equivalent to its load ratio share of the total electric energy in the New York Control Area. Cost recovery from ratepayers is incorporated into the commodity charges on customer bills.this proceeding.
On October 19, 2016, a coalition of fossil-generation companies filed a complaint in federal district court against the NYPSC alleging that the ZEC program violates certain provisions of the U.S. Constitution; specifically, that the ZEC program interferes with FERC’s jurisdiction over wholesale rates and that it discriminates against out of state competitors, which was dismissed by the district court on July 25, 2017. On September 27, 2018, the U.S. Court of Appeals for the Second Circuit affirmed the lower court's dismissal of the complaint against the ZEC program. On January 7, 2019, the fossil-generation companies filed a petition seeking U.S. Supreme Court review of the case which was denied on April 15, 2019.
In addition, on November 30, 2016 (as amended on January 13, 2017), a group of parties filed a Petition in New York State court seeking to invalidate the ZEC program, which argued that the NYPSC did not have authority to establish the program, that it violated state environmental law and that it violated certain technical provisions of the State Administrative Procedures Act when adopting the ZEC program. Subsequently, Generation, CENG and the NYPSC filed motions to dismiss the state court action, which were later opposed by the plaintiffs. On January 22, 2018, the court dismissed the environmental claims and the majority of the plaintiffs from the case but denied the motions to dismiss with respect to the remaining five plaintiffs and claims, without commenting on the merits of the case. On October 8, 2019, the court dismissed all remaining claims. The petitioners filed a notice of appeal on November 4, 2019 and have until May 4, 2020 to file their brief.
See Note 6 — Early Plant Retirements for additional information related to Ginna and Nine Mile Point, and Note 2 — Mergers, Acquisitions and Dispositions for additional information on Generation's acquisition of FitzPatrick.
Ginna Nuclear Power Plant Reliability Support Services Agreement. In November 2014, in response to a petition filed by Ginna regarding the possible retirement of Ginna, the NYPSC directed Ginna and Rochester Gas
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
& Electric Company (RG&E) to negotiate a RSSA to support the continued operation of Ginna to maintain the reliability of the RG&E transmission grid for a specified period of time.
On April 8, 2016, FERC accepted Ginna’s compliance filing and on April 20, 2016, the NYPSC accepted the revised RSSA with a term expiring on March 31, 2017. In April 2016, Generation began recognizing revenue based on the final approved pricing contained in the RSSA and also recognized a one-time revenue adjustment of $101 million representing the net cumulative previously unrecognized amount of revenue retroactive from the April 1, 2015 effective date through March 31, 2016. A 49.99% portion of the one-time adjustment was removed from Generation’s results of operations as a result of the noncontrolling interests in CENG.
The RSSA required Ginna to continue operating through the RSSA term. On September 30, 2016, Ginna filed the required notice with the NYPSC of its intent to continue operating beyond the March 31, 2017 expiry of the RSSA, conditioned upon successful execution of an agreement between Ginna and NYSERDA for the sale of ZECs under the New York CES. Subject to prevailing over any administrative or legal challenges, it is expected the New York CES will allow Ginna to continue to operate through the end of its current operating license in 2029. See Note 6 — Early Plant Retirements for additional information regarding the impacts of a decision to early retire a nuclear plant.
Federal Regulatory Matters PJM and NYISO MOPR Proceedings. PJM and NYISO capacity markets include a Minimum Offer Price Rule (MOPR).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 continues to applyapplies only to certain new gas-fired resources.resources in downstate New York. In January 2017 and May 2018, EPSA filed pleadings at FERC that generally allege that the NYISO and PJM MOPRs should be expanded to apply to existing resources including those receiving ZEC compensation under the New Jersey ZEC (Salem), New York CES (FitzPatrick, Ginna and Nine Mile Point) and Illinois ZES (Quad Cities) programs. For Generation’s nuclear facilities in PJM and NYISO that are currently receiving ZECstate-supported compensation, for carbon-free attributes, an expanded MOPR would require exclusion of ZECsuch compensation when bidding into future capacity auctions, resulting in an increased risk of these facilities not receiving capacity revenues in future auctions. Exelon filed protests at FERC in response to each filing, arguing generally that ZEC payments provide compensation for an environmental attribute and are no different than other renewable support programs that have generally not been subject to a MOPR.
On December 19, 2019, FERC issued an order in therequired PJM MOPR proceeding thatto broadly appliesapply the MOPR to all new and existing resources including nuclear, renewables, demand response, energy efficiency, storage, and all resources owned by vertically-integrated utilities,utilities. This greatly expandingexpanded the breadth and scope of PJM’s MOPR, which became effective as of PJM’s next capacity auction for the timing of which cannot be predicted at this time. FERC directed PJM to make a compliance filing within 90 days. FERC has no deadline for acting on PJM’s compliance filing.2022-2023 planning year. While FERC included some limited exemptions, (generally available to existing renewable, energy efficiency, demand response, storage and existing vertically-integrated utility resources) in its order, no exemptions were available to state-supported nuclear resources. In addition, FERC provided no new mechanism for accommodating state-supported resources other than the existing FRR mechanism under(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. Unless Illinoiszone). In response to FERC’s order, PJM submitted a compliance filing on March 18, 2020 wherein PJM proposed tariff language interpreting and New Jersey can implementimplementing 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 FRR programorder 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 their PJM zones,this proceeding, which remain pending before the Court of Appeals for the Seventh Circuit. As a result, the MOPR will applyapplied 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, orand the New Jersey ZEC program, as applicable, resultingprogram. The MOPR prevented Quad Cities from clearing in higher offers for those units that may not clearcapacity auction. At the direction of the PJM Board of Managers, PJM and its stakeholders developed further MOPR reforms to ensure that the capacity market. On January 21, 2020, Exelon,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, a numberon September 29, 2021, PJM's proposed MOPR reforms became effective by operation of other entities submitted individual requestslaw. Under the new tariff provisions, the MOPR will no longer apply to any of Generation’s owned or jointly owned nuclear plants. Requests for rehearing of FERC’s December 19, 2019notice establishing the effective date for PJM’s proposed market reforms were filed in October 2021 and denied by operation of law on November 4, 2021. Several parties have filed petitions for review of FERC's orders in this proceeding, which remain pending before the Court of Appeals for the Third Circuit. Exelon is strenuously opposing these appeals. Exelon cannot predict the outcome of this proceeding.
On February 20, 2020, FERC issued an order rejecting requests to expand NYISO’s version of the MOPR (referred 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 PJM MOPR. FERC routinely extendsMOPR in NYISO to apply to all resources, new and existing, across the deadline by which it must address requests for rehearing. FERC has not yet acted, and has no deadline by which it must act,entire NYISO market. Exelon is strenuously opposing expansion of FERC’s MOPR policies in the NYISO proceeding. Exelonmarket. While it is currently working withtoo early in the proceeding to predict its outcome and there are significant differences between the NYISO and PJM and other stakeholders to pursuemarkets that would justify a different result, if FERC applies the FRR option prior toMOPR in NYISO broadly as requested in the nextcomplaint, Generation’s facilities in NYISO that are receiving ZEC compensation may be at increased risk of not clearing the capacity auction in PJM. If Illinois implements the FRR option, Generation’s Illinois nuclear plants could be removed from PJM’s capacity auction and instead supply capacity and be compensated under the FRR program, which has the potential to mitigate the current economic distress being experienced by Generation's nuclear plants in Illinois, as discussed in Note 6 — Early Plant Retirements. Implementing the FRR program in Illinois will require both legislative
auction.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
and regulatory changes. Legislation may be introduced in New Jersey as well. Exelon cannot predict whether such legislative and regulatory changes can be implemented prior to the next capacity auction in PJM.
If Generation’s state-supported nuclear plants in PJM or NYISO are subjected to the MOPR without compensation under an FRR or similar program, it could have a material adverse impact on Exelon's and Generation's financial statements.
Operating License Renewals Conowingo Hydroelectric Project. On August 29, 2012, Generation submitted a hydroelectric licensean application to FERC 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 401 of the Clean Water Act (401 Certification) from MDE for Conowingo, Generation hashad been working with MDE and other stakeholders to resolve water quality licensing issues, including: (1) water quality, (2) fish habitat, and (3) sediment. On April 21, 2016, Generation and the U.S. Fish and Wildlife Service of the U.S. Department of the Interior executed a settlement agreement (DOI Settlement) resolving all fish passage issues between the parties. On April 27, 2018, MDE issued its 401 Certification for Conowingo. As issued, the 401 Certification containscontained numerous conditions, including those relating to reduction of nutrients from upstream sources, removal of all visible trash and debris from upstream sources, and implementation of measures relating to fish passage, which could have a material, unfavorable impact on Exelon’s and Generation’s financial statements through an increase in capital expenditures and operating costs if implemented. On May 25, 2018, Generation filed complaints in federal and state court, along with a petition for reconsideration with MDE, alleging that the conditions are unfair and onerous and in violation of MDE regulations and state, federal, and constitutional law. Generation also requested that FERC defer the issuance of the federal license while these significant state and federal law issues are pending. On February 28, 2019, Generation filed a Petition for Declaratory Order with FERC requesting that FERC issue an order declaring that MDE waived its right to issue a 401 Certification for Conowingo because it failed to timely act on Conowingo’s 401 Certification application and requesting that FERC decline to include the conditions required by MDE in April 2018.passage. 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. Among the Proposed License Articles arewere modifications to river flows to improve aquatic habitat, eel passage improvements, and initiatives to support rare, threatened and endangered wildlife. If On March 19, 2021, FERC approves the Offer of Settlement and incorporatesissued a new 50-year license for Conowingo, effective March 1, 2021. FERC adopted the Proposed License Articles into the new license without modification, thenonly making modifications it deemed necessary to allow FERC to enforce the Proposed License Articles. Consistent with the Offer of Settlement, FERC found that MDE would waivewaived its rights to issue a 401 Certification and Generation would agree, pursuant to a separate agreement with MDE (MDE Settlement), Generation agreed to implement additional environmental protection, mitigation, and enhancement measures over the anticipated 50-year term of the new license. These measures address mussel restoration and other ecological and water quality matters, among other commitments. Exelon’s commitments underOn April 19, 2021, a few environmental groups filed with FERC a petition for rehearing requesting that FERC reconsider the various provisionsissuance of the Offernew Conowingo license, which was denied by operation of Settlement and MDE Settlement are not effective unless and untillaw on May 20, 2021. On June 17, 2021, the petitioners appealed FERC’s ruling to the U.S. Court of Appeals for the D.C. Circuit. On July 15, 2021, FERC approvesissued an order addressing the Offerarguments raised on rehearing, affirming the determinations of Settlement and issues the new license with the Proposed License Articles.its March 19, 2021 order. The financial impact of the DOI and MDE Settlements and other anticipated license commitments are estimated to be $11 million to $14 million per year, on average, recognized over the new license term, including capital and operating costs. The actual timing and amount of the majority of these costs are not currently fixed and will vary from year to year throughout the life of the new license. Generation cannot currently predict when FERC will issue the new license. As of December 31, 2019, $42 million of direct costs associated with Conowingo licensing efforts have been capitalized. Generation's current depreciation provision for Conowingo assumes renewal of the FERC license. Peach Bottom Units 2 and 3. On July 10, 2018, Generation submittedMarch 6, 2020, the NRC approved a second 20-year license renewal application with the NRC for Peach Bottom Units 2 and 3. Generation anticipates the second license renewal in the first half of 2020. Peach Bottom Units 2 and 3 are currentlynow licensed to operate through 20332053 and 2034,2054, respectively. See Note 78 – Property, Plant, and Equipment for additional information regarding the estimated useful life and depreciation provisions for Peach Bottom. PJM Transmission Rate Design. Refer to Other Federal Regulatory Matters above for additional information.
Combined Notes to Consolidated Financial Statements
(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. The performance obligations, revenue recognition, and payment terms associated with these sources of revenue are further discussed in the table below. There are no significant financing components for these sources of revenue and no variable consideration for regulated electric and gas tariff sales and regulated transmission services unless noted below. Unless otherwise noted, for each of the significant revenue categories and related performance obligations described below, the Registrants have the right to consideration from the customer in an amount that corresponds directly with the value transferred to the customer for the performance completed to date. Therefore, the Registrant'sRegistrants generally recognize revenue in the amount for which they have the right to invoice the customer. As a result, there are generally no significant judgments used in determining or allocating the transaction price.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 4 — Revenue from Contracts with Customers
| | | | | | | | | | | | | | | Revenue Source | Description | Performance Obligation | Timing of Revenue Recognition | Payment Terms | Competitive Power Sales (Exelon and Generation)(Exelon) | Sales of power and other energy-related commodities to wholesale and retail customers across multiple geographic regions through itsGeneration's customer-facing business, Constellation.business. | Various including the delivery of power (generally delivered over time) and other energy-related commodities such as capacity (generally delivered over time), ZECs, RECs or other ancillary services (generally delivered at a point in time). | Concurrently as power is generated for bundled power sale contracts. (a) | Within the month following delivery to the customer. | Competitive Natural Gas Sales (Exelon and Generation)(Exelon) | Sales of natural gas on a full requirement basis or for an agreed upon volume to commercial and residential customers. | Delivery of natural gas to the customer. | Over time as the natural gas is delivered and consumed by the customer. | Within the month following delivery to the customer. | Other Competitive Products and Services (Exelon and Generation)(Exelon) | Sales of other energy-related products and services such as long-term construction and installation of energy efficiency assets and new power generating facilities, primarily to commercial and industrial customers. | Construction and/or installation of the asset for the customer. | Revenues and associated costs are recognized throughout the contract term using an input method to measure progress towards completion.(b) | Within 30 or 45 days from the invoice date. | Regulated Electric and Gas Tariff Sales (Exelon and the Utility(The Registrants) | Sales of electricity and electricity distribution services (the Utility Registrants) and natural gas and gas distribution services (PECO, BGE, and DPL) to residential, commercial, industrial, and governmental customers through regulated tariff rates approved by state regulatory commissions. | Delivery of electricity and/or natural gas. | Over time (each day) as the electricity and/or natural gas is delivered to customers. Tariff sales are generally considered daily contracts as customers can discontinue service at any time. (c) | Within the month following delivery of the electricity or natural gas to the customer. | Regulated Transmission Services (Exelon and the Utility(The Registrants) | The Utility Registrants provide open access to their transmission facilities to PJM, which directs and controls the operation of these transmission facilities and accordingly compensates the Utility Registrants pursuant to filed tariffs at cost-based rates approved by FERC. | Various including (i) Network Integration Transmission Services (NITS), (ii) scheduling, system control and dispatch services, and (iii) access to the wholesale grid. | Over time utilizing output methods to measure progress towards completion. (d) | Paid weekly by PJM. |
__________ | | (a) | Certain contracts may contain limits on the total amount of revenue Exelon and Generation are able to collect over the entire term of the contract. In such cases, Exelon and Generation estimate the total consideration expected to be received over the term of the contract net of the constraint and allocate the expected consideration to the performance obligations in the contract such that revenue is recognized ratably over the term of the entire contract as the performance obligations are satisfied. |
| | (b) | The method recognizes revenue based on the various inputs used to satisfy the performance obligation, such as costs incurred and total labor hours expended. The total amount of revenue that will be recognized is based on the agreed upon contractually-stated amount. The average contract term for these projects is approximately 18 months. |
| | (c) | Electric and natural gas utility customers have the choice to purchase electricity or natural gas from competitive electric generation and natural gas suppliers. While the Utility Registrants are required under state legislation to bill their customers |
(a)Certain contracts may contain limits on the total amount of revenue Exelon is able to collect over the entire term of the contract. In such cases, Exelon estimates the total consideration expected to be received over the term of the contract net
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 4 — Revenue from Contracts with Customers
of the constraint and allocate the expected consideration to the performance obligations in the contract such that revenue is recognized ratably over the term of the entire contract as the performance obligations are satisfied.
(b)The method recognizes revenue based on the various inputs used to satisfy the performance obligation, such as costs incurred and total labor hours expended. The total amount of revenue that will be recognized is based on the agreed upon contractually-stated amount. The average contract term for these projects is approximately 18 months. (c)Electric and natural gas utility customers have the choice to purchase electricity or natural gas from competitive electric generation and natural gas suppliers. While the Utility Registrants are required under state legislation to bill their customers for the supply and distribution of electricity and/or natural gas, they recognize revenue related only to the distribution services when customers purchase their electricity or natural gas from competitive suppliers. | | (d) | Passage of time is used for NITS and access to the wholesale grid and MWHs of energy transported over the wholesale grid is used for scheduling, system control and dispatch services. |
(d)Passage of time is used for NITS and access to the wholesale grid and MWHs of energy transported over the wholesale grid is used for scheduling, system control and dispatch services. Generation incurs incremental costs in order to execute certain retail power and gas sales contracts. These costs, which primarily relate to retail broker fees and sales commissions, are capitalized when incurred as contract acquisition costs and were immaterialnot material as of December 31, 20192021 and 2018.2020. The Utility Registrants do not incur any material costs to obtain or fulfill contracts with customers. Contract Balances (All Registrants) Contract Assets and Liabilities GenerationExelon 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 receive the consideration from the customer. These contract assets are subsequently reclassified to receivables when the right to payment becomes unconditional. GenerationExelon records contract assets and contract receivables withinin Other current assets and AccountsCustomer accounts receivable, net, - Customer, respectively, within Exelon’s and Generation’sin the Consolidated Balance Sheets.
Generation recordsThe following table provides a rollforward of the contract assets reflected in Exelon's Consolidated Balance Sheets. The Utility Registrants do not have any contract assets.
| | | | | | | | | | | | | | | | | Exelon | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Balance as of December 31, 2019 | | $ | 174 | | | | | | | | Amounts reclassified to receivables | | (86) | | | | | | | | Revenues recognized | | 68 | | | | | | | | Contract assets reclassified as held-for-sale | | (12) | | | | | | | | Balance as of December 31, 2020 | | 144 | | | | | | | | Amounts reclassified to receivables | | (59) | | | | | | | | Revenues recognized | | 52 | | | | | | | | Amounts previously held-for-sale | | 12 | | | | | | | | Balance as of December 31, 2021 | | $ | 149 | | | | | | | |
Contract Liabilities The Registrants record contract liabilities when consideration is received or due prior to the satisfaction of the performance obligations. TheseThe Registrants record contract liabilities in Other current liabilities and Other noncurrent liabilities in the Registrants' Consolidated Balance Sheets. For Generation, these contract liabilities primarily relate to upfront consideration received or due for equipment service plans solar panel leases and the Illinois ZEC program that introduces a cap on the total consideration to be received by Generation. The Generation contract liability related to the Illinois ZEC program includes certain amounts with ComEd that are eliminated in consolidation in Exelon’s Consolidated Statements of Operations and Consolidated Balance Sheets. Generation records On July 1, 2020, Pepco, DPL, and ACE each entered into a collaborative arrangement with an unrelated owner and manager of communication infrastructure (the Buyer). Under this arrangement, Pepco, DPL, and ACE sold a 60% undivided interest in their respective portfolios of transmission tower attachment agreements with telecommunications companies to the Buyer, in addition to transitioning management of the day-to-day operations of the jointly-owned agreements to the Buyer for 35 years, while retaining the safe and reliable
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 4 — Revenue from Contracts with Customers operation of its utility assets. In return, Pepco, DPL, and ACE will provide the Buyer limited access on the portion of the towers where the equipment resides for the purposes of managing the agreements for the benefit of Pepco, DPL, ACE, and the Buyer. In addition, for an initial period of three years and two, two-year extensions that are subject to certain conditions, the Buyer has the exclusive right to enter into new agreements with telecommunications companies and to receive a 30% undivided interest in those new agreements. PHI, Pepco, DPL, and ACE received cash and recorded contract liabilities within Other current liabilities and Other noncurrent liabilities within Exelon’s and Generation’s Consolidated Balance Sheets.as of July 1, 2020 as shown in the table below. 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 assets and liabilities reflected in Exelon's, PHI's, Pepco's, DPL's, and Generation'sACE'S Consolidated Balance Sheets from January 1, 2018 to December 31, 2019: | | | | | | | | | | | | | | | | | | | | Contract Assets | | Contract Liabilities | | | Exelon | | Generation | | Exelon | | Generation | Balance as of January 1, 2018 | | $ | 283 |
| | $ | 283 |
| | $ | 35 |
| | $ | 35 |
| Consideration received or due | | (146 | ) | | (146 | ) | | 179 |
| | 465 |
| Revenues recognized | | 50 |
| | 50 |
| | (187 | ) | | (458 | ) | Balance at December 31, 2018 | | 187 |
| | 187 |
| | 27 |
| | 42 |
| Consideration received or due | | (143 | ) | | (143 | ) | | 94 |
| | 287 |
| Revenues recognized | | 130 |
| | 130 |
| | (88 | ) | | (258 | ) | Balance at December 31, 2019 | | $ | 174 |
| | $ | 174 |
| | $ | 33 |
| | $ | 71 |
|
The Utility Registrants do not have any contract assets. The Utility Registrants also record contract liabilities when consideration is received prior to the satisfaction of the performance obligations.Sheets. As of December 31, 2021, 2020, and 2019, ComEd's, PECO's, and December 31, 2018, the Utility Registrants'BGE's contract liabilities were immaterial.not material.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exelon | | | | PHI | | Pepco | | DPL | | ACE | Balance as of December 31, 2018 | $ | 27 | | | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | Consideration received or due | 94 | | | | | — | | | — | | | — | | | — | | Revenues recognized | (88) | | | | | — | | | — | | | — | | | — | | Balance as of December 31, 2019 | 33 | | | | | — | | | — | | | — | | | — | | Consideration received or due | 219 | | | | | 122 | | | 98 | | | 12 | | | 12 | | Revenues recognized | (98) | | | | | (4) | | | (4) | | | — | | | — | | Contract liabilities reclassified as held-for-sale | (3) | | | | | — | | | — | | | — | | | — | | Balance as of December 31, 2020 | 151 | | | | | 118 | | | 94 | | | 12 | | | 12 | | Consideration received or due | 97 | | | | | — | | | — | | | — | | | — | | Revenues recognized | (110) | | | | | (9) | | | (7) | | | (1) | | | (1) | | Amounts previously held-for-sale | 3 | | | | | — | | | — | | | — | | | — | | Balance as of December 31, 2021 | $ | 141 | | | | | $ | 109 | | | $ | 87 | | | $ | 11 | | | $ | 11 | |
The following table reflects revenues recognized in the years ended December 31, 2021, 2020 and 2019, which were included in contract liabilities at December 31, 2020, 2019, and 2018, respectively: | | | | | | | | | | | | | | | | | | | 2021 | | 2020 | | 2019 | Exelon | $ | 40 | | | $ | 27 | | | $ | 18 | | | | | | | | PHI | 9 | | | — | | | — | | Pepco | 7 | | | — | | | — | | 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 December 31, 2019.2021. 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’sGeneration's power and gas sales contracts as they contain variable volumes and/or variable pricing. This disclosure also excludes the Utility Registrants’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 (Dollars in millions, except per share data unless otherwise noted)
Note 4 — Revenue from Contracts with Customers
| | | | | | | | | | | | | | | | | | | | | | | | | | 2020 | | 2021 | | 2022 | | 2023 | | 2024 and thereafter | | Total | Exelon | $ | 400 |
| | $ | 141 |
| | $ | 65 |
| | $ | 45 |
| | $ | 199 |
| | $ | 850 |
| Generation | 501 |
| | 196 |
| | 80 |
| | 45 |
| | 199 |
| | 1,021 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2022 | | 2023 | | 2024 | | 2025 | | 2026 and thereafter | | Total | Exelon | $ | 194 | | | $ | 70 | | | $ | 38 | | | $ | 31 | | | $ | 155 | | | $ | 488 | | | | | | | | | | | | | | PHI | 8 | | | 8 | | | 6 | | | 5 | | | 82 | | | 109 | | Pepco | 6 | | | 6 | | | 5 | | | 5 | | | 65 | | | 87 | | DPL | 1 | | | 1 | | | — | | | — | | | 9 | | | 11 | | ACE | 1 | | | 1 | | | 1 | | | — | | | 8 | | | 11 | |
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 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 CODM in deciding how to evaluate performance and allocate resources at each of the Registrants. Exelon has 11 reportable segments, which include Generation'sincludes 5 reportable segments for Generation 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'sthe reportable segments of Generation is the integrated management of itsGeneration's 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’sthe 5 reportable segments of Generation 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 that covers a majority of the state of Texas. •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 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. • represents operations within ISO-NE. |
| | • | South represents operations in the FRCC, MISO’s Southern Region, the remaining portions of the SERC not included within MISO or PJM.
|
| | • | West represents operations in the WECC, including California ISO.
|
| | • | Canada represents operations across the entire country of Canada and includes AESO, OIESO, and the Canadian portion of MISO. |
The CODMs for Exelon and Generation evaluateCODM evaluates the performance of Generation’s electric business activities and allocateallocates resources based on RNF. GenerationRevenues Net of Purchased Power and Fuel Expense (RNF). Management believes that RNF is a useful
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 5 — Segment Information 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
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 5 — Segment Information
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 doThe CODM does not use a measure of total assets in making decisions regarding allocating resources to or assessing the performance of these reportable segments. During the first quarter of 2019, due to a change in economics in our New England region, Generation changed the way that information is reviewed by the CODM. The New England region is no longer regularly reviewed as a separate region by the CODM nor is it presented separately in any external information presented to third parties. Information for the New England region is reviewed by the CODM as part of Other Power Regions. Exelon and Generation retrospectively applied this change.
An analysis and reconciliation of the Registrants’ reportable segment information to the respective information in the Exelon consolidated financial statements for the years ended December 31, 2019, 2018,2021, 2020, and 20172019 is as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Generation (a) |
| ComEd |
| PECO |
| BGE |
| PHI | | Other (b) |
| Intersegment Eliminations |
| Exelon | Operating revenues(c): | | | | | | | | | | | | | | | | 2019 | | | | | | | | | | | | | | | | Competitive businesses electric revenues | $ | 16,285 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | (1,165 | ) | | $ | 15,120 |
| Competitive businesses natural gas revenues | 2,148 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (1 | ) | | 2,147 |
| Competitive businesses other revenues | 491 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (4 | ) | | 487 |
| Rate-regulated electric revenues | — |
| | 5,747 |
| | 2,490 |
| | 2,379 |
| | 4,626 |
| | — |
| | (47 | ) | | 15,195 |
| Rate-regulated natural gas revenues | — |
| | — |
| | 610 |
| | 727 |
| | 167 |
| | — |
| | (15 | ) | | 1,489 |
| Shared service and other revenues | — |
| | — |
| | — |
| | — |
| | 13 |
| | 1,921 |
| | (1,934 | ) | | — |
| Total operating revenues | $ | 18,924 |
| | $ | 5,747 |
| | $ | 3,100 |
| | $ | 3,106 |
| | $ | 4,806 |
| | $ | 1,921 |
| | $ | (3,166 | ) | | $ | 34,438 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ComEd | | PECO | | BGE | | PHI | | Generation | | Other(a) | | Intersegment Eliminations | | Exelon | Operating revenues(b): | | | | | | | | | | | | | | | | 2021 | | | | | | | | | | | | | | | | Competitive businesses electric revenues | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 16,290 | | | $ | — | | | $ | (1,171) | | | $ | 15,119 | | Competitive businesses natural gas revenues | — | | | — | | | — | | | — | | | 3,379 | | | — | | | 0 | | 3,379 | | Competitive businesses other revenues | — | | | — | | | — | | | — | | | (20) | | | — | | | (11) | | | (31) | | Rate-regulated electric revenues | 6,406 | | | 2,659 | | | 2,505 | | | 4,860 | | | — | | | — | | | (78) | | | 16,352 | | Rate-regulated natural gas revenues | — | | | 539 | | | 836 | | | 168 | | | — | | | — | | | (15) | | | 1,528 | | Shared service and other revenues | — | | | — | | | — | | | 13 | | | — | | | 2,213 | | | (2,226) | | | — | | Total operating revenues | $ | 6,406 | | | $ | 3,198 | | | $ | 3,341 | | | $ | 5,041 | | | $ | 19,649 | | | $ | 2,213 | | | $ | (3,501) | | | $ | 36,347 | | 2020 | | | | | | | | | | | | | | | | Competitive businesses electric revenues | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 15,060 | | | $ | — | | | $ | (1,196) | | | $ | 13,864 | | Competitive businesses natural gas revenues | — | | | — | | | — | | | — | | | 2,003 | | | — | | | (3) | | | 2,000 | | Competitive businesses other revenues | — | | | — | | | — | | | — | | | 540 | | | — | | | (4) | | | 536 | | Rate-regulated electric revenues | 5,904 | | | 2,543 | | | 2,336 | | | 4,485 | | | — | | | — | | | (61) | | | 15,207 | | Rate-regulated natural gas revenues | — | | | 515 | | | 762 | | | 162 | | | — | | | — | | | (7) | | | 1,432 | | Shared service and other revenues | — | | | — | | | — | | | 16 | | | — | | | 2,035 | | | (2,051) | | | — | | Total operating revenues | $ | 5,904 | | | $ | 3,058 | | | $ | 3,098 | | | $ | 4,663 | | | $ | 17,603 | | | $ | 2,035 | | | $ | (3,322) | | | $ | 33,039 | | | | | | | | | | | | | | | | | |
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 5 — Segment Information
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ComEd | | PECO | | BGE | | PHI | | Generation | | Other(a) | | Intersegment Eliminations | | Exelon | 2019 | | | | | | | | | | | | | | | | Competitive businesses electric revenues | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 16,285 | | | $ | — | | | $ | (1,165) | | | $ | 15,120 | | Competitive businesses natural gas revenues | — | | | — | | | — | | | — | | | 2,148 | | | — | | | (1) | | | 2,147 | | Competitive businesses other revenues | — | | | — | | | — | | | — | | | 491 | | | — | | | (4) | | | 487 | | Rate-regulated electric revenues | 5,747 | | | 2,490 | | | 2,379 | | | 4,626 | | | — | | | — | | | (47) | | | 15,195 | | Rate-regulated natural gas revenues | — | | | 610 | | | 727 | | | 167 | | | — | | | — | | | (15) | | | 1,489 | | Shared service and other revenues | — | | | — | | | — | | | 13 | | | — | | | 1,921 | | | (1,934) | | | — | | Total operating revenues | $ | 5,747 | | | $ | 3,100 | | | $ | 3,106 | | | $ | 4,806 | | | $ | 18,924 | | | $ | 1,921 | | | $ | (3,166) | | | $ | 34,438 | | | | | | | | | | | | | | | | | | Intersegment revenues(c): | | | | | | | | | | | | | | | | 2021 | $ | 41 | | | $ | 21 | | | $ | 31 | | | $ | 13 | | | $ | 1,188 | | | $ | 2,203 | | | $ | (3,497) | | | $ | — | | 2020 | 37 | | | 9 | | | 20 | | | 17 | | | 1,211 | | | 2,024 | | | (3,314) | | | 4 | | 2019 | 30 | | | 6 | | | 26 | | | 14 | | | 1,172 | | | 1,913 | | | (3,159) | | | 2 | | Depreciation and amortization: | | | | | | | | | | | | | | | | 2021 | $ | 1,205 | | | $ | 348 | | | $ | 591 | | | $ | 821 | | | $ | 3,003 | | | $ | 67 | | | $ | 1 | | | $ | 6,036 | | 2020 | 1,133 | | | 347 | | | 550 | | | 782 | | | 2,123 | | | 79 | | | — | | | 5,014 | | 2019 | 1,033 | | | 333 | | | 502 | | | 754 | | | 1,535 | | | 95 | | | — | | | 4,252 | | Operating expenses: | | | | | | | | | | | | | | | | 2021 | $ | 5,151 | | | $ | 2,547 | | | $ | 2,860 | | | $ | 4,240 | | | $ | 20,196 | | | $ | 2,242 | | | $ | (3,411) | | | $ | 33,825 | | 2020 | 4,950 | | | 2,512 | | | 2,598 | | | 4,045 | | | 17,358 | | | 2,047 | | | (3,270) | | | 30,240 | | 2019 | 4,580 | | | 2,388 | | | 2,574 | | | 4,084 | | | 17,628 | | | 1,996 | | | (3,154) | | | 30,096 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Interest expense, net: | | | | | | | | | | | | | | | | 2021 | $ | 389 | | | $ | 161 | | | $ | 138 | | | $ | 267 | | | $ | 297 | | | $ | 320 | | | $ | (1) | | | $ | 1,571 | | 2020 | 382 | | | 147 | | | 133 | | | 268 | | | 357 | | | 351 | | | (3) | | | 1,635 | | 2019 | 359 | | | 136 | | | 121 | | | 263 | | | 429 | | | 308 | | | — | | | 1,616 | | Income (loss) before income taxes: | | | | | | | | | | | | | | | | 2021 | $ | 914 | | | $ | 516 | | | $ | 373 | | | $ | 603 | | | $ | 152 | | | $ | (351) | | | $ | 1 | | | $ | 2,208 | | 2020 | 615 | | | 417 | | | 390 | | | 418 | | | 836 | | | (343) | | | — | | | 2,333 | | 2019 | 851 | | | 593 | | | 439 | | | 514 | | | 1,917 | | | (327) | | | (2) | | | 3,985 | | Income taxes: | | | | | | | | | | | | | | | | 2021 | $ | 172 | | | $ | 12 | | | $ | (35) | | | $ | 42 | | | $ | 225 | | | $ | (46) | | | $ | — | | | $ | 370 | | 2020 | 177 | | | (30) | | | 41 | | | (77) | | | 249 | | | 13 | | | — | | | 373 | | 2019 | 163 | | | 65 | | | 79 | | | 38 | | | 516 | | | (87) | | | — | | | 774 | | Net income (loss): | | | | | | | | | | | | | | | | 2021 | $ | 742 | | | $ | 504 | | | $ | 408 | | | $ | 561 | | | $ | (83) | | | $ | (304) | | | $ | 1 | | | $ | 1,829 | | 2020 | 438 | | | 447 | | | 349 | | | 495 | | | 579 | | | (354) | | | — | | | 1,954 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Generation (a) |
| ComEd |
| PECO |
| BGE |
| PHI | | Other (b) |
| Intersegment Eliminations |
| Exelon | 2018 | | | | | | | | | | | | | | | | Competitive businesses electric revenues | $ | 17,411 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | (1,256 | ) | | $ | 16,155 |
| Competitive businesses natural gas revenues | 2,718 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (8 | ) | | 2,710 |
| Competitive businesses other revenues | 308 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (5 | ) | | 303 |
| Rate-regulated electric revenues | — |
| | 5,882 |
| | 2,470 |
| | 2,428 |
| | 4,602 |
| | — |
| | (45 | ) | | 15,337 |
| Rate-regulated natural gas revenues | — |
| | — |
| | 568 |
| | 741 |
| | 181 |
| | — |
| | (20 | ) | | 1,470 |
| Shared service and other revenues | — |
| | — |
| | — |
| | — |
| | 15 |
| | 1,948 |
| | (1,960 | ) | | 3 |
| Total operating revenues | $ | 20,437 |
| | $ | 5,882 |
| | $ | 3,038 |
| | $ | 3,169 |
| | $ | 4,798 |
| | $ | 1,948 |
| | $ | (3,294 | ) | | $ | 35,978 |
| 2017 | | | | | | | | | | | | | | | | Competitive businesses electric revenues | $ | 15,332 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | (1,105 | ) | | $ | 14,227 |
| Competitive businesses natural gas revenues | 2,575 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 2,575 |
| Competitive businesses other revenues | 593 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (1 | ) | | 592 |
| Rate-regulated electric revenues | — |
| | 5,536 |
| | 2,375 |
| | 2,489 |
| | 4,462 |
| | — |
| | (29 | ) | | 14,833 |
| Rate-regulated natural gas revenues | — |
| | — |
| | 495 |
| | 687 |
| | 161 |
| | — |
| | (10 | ) | | 1,333 |
| Shared service and other revenues | — |
| | — |
| | — |
| | — |
| | 49 |
| | 1,831 |
| | (1,880 | ) | | — |
| Total operating revenues | $ | 18,500 |
| | $ | 5,536 |
| | $ | 2,870 |
| | $ | 3,176 |
| | $ | 4,672 |
| | $ | 1,831 |
| | $ | (3,025 | ) | | $ | 33,560 |
| | | | | | | | | | | | | | | | | Intersegment revenues(d): | | | | | | | | | | | | | | | | 2019 | $ | 1,172 |
| | $ | 30 |
| | $ | 6 |
| | $ | 26 |
| | $ | 14 |
| | $ | 1,913 |
| | $ | (3,159 | ) | | $ | 2 |
| 2018 | 1,269 |
| | 27 |
| | 8 |
| | 29 |
| | 15 |
| | 1,942 |
| | (3,289 | ) | | 1 |
| 2017 | 1,110 |
| | 15 |
| | 7 |
| | 16 |
| | 50 |
| | 1,824 |
| | (3,020 | ) | | 2 |
| Depreciation and amortization: | | | | | | | | | | | | | | | | 2019 | $ | 1,535 |
| | $ | 1,033 |
| | $ | 333 |
| | $ | 502 |
| | $ | 754 |
| | $ | 95 |
| | $ | — |
| | $ | 4,252 |
| 2018 | 1,797 |
| | 940 |
| | 301 |
| | 483 |
| | 740 |
| | 92 |
| | — |
| | 4,353 |
| 2017 | 1,457 |
| | 850 |
| | 286 |
| | 473 |
| | 675 |
| | 87 |
| | — |
| | 3,828 |
|
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 5 — Segment Information
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Generation (a) |
| ComEd |
| PECO |
| BGE |
| PHI | | Other (b) |
| Intersegment Eliminations |
| Exelon | Operating expenses (c): | | | | | | | | | | | | | | | | 2019 | $ | 17,628 |
| | $ | 4,580 |
| | $ | 2,388 |
| | $ | 2,574 |
| | $ | 4,084 |
| | $ | 1,996 |
| | $ | (3,154 | ) | | $ | 30,096 |
| 2018 | 19,510 |
| | 4,741 |
| | 2,452 |
| | 2,696 |
| | 4,156 |
| | 1,929 |
| | (3,341 | ) | | 32,143 |
| 2017 | 18,001 |
| | 4,214 |
| | 2,215 |
| | 2,562 |
| | 3,911 |
| | 1,742 |
| | (3,026 | ) | | 29,619 |
| Interest expense, net: | | | | | | | | | | | | | | | | 2019 | $ | 429 |
| | $ | 359 |
| | $ | 136 |
| | $ | 121 |
| | $ | 263 |
| | $ | 308 |
| | $ | — |
| | $ | 1,616 |
| 2018 | 432 |
| | 347 |
| | 129 |
| | 106 |
| | 261 |
| | 279 |
| | — |
| | 1,554 |
| 2017 | 440 |
| | 361 |
| | 126 |
| | 105 |
| | 245 |
| | 283 |
| | — |
| | 1,560 |
| Income (loss) before income taxes: | | | | | | | | | | | | | | | | 2019 | $ | 1,917 |
| | $ | 851 |
| | $ | 593 |
| | $ | 439 |
| | $ | 514 |
| | $ | (327 | ) | | $ | (2 | ) | | $ | 3,985 |
| 2018 | 365 |
| | 832 |
| | 466 |
| | 387 |
| | 425 |
| | (249 | ) | | (1 | ) | | 2,225 |
| 2017 | 1,455 |
| | 984 |
| | 538 |
| | 525 |
| | 571 |
| | (296 | ) | | (2 | ) | | 3,775 |
| Income taxes: | | | | | | | | | | | | | | | | 2019 | $ | 516 |
| | $ | 163 |
| | $ | 65 |
| | $ | 79 |
| | $ | 38 |
| | $ | (87 | ) | | $ | — |
| | $ | 774 |
| 2018 | (108 | ) | | 168 |
| | 6 |
| | 74 |
| | 33 |
| | (55 | ) | | — |
| | 118 |
| 2017 | (1,376 | ) | | 417 |
| | 104 |
| | 218 |
| | 217 |
| | 294 |
| | — |
| | (126 | ) | Net income (loss): | | | | | | | | | | | | | | | | 2019 | $ | 1,217 |
| | $ | 688 |
| | $ | 528 |
| | $ | 360 |
| | $ | 477 |
| | $ | (240 | ) | | $ | (2 | ) | | $ | 3,028 |
| 2018 | 443 |
| | 664 |
| | 460 |
| | 313 |
| | 393 |
| | (193 | ) | | (1 | ) | | 2,079 |
| 2017 | 2,798 |
| | 567 |
| | 434 |
| | 307 |
| | 355 |
| | (590 | ) | | (2 | ) | | 3,869 |
| Capital expenditures: | | | | | | | | | | | | | | | | 2019 | $ | 1,845 |
| | $ | 1,915 |
| | $ | 939 |
| | $ | 1,145 |
| | $ | 1,355 |
| | $ | 49 |
| | $ | — |
| | $ | 7,248 |
| 2018 | 2,242 |
| | 2,126 |
| | 849 |
| | 959 |
| | 1,375 |
| | 43 |
| | — |
| | 7,594 |
| 2017 | 2,259 |
| | 2,250 |
| | 732 |
| | 882 |
| | 1,396 |
| | 65 |
| | — |
| | 7,584 |
| Total assets: | | | | | | | | | | | | | | | | 2019 | $ | 48,995 |
| | $ | 32,765 |
| | $ | 11,469 |
| | $ | 10,634 |
| | $ | 22,719 |
| | $ | 8,484 |
| | $ | (10,089 | ) | | $ | 124,977 |
| 2018 | 47,556 |
| | 31,213 |
| | 10,642 |
| | 9,716 |
| | 21,952 |
| | 8,355 |
| | (9,800 | ) | | 119,634 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ComEd | | PECO | | BGE | | PHI | | Generation | | Other(a) | | Intersegment Eliminations | | Exelon | 2019 | 688 | | | 528 | | | 360 | | | 477 | | | 1,217 | | | (240) | | | (2) | | | 3,028 | | Capital expenditures: | | | | | | | | | | | | | | | | 2021 | $ | 2,387 | | | $ | 1,240 | | | $ | 1,226 | | | $ | 1,720 | | | $ | 1,329 | | | $ | 79 | | | $ | — | | | $ | 7,981 | | 2020 | 2,217 | | | 1,147 | | | 1,247 | | | 1,604 | | | 1,747 | | | 86 | | | — | | | 8,048 | | 2019 | 1,915 | | | 939 | | | 1,145 | | | 1,355 | | | 1,845 | | | 49 | | | — | | | 7,248 | | Total assets: | | | | | | | | | | | | | | | | 2021 | $ | 36,470 | | | $ | 13,824 | | | $ | 12,324 | | | $ | 24,744 | | | $ | 48,086 | | | $ | 7,727 | | | $ | (10,162) | | | $ | 133,013 | | 2020 | 34,466 | | | 12,531 | | | 11,650 | | | 23,736 | | | 48,094 | | | 9,005 | | | (10,165) | | | 129,317 | |
__________ | | (a) | See Note 24 —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 24 — 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 25 - Related Party Transactions for additional information on intersegment revenues. |
| | (b) | Other primarily includes Exelon’s corporate operations, shared service entities and other financing and investment activities. |
| | (c) | 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 23 — Supplemental Financial Information for additional information on total utility taxes. |
| | (d) | 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 authoritative guidance. For Exelon, these amounts are included in Operating revenues in the Consolidated Statements of Operations and Comprehensive Income. |
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 5 — Segment Information
PHI: | | | | | | | | | | | | | | | | | | | | | | | | | | Pepco | | DPL | | ACE | | Other(b) | | Intersegment Eliminations | | PHI | Operating revenues(a): | | | | | | | | | | | | 2019 | | | | | | | | | | | | Rate-regulated electric revenues | $ | 2,260 |
| | $ | 1,139 |
| | $ | 1,240 |
| | $ | — |
| | $ | (13 | ) | | $ | 4,626 |
| Rate-regulated natural gas revenues | — |
| | 167 |
| | — |
| | — |
| | — |
| | 167 |
| Shared service and other revenues | — |
| | — |
| | — |
| | 396 |
| | (383 | ) | | 13 |
| Total operating revenues | $ | 2,260 |
| | $ | 1,306 |
| | $ | 1,240 |
| | $ | 396 |
| | $ | (396 | ) | | $ | 4,806 |
| 2018 | | | | | | | | | | | | Rate-regulated electric revenues | $ | 2,232 |
| | $ | 1,151 |
| | $ | 1,236 |
| | $ | — |
| | $ | (17 | ) | | $ | 4,602 |
| Rate-regulated natural gas revenues | — |
| | 181 |
| | — |
| | — |
| | — |
| | 181 |
| Shared service and other revenues | — |
| | — |
| | — |
| | 435 |
| | (420 | ) | | 15 |
| Total operating revenues | $ | 2,232 |
| | $ | 1,332 |
| | $ | 1,236 |
| | $ | 435 |
| | $ | (437 | ) | | $ | 4,798 |
| 2017 | | | | | | | | | | | | Rate-regulated electric revenues | $ | 2,151 |
| | $ | 1,139 |
| | $ | 1,186 |
| | $ | — |
| | $ | (14 | ) | | $ | 4,462 |
| Rate-regulated natural gas revenues | — |
| | 161 |
| | — |
| | — |
| | — |
| | 161 |
| Shared service and other revenues | — |
| | — |
| | — |
| | 52 |
| | (3 | ) | | 49 |
| Total operating revenues | $ | 2,151 |
| | $ | 1,300 |
| | $ | 1,186 |
| | $ | 52 |
| | $ | (17 | ) | | $ | 4,672 |
| Intersegment revenues: | | | | | | | | | | | | 2019 | $ | 5 |
| | $ | 7 |
| | $ | 3 |
| | $ | 396 |
| | $ | (397 | ) | | $ | 14 |
| 2018 | 6 |
| | 8 |
| | 3 |
| | 435 |
| | (437 | ) | | 15 |
| 2017 | 6 |
| | 8 |
| | 2 |
| | 53 |
| | (19 | ) | | 50 |
| Depreciation and amortization: | | | | | | | | | | | | 2019 | $ | 374 |
| | $ | 184 |
| | $ | 157 |
| | $ | 39 |
| | $ | — |
| | $ | 754 |
| 2018 | 385 |
| | 182 |
| | 136 |
| | 37 |
| | — |
| | $ | 740 |
| 2017 | 321 |
| | 167 |
| | 146 |
| | 42 |
| | (1 | ) | | $ | 675 |
| Operating expenses: | | | | | | | | | | |
|
| 2019 | $ | 1,899 |
| | $ | 1,089 |
| | $ | 1,089 |
| | $ | 403 |
| | $ | (396 | ) | | $ | 4,084 |
| 2018 | 1,919 |
| | 1,143 |
| | 1,087 |
| | 442 |
| | (435 | ) | | $ | 4,156 |
| 2017 | 1,760 |
| | 1,071 |
| | 1,029 |
| | 68 |
| | (17 | ) | | $ | 3,911 |
| Interest expense, net: | | | | | | | | | | |
|
| 2019 | $ | 133 |
| | $ | 61 |
| | $ | 58 |
| | $ | 10 |
| | $ | 1 |
| | $ | 263 |
| 2018 | 128 |
| | 58 |
| | 64 |
| | 11 |
| | — |
| | $ | 261 |
| 2017 | 121 |
| | 51 |
| | 61 |
| | 13 |
| | (1 | ) | | $ | 245 |
| Income (loss) before income taxes: | | | | | | | | | | |
|
| 2019 | $ | 259 |
| | $ | 169 |
| | $ | 99 |
| | $ | 476 |
| | $ | (489 | ) | | $ | 514 |
| 2018 | 216 |
| | 142 |
| | 87 |
| | 388 |
| | (408 | ) | | $ | 425 |
| 2017 | 303 |
| | 192 |
| | 103 |
| | 377 |
| | (404 | ) | | $ | 571 |
| Income taxes: | | | | | | | | | | |
|
| 2019 | $ | 16 |
| | $ | 22 |
| | $ | — |
| | $ | (1 | ) | | $ | 1 |
| | $ | 38 |
| 2018 | 11 |
| | 22 |
| | 12 |
| | (10 | ) | | (2 | ) | | $ | 33 |
| 2017 | 105 |
| | 71 |
| | 26 |
| | 15 |
| | — |
| | $ | 217 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Pepco | | DPL | | ACE | | Other(a) | | Intersegment Eliminations | | PHI | Operating revenues(b): | | | | | | | | | | | | 2021 | | | | | | | | | | | | Rate-regulated electric revenues | $ | 2,274 | | | $ | 1,212 | | | $ | 1,388 | | | $ | — | | | $ | (14) | | | $ | 4,860 | | Rate-regulated natural gas revenues | — | | | 168 | | | — | | | — | | | — | | | 168 | | Shared service and other revenues | — | | | — | | | — | | | 379 | | | (366) | | | 13 | | Total operating revenues | $ | 2,274 | | | $ | 1,380 | | | $ | 1,388 | | | $ | 379 | | | $ | (380) | | | $ | 5,041 | | 2020 | | | | | | | | | | | | Rate-regulated electric revenues | $ | 2,149 | | | $ | 1,109 | | | $ | 1,245 | | | $ | — | | | $ | (18) | | | $ | 4,485 | | Rate-regulated natural gas revenues | — | | | 162 | | | — | | | — | | | — | | | 162 | | Shared service and other revenues | — | | | — | | | — | | | 372 | | | (356) | | | 16 | | Total operating revenues | $ | 2,149 | | | $ | 1,271 | | | $ | 1,245 | | | $ | 372 | | | $ | (374) | | | $ | 4,663 | | 2019 | | | | | | | | | | | | Rate-regulated electric revenues | $ | 2,260 | | | $ | 1,139 | | | $ | 1,240 | | | $ | — | | | $ | (13) | | | $ | 4,626 | | Rate-regulated natural gas revenues | — | | | 167 | | | — | | | — | | | — | | | 167 | | Shared service and other revenues | — | | | — | | | — | | | 396 | | | (383) | | | 13 | | Total operating revenues | $ | 2,260 | | | $ | 1,306 | | | $ | 1,240 | | | $ | 396 | | | $ | (396) | | | $ | 4,806 | | Intersegment revenues(c): | | | | | | | | | | | | 2021 | $ | 5 | | | $ | 7 | | | $ | 2 | | | $ | 380 | | | $ | (381) | | | $ | 13 | | 2020 | 7 | | | 9 | | | 4 | | | 372 | | | (375) | | | 17 | | 2019 | 5 | | | 7 | | | 3 | | | 396 | | | (397) | | | 14 | | Depreciation and amortization: | | | | | | | | | | | | 2021 | $ | 403 | | | $ | 210 | | | $ | 179 | | | $ | 29 | | | $ | — | | | $ | 821 | | 2020 | 377 | | | 191 | | | 180 | | | 34 | | | — | | | 782 | | 2019 | 374 | | | 184 | | | 157 | | | 39 | | | — | | | 754 | | Operating expenses: | | | | | | | | | | | | 2021 | $ | 1,871 | | | $ | 1,161 | | | $ | 1,201 | | | $ | 388 | | | $ | (381) | | | $ | 4,240 | | 2020 | 1,799 | | | 1,120 | | | 1,123 | | | 378 | | | (375) | | | 4,045 | | 2019 | 1,899 | | | 1,089 | | | 1,089 | | | 403 | | | (396) | | | 4,084 | | Interest expense, net: | | | | | | | | | | | | 2021 | $ | 140 | | | $ | 61 | | | $ | 58 | | | $ | 8 | | | $ | — | | | $ | 267 | | 2020 | 138 | | | 61 | | | 59 | | | 10 | | | — | | | 268 | | 2019 | 133 | | | 61 | | | 58 | | | 10 | | | 1 | | | 263 | | Income (loss) before income taxes: | | | | | | | | | | | | 2021 | $ | 311 | | | $ | 170 | | | $ | 133 | | | $ | (11) | | | $ | — | | | $ | 603 | | 2020 | 259 | | | 100 | | | 71 | | | (12) | | | — | | | 418 | | 2019 | 259 | | | 169 | | | 99 | | | (13) | | | — | | | 514 | | Income taxes: | | | | | | | | | | | | 2021 | $ | 15 | | | $ | 42 | | | $ | (13) | | | $ | (2) | | | $ | — | | | $ | 42 | | 2020 | (7) | | | (25) | | | (41) | | | (4) | | | — | | | (77) | | 2019 | 16 | | | 22 | | | — | | | — | | | — | | | 38 | |
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 5 — Segment Information
| | | Pepco | | DPL | | ACE | | Other(b) | | Intersegment Eliminations | | PHI | | Pepco | | DPL | | ACE | | Other(a) | | Intersegment Eliminations | | PHI | Net income (loss): | | | | | | | | | | |
|
| Net income (loss): | | 2021 | | 2021 | $ | 296 | | | $ | 128 | | | $ | 146 | | | $ | (9) | | | $ | — | | | $ | 561 | | 2020 | | 2020 | 266 | | | 125 | | | 112 | | | (8) | | | — | | | 495 | | 2019 | $ | 243 |
| | $ | 147 |
| | $ | 99 |
| | $ | (26 | ) | | $ | 14 |
| | $ | 477 |
| 2019 | 243 | | | 147 | | | 99 | | | (12) | | | — | | | 477 | | 2018 | 205 |
| | 120 |
| | 75 |
| | (22 | ) | | 15 |
| | $ | 393 |
| | 2017 | 198 |
| | 121 |
| | 77 |
| | (91 | ) | | 50 |
| | $ | 355 |
| | Capital expenditures: | | | | | | | | | | |
|
| Capital expenditures: | | 2021 | | 2021 | $ | 843 | | | $ | 429 | | | $ | 445 | | | $ | 3 | | | $ | — | | | $ | 1,720 | | 2020 | | 2020 | 773 | | | 424 | | | 401 | | | 6 | | | — | | | 1,604 | | 2019 | $ | 626 |
| | $ | 348 |
| | $ | 375 |
| | $ | 6 |
| | $ | — |
| | $ | 1,355 |
| 2019 | 626 | | | 348 | | | 375 | | | 6 | | | — | | | 1,355 | | 2018 | 656 |
| | 364 |
| | 335 |
| | 20 |
| | — |
| | $ | 1,375 |
| | 2017 | 628 |
| | 428 |
| | 312 |
| | 28 |
| | — |
| | 1,396 |
| | Total assets: | | | | | | | | | | | | Total assets: | | 2019 | $ | 8,661 |
| | $ | 4,830 |
| | $ | 3,933 |
| | $ | 11,105 |
| | $ | (5,810 | ) | | $ | 22,719 |
| | 2018 | 8,267 |
| | 4,588 |
| | 3,699 |
| | 10,819 |
| | (5,421 | ) | | 21,952 |
| | 2021 | | 2021 | $ | 9,903 | | | $ | 5,412 | | | $ | 4,556 | | | $ | 4,933 | | | $ | (60) | | | $ | 24,744 | | 2020 | | 2020 | 9,264 | | | 5,140 | | | 4,286 | | | 5,079 | | | (33) | | | 23,736 | |
__________ | | (a) | 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 23 — Supplemental Financial Information for additional information on total utility taxes. |
| | (b) | Other primarily includes PHI’s corporate operations, shared service entities and other financing and investment activities. |
(a)Other primarily includes PHI’s corporate operations, shared service entities, and other financing and investment activities.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 5 — Segment Information
(c)Includes intersegment revenues with ComEd, BGE, and PECO, which are eliminated at Exelon.
The following tables disaggregate the Registrants' 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. 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 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): | | | | | | | | | | | | | | | | | | | | | | 2019 | | Revenues from external customers(a) | | | | | | Contracts with customers | | Other(b) | | Total | | Intersegment Revenues | | Total Revenues | Mid-Atlantic | $ | 5,053 |
|
| $ | 17 |
| | $ | 5,070 |
| | $ | 4 |
|
| $ | 5,074 |
| Midwest | 4,095 |
|
| 232 |
| | 4,327 |
| | (34 | ) |
| 4,293 |
| New York | 1,571 |
|
| 25 |
| | 1,596 |
| | — |
|
| 1,596 |
| ERCOT | 768 |
|
| 229 |
| | 997 |
| | 16 |
|
| 1,013 |
| Other Power Regions | 3,687 |
|
| 608 |
| | 4,295 |
| | (49 | ) |
| 4,246 |
| Total Competitive Businesses Electric Revenues | 15,174 |
|
| 1,111 |
| | 16,285 |
| | (63 | ) |
| 16,222 |
| Competitive Businesses Natural Gas Revenues | 1,446 |
|
| 702 |
| | 2,148 |
| | 62 |
|
| 2,210 |
| Competitive Businesses Other Revenues(c) | 440 |
| | 51 |
| | 491 |
| | 1 |
| | 492 |
| Total Generation Consolidated Operating Revenues | 17,060 |
|
| 1,864 |
| | $ | 18,924 |
| | $ | — |
|
| $ | 18,924 |
|
| | | | | | | | | | | | | | | | | | | | | | 2018 | | Revenues from external customers(a) | | | | | | Contracts with customers | | Other(b) | | Total | | Intersegment Revenues | | Total Revenues | Mid-Atlantic | $ | 5,241 |
| | $ | 233 |
| | $ | 5,474 |
| | $ | 13 |
| | $ | 5,487 |
| Midwest | 4,527 |
| | 190 |
| | 4,717 |
| | (11 | ) | | 4,706 |
| New York | 1,723 |
| | (36 | ) | | 1,687 |
| | — |
| | 1,687 |
| ERCOT | 572 |
| | 560 |
| | 1,132 |
| | 1 |
| | 1,133 |
| Other Power Regions | 3,530 |
| | 871 |
| | 4,401 |
| | (66 | ) | | 4,335 |
| Total Competitive Businesses Electric Revenues | 15,593 |
| | 1,818 |
| | 17,411 |
| | (63 | ) | | 17,348 |
| Competitive Businesses Natural Gas Revenues | 1,524 |
| | 1,194 |
| | 2,718 |
| | 62 |
| | 2,780 |
| Competitive Businesses Other Revenues(c) | 510 |
| | (202 | ) | | 308 |
| | 1 |
| | 309 |
| Total Generation Consolidated Operating Revenues | $ | 17,627 |
| | $ | 2,810 |
| | $ | 20,437 |
| | $ | — |
| | $ | 20,437 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2021 | | Revenues from external customers(a) | | | | | | Contracts with customers | | Other(b) | | Total | | Intersegment Revenues | | Total Revenues | Mid-Atlantic | $ | 4,381 | | | $ | 183 | | | $ | 4,564 | | | $ | 20 | | | $ | 4,584 | | Midwest | 4,265 | | | (205) | | | 4,060 | | | — | | | 4,060 | | New York | 1,633 | | | (57) | | | 1,576 | | | (1) | | | 1,575 | | ERCOT | 896 | | | 276 | | | 1,172 | | | 9 | | | 1,181 | | Other Power Regions | 3,937 | | | 981 | | | 4,918 | | | (28) | | | 4,890 | | Total Competitive Businesses Electric Revenues | $ | 15,112 | | | $ | 1,178 | | | $ | 16,290 | | | $ | — | | | $ | 16,290 | | Competitive Businesses Natural Gas Revenues | 1,777 | | | 1,602 | | | 3,379 | | | — | | | 3,379 | | Competitive Businesses Other Revenues(c) | 365 | | | (385) | | | (20) | | | — | | | (20) | | Total Generation Consolidated Operating Revenues | $ | 17,254 | | | $ | 2,395 | | | $ | 19,649 | | | $ | — | | | $ | 19,649 | |
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 5 — Segment Information
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2020 | | Revenues from external customers(a) | | | | | | Contracts with customers | | Other(b) | | Total | | Intersegment Revenues | | Total Revenues | Mid-Atlantic | $ | 4,785 | | | $ | (168) | | | $ | 4,617 | | | $ | 28 | | | $ | 4,645 | | Midwest | 3,717 | | | 312 | | | 4,029 | | | (5) | | | 4,024 | | New York | 1,444 | | | (12) | | | 1,432 | | | (1) | | | 1,431 | | ERCOT | 735 | | | 198 | | | 933 | | | 25 | | | 958 | | Other Power Regions | 3,586 | | | 463 | | | 4,049 | | | (47) | | | 4,002 | | Total Competitive Businesses Electric Revenues | $ | 14,267 | | | $ | 793 | | | $ | 15,060 | | | $ | — | | | $ | 15,060 | | Competitive Businesses Natural Gas Revenues | 1,283 | | | 720 | | | 2,003 | | | — | | | 2,003 | | Competitive Businesses Other Revenues(c) | 355 | | | 185 | | | 540 | | | — | | | 540 | | Total Generation Consolidated Operating Revenues | $ | 15,905 | | | $ | 1,698 | | | $ | 17,603 | | | $ | — | | | $ | 17,603 | |
| | | 2017 | | 2019 | | Revenues from external customers(a) | | | | | | Revenues from external customers(a) | | | Contracts with customers | | Other(b) | | Total | | Intersegment Revenues | | Total Revenues | | Contracts with customers | | Other(b) | | Total | | Intersegment Revenues | | Total Revenues | Mid-Atlantic | $ | 5,523 |
| | $ | (8 | ) | | $ | 5,515 |
| | $ | 25 |
| | $ | 5,540 |
| Mid-Atlantic | $ | 5,053 | | | $ | 17 | | | $ | 5,070 | | | $ | 4 | | | $ | 5,074 | | Midwest | 3,923 |
| | 283 |
| | 4,206 |
| | (25 | ) | | 4,181 |
| Midwest | 4,095 | | | 232 | | | 4,327 | | | (34) | | | 4,293 | | New York | 1,605 |
| | (38 | ) | | 1,567 |
| | (17 | ) | | 1,550 |
| New York | 1,571 | | | 25 | | | 1,596 | | | — | | | 1,596 | | ERCOT | 641 |
| | 317 |
| | 958 |
| | 4 |
| | 962 |
| ERCOT | 768 | | | 229 | | | 997 | | | 16 | | | 1,013 | | Other Power Regions | 2,658 |
| | 428 |
| | 3,086 |
| | (35 | ) | | 3,051 |
| Other Power Regions | 3,687 | | | 608 | | | 4,295 | | | (49) | | | 4,246 | | Total Competitive Businesses Electric Revenues | 14,350 |
| | 982 |
| | 15,332 |
| | (48 | ) | | 15,284 |
| Total Competitive Businesses Electric Revenues | $ | 15,174 | | | $ | 1,111 | | | $ | 16,285 | | | $ | (63) | | | $ | 16,222 | | Competitive Businesses Natural Gas Revenues | 1,658 |
| | 917 |
| | 2,575 |
| | 53 |
| | 2,628 |
| Competitive Businesses Natural Gas Revenues | 1,446 | | | 702 | | | 2,148 | | | 62 | | | 2,210 | | Competitive Businesses Other Revenues(c) | 744 |
| | (151 | ) | | 593 |
| | (5 | ) | | 588 |
| Competitive Businesses Other Revenues(c) | 440 | | | 51 | | | 491 | | | 1 | | | 492 | | Total Generation Consolidated Operating Revenues | $ | 16,752 |
| | $ | 1,748 |
| | $ | 18,500 |
| | $ | — |
| | $ | 18,500 |
| Total Generation Consolidated Operating Revenues | $ | 17,060 | | | $ | 1,864 | | | $ | 18,924 | | | $ | — | | | $ | 18,924 | |
__________ | | (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(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)Represents activities not allocated to a region. See text above for a description of included activities. Includes a $38 million decrease to revenues for the amortization of intangible assets and liabilities related to commodity contracts recorded at fair value in 2017, unrealized mark-to-market losses of $4 million, $262 million, and $131 million in 2019, 2018, and 2017, respectively, and elimination of intersegment revenues. |
Revenues net of purchased powerincluded activities. Includes unrealized mark-to-market losses of $633 million, gains of $110 million and fuel expense (Generation):losses of $4 million for the years ended December 31, 2021, 2020, and 2019, respectively, and the elimination of intersegment revenues.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2019 | | 2018 | | 2017 | | RNF from external customers(a) | | Intersegment RNF | | Total RNF | | RNF from external customers(a) | | Intersegment RNF | | Total RNF | | RNF from external customers(a) | | Intersegment RNF | | Total RNF | Mid-Atlantic | $ | 2,637 |
|
| $ | 18 |
| | $ | 2,655 |
| | $ | 3,022 |
|
| $ | 51 |
| | $ | 3,073 |
| | $ | 3,105 |
|
| $ | 109 |
| | $ | 3,214 |
| Midwest | 2,994 |
|
| (32 | ) | | 2,962 |
| | 3,112 |
|
| 23 |
| | 3,135 |
| | 2,810 |
|
| 10 |
| | 2,820 |
| New York | 1,081 |
|
| 13 |
| | 1,094 |
| | 1,112 |
|
| 10 |
| | 1,122 |
| | 1,007 |
|
| 1 |
| | 1,008 |
| ERCOT | 338 |
|
| (30 | ) | | 308 |
| | 501 |
|
| (243 | ) | | 258 |
| | 575 |
|
| (243 | ) | | 332 |
| Other Power Regions | 694 |
|
| (74 | ) | | 620 |
| | 883 |
|
| (154 | ) | | 729 |
| | 1,014 |
|
| (195 | ) | | 819 |
| Total Revenues net of purchased power and fuel for Reportable Segments | $ | 7,744 |
|
| $ | (105 | ) | | $ | 7,639 |
| | $ | 8,630 |
|
| $ | (313 | ) | | $ | 8,317 |
| | $ | 8,511 |
|
| $ | (318 | ) | | $ | 8,193 |
| Other (b) | 324 |
|
| 105 |
| | 429 |
| | 114 |
|
| 313 |
| | 427 |
| | 299 |
|
| 318 |
| | 617 |
| Total Generation Revenues net of purchased power and fuel expense | $ | 8,068 |
|
| $ | — |
| | $ | 8,068 |
| | $ | 8,744 |
|
| $ | — |
| | $ | 8,744 |
| | $ | 8,810 |
|
| $ | — |
| | $ | 8,810 |
|
__________
| | (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 a $54 million decrease in RNF for the amortization of intangible assets and liabilities related to commodity contracts in 2017, unrealized mark-to-market losses of $215 million, $319 million, and $175 million in 2019, 2018, and 2017, respectively, accelerated nuclear fuel amortization associated with the announced early plant retirements as discussed in Note 6 - Early Plant Retirements of $13 million, $57 million and $12 million in 2019, 2018, and 2017, 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
ElectricRevenues net of purchased power and Gas Revenue by Customer Class (Utility Registrants)fuel expense (Generation):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2021 | | 2020 | | 2019 | | RNF from external customers(a) | | Intersegment RNF | | Total RNF | | RNF from external customers(a) | | Intersegment RNF | | Total RNF | | RNF from external customers(a) | | Intersegment RNF | | Total RNF | Mid-Atlantic | $ | 2,247 | | | $ | 17 | | | $ | 2,264 | | | $ | 2,174 | | | $ | 30 | | | $ | 2,204 | | | $ | 2,637 | | | $ | 18 | | | $ | 2,655 | | Midwest | 2,717 | | | — | | | 2,717 | | | 2,902 | | | — | | | 2,902 | | | 2,994 | | | (32) | | | 2,962 | | New York | 1,151 | | | 10 | | | 1,161 | | | 983 | | | 14 | | | 997 | | | 1,081 | | | 13 | | | 1,094 | | ERCOT | (668) | | | (157) | | | (825) | | | 407 | | | 19 | | | 426 | | | 338 | | | (30) | | | 308 | | Other Power Regions | 984 | | | (93) | | | 891 | | | 759 | | | (94) | | | 665 | | | 694 | | | (74) | | | 620 | | Total RNF for Reportable Segments | $ | 6,431 | | | $ | (223) | | | $ | 6,208 | | | $ | 7,225 | | | $ | (31) | | | $ | 7,194 | | | $ | 7,744 | | | $ | (105) | | | $ | 7,639 | | Other(b) | 1,055 | | | 223 | | | 1,278 | | | 793 | | | 31 | | | 824 | | | 324 | | | 105 | | | 429 | | Total Generation RNF | $ | 7,486 | | | $ | — | | | $ | 7,486 | | | $ | 8,018 | | | $ | — | | | $ | 8,018 | | | $ | 8,068 | | | $ | — | | | $ | 8,068 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2019 | | | | | | | | | | | | | | | Revenues from contracts with customers | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Rate-regulated electric revenues | | | | | | | | | | | | | | Residential | $ | 2,916 |
| | $ | 1,596 |
| | $ | 1,326 |
| | $ | 2,316 |
| | $ | 1,012 |
| | $ | 645 |
| | $ | 659 |
| Small commercial & industrial | 1,463 |
| | 404 |
| | 254 |
| | 505 |
| | 149 |
| | 186 |
| | 170 |
| Large commercial & industrial | 540 |
| | 219 |
| | 436 |
| | 1,112 |
| | 833 |
| | 99 |
| | 180 |
| Public authorities & electric railroads | 47 |
| | 29 |
| | 27 |
| | 61 |
| | 34 |
| | 14 |
| | 13 |
| Other(a) | 888 |
| | 249 |
| | 321 |
| | 650 |
| | 227 |
| | 204 |
| | 218 |
| Total rate-regulated electric revenues(b) | 5,854 |
| | 2,497 |
| | 2,364 |
| | 4,644 |
| | 2,255 |
| | 1,148 |
| | 1,240 |
| Rate-regulated natural gas revenues | | | | | | | | | | | | | | Residential | — |
| | 409 |
| | 474 |
| | 96 |
| | — |
| | 96 |
| | — |
| Small commercial & industrial | — |
| | 169 |
| | 77 |
| | 44 |
| | — |
| | 45 |
| | — |
| Large commercial & industrial | — |
| | 1 |
| | 132 |
| | 5 |
| | — |
| | 5 |
| | — |
| Transportation | — |
| | 25 |
| | — |
| | 14 |
| | — |
| | 14 |
| | — |
| Other(c) | — |
| | 6 |
| | 31 |
| | 7 |
| | — |
| | 7 |
| | — |
| Total rate-regulated natural gas revenues(d) | — |
| | 610 |
| | 714 |
| | 166 |
| | — |
| | 167 |
| | — |
| Total rate-regulated revenues from contracts with customers | 5,854 |
| | 3,107 |
| | 3,078 |
| | 4,810 |
| | 2,255 |
| | 1,315 |
| | 1,240 |
| | | | | | | | | | | | | | | Other revenues | | | | | | | | | | | | | | Revenues from alternative revenue programs | (133 | ) | | (21 | ) | | 12 |
| | (14 | ) | | (3 | ) | | (11 | ) | | — |
| Other rate-regulated electric revenues(e) | 26 |
| | 13 |
| | 12 |
| | 10 |
| | 8 |
| | 2 |
| | — |
| Other rate-regulated natural gas revenues(e) | — |
| | 1 |
| | 4 |
| | — |
| | — |
| | — |
| | — |
| Total other revenues | (107 | ) | | (7 | ) | | 28 |
| | (4 | ) | | 5 |
| | (9 | ) | | — |
| Total rate-regulated revenues for reportable segments | $ | 5,747 |
| | $ | 3,100 |
| | $ | 3,106 |
| | $ | 4,806 |
| | $ | 2,260 |
| | $ | 1,306 |
| | $ | 1,240 |
|
__________
(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 $565 millionand $295 million and losses of $215 million for the years ended December 31, 2021, 2020, and 2019, respectively; •accelerated nuclear fuel amortization associated with the announced early plant retirements as discussed in Note 7 - Early Plant Retirements of $148 million, $60 million, and $13 million in for the years ended December 31, 2021, 2020, and 2019, 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):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2021 | | | | | | | | | | | | | | | Revenues from contracts with customers | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Rate-regulated electric revenues | | | | | | | | | | | | | | Residential | $ | 3,233 | | | $ | 1,704 | | | $ | 1,375 | | | $ | 2,441 | | | $ | 1,003 | | | $ | 694 | | | $ | 744 | | Small commercial & industrial | 1,571 | | | 422 | | | 267 | | | 521 | | | 135 | | | 193 | | | 193 | | Large commercial & industrial | 559 | | | 243 | | | 459 | | | 1,123 | | | 844 | | | 94 | | | 185 | | Public authorities & electric railroads | 45 | | | 31 | | | 27 | | | 58 | | | 31 | | | 14 | | | 13 | | Other(a) | 926 | | | 229 | | | 371 | | | 634 | | | 205 | | | 201 | | | 229 | | Total rate-regulated electric revenues(b) | $ | 6,334 | | | $ | 2,629 | | | $ | 2,499 | | | $ | 4,777 | | | $ | 2,218 | | | $ | 1,196 | | | $ | 1,364 | | Rate-regulated natural gas revenues | | | | | | | | | | | | | | Residential | $ | — | | | $ | 372 | | | $ | 518 | | | $ | 97 | | | $ | — | | | $ | 97 | | | $ | — | | Small commercial & industrial | — | | | 136 | | | 83 | | | 42 | | | — | | | 42 | | | — | | Large commercial & industrial | — | | | — | | | 147 | | | 7 | | | — | | | 7 | | | — | | Transportation | — | | | 24 | | | — | | | 14 | | | — | | | 14 | | | — | | Other(c) | — | | | 7 | | | 68 | | | 8 | | | — | | | 8 | | | — | | Total rate-regulated natural gas revenues(d) | $ | — | | | $ | 539 | | | $ | 816 | | | $ | 168 | | | $ | — | | | $ | 168 | | | $ | — | | Total rate-regulated revenues from contracts with customers | $ | 6,334 | | | $ | 3,168 | | | $ | 3,315 | | | $ | 4,945 | | | $ | 2,218 | | | $ | 1,364 | | | $ | 1,364 | | Other revenues | | | | | | | | | | | | | | Revenues from alternative revenue programs | $ | 42 | | | $ | 26 | | | $ | 12 | | | $ | 91 | | | $ | 53 | | | $ | 14 | | | $ | 24 | | Other rate-regulated electric revenues(e) | 30 | | | 4 | | | 11 | | | 5 | | | 3 | | | 2 | | | — | | Other rate-regulated natural gas revenues(e) | — | | | — | | | 3 | | | — | | | — | | | — | | | — | | | | | | | | | | | | | | | | Total other revenues | $ | 72 | | | $ | 30 | | | $ | 26 | | | $ | 96 | | | $ | 56 | | | $ | 16 | | | $ | 24 | | Total rate-regulated revenues for reportable segments | $ | 6,406 | | | $ | 3,198 | | | $ | 3,341 | | | $ | 5,041 | | | $ | 2,274 | | | $ | 1,380 | | | $ | 1,388 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2018 | | | | | | | | | | | | | | | Revenues from contracts with customers | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Rate-regulated electric revenues | | | | | | | | | | | | | | Residential | $ | 2,942 |
| | $ | 1,566 |
| | $ | 1,382 |
| | $ | 2,351 |
| | $ | 1,021 |
| | $ | 669 |
| | $ | 661 |
| Small commercial & industrial | 1,487 |
| | 404 |
| | 257 |
| | 488 |
| | 140 |
| | 186 |
| | 162 |
| Large commercial & industrial | 538 |
| | 223 |
| | 429 |
| | 1,124 |
| | 846 |
| | 100 |
| | 178 |
| Public authorities & electric railroads | 47 |
| | 28 |
| | 28 |
| | 58 |
| | 32 |
| | 14 |
| | 12 |
| Other(a) | 867 |
| | 243 |
| | 327 |
| | 593 |
| | 193 |
| | 175 |
| | 227 |
| Total rate-regulated electric revenues(b) | 5,881 |
| | 2,464 |
| | 2,423 |
| | 4,614 |
| | 2,232 |
| | 1,144 |
| | 1,240 |
| Rate-regulated natural gas revenues | | | | | | | | | | | | | | Residential | — |
| | 395 |
| | 491 |
| | 99 |
| | — |
| | 99 |
| | — |
| Small commercial & industrial | — |
| | 143 |
| | 77 |
| | 44 |
| | — |
| | 44 |
| | — |
| Large commercial & industrial | — |
| | 1 |
| | 124 |
| | 8 |
| | — |
| | 8 |
| | — |
| Transportation | — |
| | 23 |
| | — |
| | 16 |
| | — |
| | 16 |
| | — |
| Other(c) | — |
| | 6 |
| | 63 |
| | 13 |
| | — |
| | 13 |
| | — |
| Total rate-regulated natural gas revenues(d) | — |
| | 568 |
| | 755 |
| | 180 |
| | — |
| | 180 |
| | — |
| Total rate-regulated revenues from contracts with customers | 5,881 |
| | 3,032 |
| | 3,178 |
| | 4,794 |
| | 2,232 |
| | 1,324 |
| | 1,240 |
| | | | | | | | | | | | | | | Other revenues | | | | | | | | | | | | | | Revenues from alternative revenue programs | (29 | ) | | (7 | ) | | (26 | ) | | (7 | ) | | (7 | ) | | 4 |
| | (4 | ) | Other rate-regulated electric revenues(e) | 30 |
| | 12 |
| | 13 |
| | 10 |
| | 7 |
| | 3 |
| | — |
| Other rate-regulated natural gas revenues(e) | — |
| | 1 |
| | 4 |
| | 1 |
| | — |
| | 1 |
| | — |
| Total other revenues | 1 |
| | 6 |
| | (9 | ) | | 4 |
| | — |
| | 8 |
| | (4 | ) | Total rate-regulated revenues for reportable segments | $ | 5,882 |
| | $ | 3,038 |
| | $ | 3,169 |
| | $ | 4,798 |
| | $ | 2,232 |
| | $ | 1,332 |
| | $ | 1,236 |
|
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 5 — Segment Information
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2020 | | | | | | | | | | | | | | | Revenues from contracts with customers | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Rate-regulated electric revenues | | | | | | | | | | | | | | Residential | $ | 3,090 | | | $ | 1,656 | | | $ | 1,345 | | | $ | 2,332 | | | $ | 988 | | | $ | 652 | | | $ | 692 | | Small commercial & industrial | 1,399 | | | 386 | | | 241 | | | 472 | | | 132 | | | 171 | | | 169 | | Large commercial & industrial | 515 | | | 228 | | | 406 | | | 1,001 | | | 736 | | | 89 | | | 176 | | Public authorities & electric railroads | 45 | | | 29 | | | 27 | | | 60 | | | 34 | | | 13 | | | 13 | | Other(a) | 884 | | | 225 | | | 309 | | | 613 | | | 218 | | | 190 | | | 207 | | Total rate-regulated electric revenues(b) | $ | 5,933 | | | $ | 2,524 | | | $ | 2,328 | | | $ | 4,478 | | | $ | 2,108 | | | $ | 1,115 | | | $ | 1,257 | | Rate-regulated natural gas revenues | | | | | | | | | | | | | | Residential | $ | — | | | $ | 361 | | | $ | 504 | | | $ | 96 | | | $ | — | | | $ | 96 | | | $ | — | | Small commercial & industrial | — | | | 126 | | | 79 | | | 42 | | | — | | | 42 | | | — | | Large commercial & industrial | — | | | — | | | 135 | | | 4 | | | — | | | 4 | | | — | | Transportation | — | | | 24 | | | — | | | 14 | | | — | | | 14 | | | — | | Other(c) | — | | | 4 | | | 29 | | | 6 | | | — | | | 6 | | | — | | Total rate-regulated natural gas revenues(d) | $ | — | | | $ | 515 | | | $ | 747 | | | $ | 162 | | | $ | — | | | $ | 162 | | | $ | — | | Total rate-regulated revenues from contracts with customers | $ | 5,933 | | | $ | 3,039 | | | $ | 3,075 | | | $ | 4,640 | | | $ | 2,108 | | | $ | 1,277 | | | $ | 1,257 | | Other revenues | | | | | | | | | | | | | | Revenues from alternative revenue programs | $ | (47) | | | $ | 16 | | | $ | 16 | | | $ | 21 | | | $ | 40 | | | $ | (7) | | | $ | (12) | | Other rate-regulated electric revenues(e) | 18 | | | 3 | | | 5 | | | 2 | | | 1 | | | 1 | | | — | | Other rate-regulated natural gas revenues(e) | — | | | — | | | 2 | | | — | | | — | | | — | | | — | | | | | | | | | | | | | | | | Total other revenues | $ | (29) | | | $ | 19 | | | $ | 23 | | | $ | 23 | | | $ | 41 | | | $ | (6) | | | $ | (12) | | Total rate-regulated revenues for reportable segments | $ | 5,904 | | | $ | 3,058 | | | $ | 3,098 | | | $ | 4,663 | | | $ | 2,149 | | | $ | 1,271 | | | $ | 1,245 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2017 | Revenues from contracts with customers | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Rate-regulated electric revenues | | | | | | | | | | | | | | Residential | $ | 2,715 |
| | $ | 1,505 |
| | $ | 1,365 |
| | $ | 2,246 |
| | $ | 964 |
| | $ | 663 |
| | $ | 619 |
| Small commercial & industrial | 1,363 |
| | 401 |
| | 254 |
| | 490 |
| | 137 |
| | 187 |
| | 166 |
| Large commercial & industrial | 455 |
| | 223 |
| | 427 |
| | 1,086 |
| | 794 |
| | 103 |
| | 189 |
| Public authorities & electric railroads | 44 |
| | 30 |
| | 31 |
| | 60 |
| | 33 |
| | 14 |
| | 13 |
| Other(a) | 886 |
| | 204 |
| | 299 |
| | 541 |
| | 199 |
| | 163 |
| | 191 |
| Total rate-regulated electric revenues(b) | 5,463 |
| | 2,363 |
| | 2,376 |
| | 4,423 |
| | 2,127 |
| | 1,130 |
| | 1,178 |
| Rate-regulated natural gas revenues | | | | | | | | | | | | | | Residential | — |
| | 331 |
| | 437 |
| | 90 |
| | — |
| | 90 |
| | — |
| Small commercial & industrial | — |
| | 131 |
| | 75 |
| | 38 |
| | — |
| | 38 |
| | — |
| Large commercial & industrial | — |
| | 1 |
| | 119 |
| | 8 |
| | — |
| | 8 |
| | — |
| Transportation | — |
| | 23 |
| | — |
| | 15 |
| | — |
| | 15 |
| | — |
| Other(c) | — |
| | 8 |
| | 28 |
| | 9 |
| | — |
| | 9 |
| | — |
| Total rate-regulated natural gas revenues(d) | — |
| | 494 |
| | 659 |
| | 160 |
| | — |
| | 160 |
| | — |
| Total rate-regulated revenues from contracts with customers | 5,463 |
| | 2,857 |
| | 3,035 |
| | 4,583 |
| | 2,127 |
| | 1,290 |
| | 1,178 |
| | | | | | | | | | | | | | | Other revenues | | | | | | | | | | | | | | Revenues from alternative revenue programs | 43 |
| | — |
| | 124 |
| | 33 |
| | 19 |
| | 6 |
| | 8 |
| Other rate-regulated electric revenues(e) | 30 |
| | 12 |
| | 13 |
| | 8 |
| | 5 |
| | 3 |
| | — |
| Other rate-regulated natural gas revenues(e) | — |
| | 1 |
| | 4 |
| | 1 |
| | — |
| | 1 |
| | — |
| Other revenues(f) | — |
| | — |
| | — |
| | 47 |
| | — |
| | — |
| | — |
| Total other revenues | 73 |
| | 13 |
| | 141 |
| | 89 |
| | 24 |
| | 10 |
| | 8 |
| Total rate-regulated revenues for reportable segments | $ | 5,536 |
| | $ | 2,870 |
| | $ | 3,176 |
| | $ | 4,672 |
| | $ | 2,151 |
| | $ | 1,300 |
| | $ | 1,186 |
|
__________
| | (a) | Includes revenues from transmission revenue from PJM, wholesale electric revenue and mutual assistance revenue. |
| | (b) | Includes operating revenues from affiliates of $30 million, $5 million, $8 million, $14 million, $5 million, $7 million and $3 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, in 2019, $27 million, $7 million, $8 million, $15 million, $6 million, $8 million and $3 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, in 2018, and $15 million, $6 million, $5 million, $3 million, $6 million, $8 million and $2 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, in 2017. |
| | (c) | Includes revenues from off-system natural gas sales. |
| | (d) | Includes operating revenues from affiliates of $1 million and $18 million at PECO and BGE, respectively, in 2019, $1 million and $21 million at PECO and BGE, respectively, in 2018, and $1 million and $11 million at PECO and BGE, respectively, in 2017. |
| | (e) | Includes late payment charge revenues. |
| | (f) | Includes operating revenues from affiliates of $47 million at PHI in 2017.
|
6. Early Plant Retirements (Exelon and Generation)
Exelon and Generation continuously evaluate factors that affect the current and expected economic value 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 rules 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,
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 5 — Segment Information | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2019 | Revenues from contracts with customers | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Rate-regulated electric revenues | | | | | | | | | | | | | | Residential | $ | 2,916 | | | $ | 1,596 | | | $ | 1,326 | | | $ | 2,316 | | | $ | 1,012 | | | $ | 645 | | | $ | 659 | | Small commercial & industrial | 1,463 | | | 404 | | | 254 | | | 505 | | | 149 | | | 186 | | | 170 | | Large commercial & industrial | 540 | | | 219 | | | 436 | | | 1,112 | | | 833 | | | 99 | | | 180 | | Public authorities & electric railroads | 47 | | | 29 | | | 27 | | | 61 | | | 34 | | | 14 | | | 13 | | Other(a) | 888 | | | 249 | | | 321 | | | 650 | | | 227 | | | 204 | | | 218 | | Total rate-regulated electric revenues(b) | $ | 5,854 | | | $ | 2,497 | | | $ | 2,364 | | | $ | 4,644 | | | $ | 2,255 | | | $ | 1,148 | | | $ | 1,240 | | Rate-regulated natural gas revenues | | | | | | | | | | | | | | Residential | $ | — | | | $ | 409 | | | $ | 474 | | | $ | 96 | | | $ | — | | | $ | 96 | | | $ | — | | Small commercial & industrial | — | | | 169 | | | 77 | | | 44 | | | — | | | 45 | | | — | | Large commercial & industrial | — | | | 1 | | | 132 | | | 5 | | | — | | | 5 | | | — | | Transportation | — | | | 25 | | | — | | | 14 | | | — | | | 14 | | | — | | Other(c) | — | | | 6 | | | 31 | | | 7 | | | — | | | 7 | | | — | | Total rate-regulated natural gas revenues(d) | $ | — | | | $ | 610 | | | $ | 714 | | | $ | 166 | | | $ | — | | | $ | 167 | | | $ | — | | Total rate-regulated revenues from contracts with customers | $ | 5,854 | | | $ | 3,107 | | | $ | 3,078 | | | $ | 4,810 | | | $ | 2,255 | | | $ | 1,315 | | | $ | 1,240 | | Other revenues | | | | | | | | | | | | | | Revenues from alternative revenue programs | $ | (133) | | | $ | (21) | | | $ | 12 | | | $ | (14) | | | $ | (3) | | | $ | (11) | | | $ | — | | Other rate-regulated electric revenues(e) | 26 | | | 13 | | | 12 | | | 10 | | | 8 | | | 2 | | | — | | Other rate-regulated natural gas revenues(e) | — | | | 1 | | | 4 | | | — | | | — | | | — | | | — | | | | | | | | | | | | | | | | Total other revenues | $ | (107) | | | $ | (7) | | | $ | 28 | | | $ | (4) | | | $ | 5 | | | $ | (9) | | | $ | — | | Total rate-regulated revenues for reportable segments | $ | 5,747 | | | $ | 3,100 | | | $ | 3,106 | | | $ | 4,806 | | | $ | 2,260 | | | $ | 1,306 | | | $ | 1,240 | |
__________ (a)Includes revenues from transmission revenue from PJM, wholesale electric revenue and mutual assistance revenue. (b)Includes operating revenues from affiliates in 2021, 2020, and 2019 respectively of: •$41 million, $37 million, and $30 million at ComEd •$20 million, $8 million, and $5 million at PECO •$13 million, $10 million, and $8 million at BGE •$13 million, $17 million, and $14 million at PHI •$5 million, $7 million, and $5 million at Pepco •$7 million, $9 million, and $7 million at DPL •$2 million, $4 million, and $3 million at ACE (c)Includes revenues from off-system natural gas sales. (d)Includes operating revenues from affiliates in 2021, 2020, and 2019 respectively of: •$1 million, $1 million, and $1 million at PECO •$18 million, $10 million, and $18 million at BGE (e)Includes late payment charge revenues.
Combined Notes to Consolidated Financial Statements (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. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, 2021 | | Exelon | | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Balance as of December 31, 2020 | $ | 366 | | | | | $ | 97 | | | $ | 116 | | | $ | 35 | | | $ | 86 | | | $ | 32 | | | $ | 22 | | | $ | 32 | | Plus: Current period provision for expected credit losses(a) | 126 | | | | | 21 | | | 23 | | | 15 | | | 37 | | | 13 | | | 6 | | | 18 | | Less: Write-offs, net of recoveries(b)(c) | 117 | | | | | 45 | | | 34 | | | 12 | | | 19 | | | 8 | | | 10 | | | 1 | | | | | | | | | | | | | | | | | | | | Balance as of December 31, 2021 | $ | 375 | | | | | $ | 73 | | | $ | 105 | | | $ | 38 | | | $ | 104 | | | $ | 37 | | | $ | 18 | | | $ | 49 | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, 2020 | | Exelon | | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Balance as of December 31, 2019 | $ | 243 | | | | | $ | 59 | | | $ | 55 | | | $ | 12 | | | $ | 37 | | | $ | 13 | | | $ | 11 | | | $ | 13 | | Plus: Current period provision for expected credit losses(d) | 248 | | | | | 62 | | | 79 | | | 30 | | | 64 | | | 24 | | | 15 | | | 25 | | Less: Write-offs, net of recoveries(c) | 69 | | | | | 24 | | | 18 | | | 7 | | | 15 | | | 5 | | | 4 | | | 6 | | Less: Sale of customer accounts receivable(e) | 56 | | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Balance as of December 31, 2020 | $ | 366 | | | | | $ | 97 | | | $ | 116 | | | $ | 35 | | | $ | 86 | | | $ | 32 | | | $ | 22 | | | $ | 32 | |
_________ (a)For Exelon, the increase primarily relates to the impacts of the February 2021 extreme cold weather event. See Note 3 — Regulatory Matters for additional information. For the Utility Registrants, the increase is primarily a result of increased aging of receivables. (b)For ComEd, PECO and DPL, the increase in 2021 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 2021, write-offs of aging accounts receivable increased throughout the year. (c)Recoveries were not material to the Registrants. (d)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 reconnection of service to customers previously disconnected due to COVID-19. (e)See below for additional information on the sale of customer accounts receivable 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. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, 2021 | | Exelon | | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Balance as of December 31, 2020 | $ | 71 | | | | | $ | 21 | | | $ | 8 | | | $ | 9 | | | $ | 33 | | | $ | 13 | | | $ | 9 | | | $ | 11 | | Plus: Current period provision for expected credit losses | 15 | | | | | (2) | | | 3 | | | 4 | | | 6 | | | 3 | | | (1) | | | 4 | | Less: Write-offs, net of recoveries(a) | 10 | | | | | 2 | | | 4 | | | 4 | | | — | | | — | | | — | | | — | | Balance as of December 31, 2021 | $ | 76 | | | | | $ | 17 | | | $ | 7 | | | $ | 9 | | | $ | 39 | | | $ | 16 | | | $ | 8 | | | $ | 15 | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, 2020 | | Exelon | | | | 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 | 33 | | | | | 5 | | | 3 | | | 7 | | | 18 | | | 6 | | | 5 | | | 7 | | Less: Write-offs, net of recoveries(a) | 10 | | | | | 4 | | | 2 | | | 3 | | | 1 | | | — | | | — | | | 1 | | Balance as of December 31, 2020 | $ | 71 | | | | | $ | 21 | | | $ | 8 | | | $ | 9 | | | $ | 33 | | | $ | 13 | | | $ | 9 | | | $ | 11 | |
_________ (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 December 31, 2021 and 2020. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Unbilled customer revenues(a) | | Exelon | | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | December 31, 2021 | $ | 1,120 | | | | | $ | 240 | | | $ | 161 | | | $ | 171 | | | $ | 175 | | | $ | 82 | | | $ | 53 | | | $ | 40 | | December 31, 2020 | 998 | | | | | 218 | | | 147 | | | 197 | | | 178 | | | 87 | | | 62 | | | 29 | |
_________ (a)Unbilled customer revenues are classified in Customer accounts receivables, net in the Registrants' Consolidated Balance Sheets. Sales of Customer Accounts Receivable (Exelon) 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 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 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, Exelon 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, Exelon received additional cash of $250 million from the Purchasers for the remaining available funding in the Facility. Additionally, during the first quarter of 2021, Exelon 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, Exelon returned cash of $50 million to the Purchasers due to the eligible receivables decreasing temporarily. Subsequently, in the second quarter, Exelon 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 in Cash flows from investing activities in Exelon’s Consolidated Statement 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: | | | | | | | | | | | | | As of December 31, | | 2021 | | 2020 | Derecognized receivables transferred at fair value | $ | 1,265 | | | $ | 1,139 | | Cash proceeds received | 900 | | | 500 | | DPP | 365 | | | 639 | |
| | | | | | | | | | | | | For the Year Ended December 31, | | 2021 | | 2020 | Loss on sale of receivables(a) | $ | 36 | | | $ | 30 | |
_________ (a)Reflected in Operating and maintenance expense in Exelon's Consolidated Statements of Operations and Comprehensive Income.
| | | | | | | | | | | | | For the Year Ended December 31, | | 2021 | | 2020 | Proceeds from new transfers(a) | $ | 6,095 | | | $ | 2,816 | | Cash collections received on DPP and reinvested in the Facility(b) | 3,502 | | | 3,771 | | Cash collections reinvested in the Facility | 9,597 | | | 6,587 | |
_________ (a)Customer accounts receivable sold into the Facility were $9,747 million and $6,608 million for the years ended December 31, 2021 and December 31, 2020, respectively. (b)Does not include the $400 million in cash proceeds received from the Purchasers in the first quarter of 2021. The 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. Exelon did not record a servicing asset or liability as the servicing fees were immaterial. Exelon 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 18 — Fair Value of Financial Assets and Liabilities and Note 23 — 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) The Utility Registrants are required, under separate legislation and regulations in Illinois, Pennsylvania, Maryland, District of Columbia, and New Jersey, to purchase certain receivables from alternative retail electric and, as applicable, natural gas suppliers that participate in the utilities' consolidated billing. 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 other purchases and sales of customer and other accounts receivable activity related to Generation is eliminated upon consolidation in Exelon's Consolidated Financial Statements. The following tables present the total receivables purchased and sold. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, 2021 | | Exelon | | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Total receivables purchased | $ | 3,817 | | | | | $ | 1,031 | | | $ | 1,041 | | | $ | 687 | | | $ | 1,081 | | | $ | 660 | | | $ | 217 | | | $ | 204 | | Total receivables sold | 124 | | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | | | | | | | | | | | | | | | | | | Related party transactions: | | | | | | | | | | | | | | | | | | Receivables purchased from Generation | — | | | | | 1 | | | 1 | | | 21 | | | — | | | — | | | — | | | — | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, 2020 | | Exelon | | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Total receivables purchased | $ | 3,529 | | | | | $ | 1,094 | | | $ | 1,020 | | | $ | 652 | | | $ | 1,015 | | | $ | 622 | | | $ | 207 | | | $ | 186 | | Total receivables sold | 572 | | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | | | | | | | | | | | | | | | | | | Related party transactions: | | | | | | | | | | | | | | | | | | Receivables purchased from Generation | — | | | | | 34 | | | 67 | | | 79 | | | 72 | | | 51 | | | 13 | | | 8 | | | | | | | | | | | | | | | | | | | |
7. Early Plant Retirements (Exelon)
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, just prior to its next scheduled nuclear refueling outage.
Nuclear Generation In 2015On August 27, 2020, Generation announced that it intended to permanently cease generation operations at Byron in September 2021 and 2016, Generation identifiedat Dresden in November 2021. Neither of these nuclear plants cleared in PJM’s capacity auction for the Clinton2022-2023 planning year held in May 2021. Generation’s Braidwood and Quad CitiesLaSalle nuclear plants in Illinois Ginna and Nine Mile Pointdid 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 authorized 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 New YorkPJM. The Byron, Dresden, and Three Mile Island nuclear plant in Pennsylvania as having the greatest risk of early retirement based on economic valuation and other factors. In 2017, PSEG made public similar financial challenges facing its New JerseyBraidwood nuclear plants including Salem, of which Generation owns a 42.59% ownership interest. PSEG islocated in Illinois participated in the operator of SalemCMC procurement process and also has the decision-making authoritywere awarded contracts that commit each plant to retire Salem. Assuming the continued effectiveness of the Illinois ZES, New Jersey ZEC program and the New York CES, Generation and CENG,operate through its ownership of Ginna and Nine Mile Point, no longer consider Clinton, Quad Cities, Salem, Ginna or Nine Mile Point to be at heightened risk for early retirement. However, to the extent the Illinois ZES, New Jersey ZEC program or the New York CES do not operate as expected over their full terms, each of these plants could again be at heightened risk for early retirement, which could have a material impact on Exelon’s and Generation’s future financial statements. In addition, FERC’s December 19, 2019 order on the MOPR in PJM may undermine the continued effectiveness of the Illinois ZES and the New Jersey ZEC program unless Illinois and New Jersey implement an FRR mechanism under which the Generation plants in these states would be removed from PJM’s capacity auction.May 31, 2027. See Note 3 — Regulatory Matters for additional informationinformation. Following enactment of the legislation, Generation announced on September 15, 2021, that it has reversed the Illinois ZES, New Jersey ZEC program, New York CESprevious decision to retire Byron and FERC's December 19, 2019 order.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 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
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 7 — Early Plant Retirements 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 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, the expected economic useful life for both facilities was updated 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 10 — Asset Retirement Obligations 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. In Pennsylvania, the TMI nuclear plant did not clear in the May 2017 PJM capacity auction for the 2020-2021 planning year, the third consecutive year that TMI failed to clear the PJM base residual capacity auction and on May 30, 2017, based on these capacity auction results, prolonged periods of low wholesale power prices, and the absence of federal or state policies, that place a value on nuclear energy for its ability to produce electricity without air pollution, Generation announced that it would permanently cease generation operations at TMI. On September 20, 2019, GenerationTMI permanently ceased generation operationsoperations. The total impact for the years ended December 31, 2021, 2020, and 2019 in Exelon'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, and decision to early retire TMI is summarized in the table below. | | | | | | | | | | | | | | | | | | | | | Income statement expense (pre-tax) | | 2021(a) | | 2020(a) | | 2019(b) | Depreciation and amortization | | | | | | | Accelerated depreciation(c) | | $ | 1,805 | | | $ | 895 | | | $ | 216 | | Accelerated nuclear fuel amortization | | 148 | | | 60 | | | 13 | | Operating and maintenance | | | | | | | One-time charges | | (94) | | | 255 | | | — | | Other charges(d) | | 9 | | | 34 | | | (53) | | Contractual offset(e) | | (451) | | | (364) | | | — | | Total | | $ | 1,417 | | | $ | 880 | | | $ | 176 | | | | | | | | |
_________ (a)Reflects expense for Byron and Dresden. (b)Reflects expense for TMI. (c)Includes the accelerated depreciation of plant assets including any ARC. (d)For 2020 and 2019, reflects the net impacts associated with the remeasurement of the ARO. See Note 10 – Asset Retirement Obligations for additional information. (e)Reflects contractual offset for ARO accretion, ARC depreciation, ARO remeasurement, 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 TMI.ComEd. With the 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 Consolidated 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 regulatory liabilities at ComEd. See Note 10 — Asset Retirement Obligations for additional information.
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 the FERC in December 2018. On February 2, 2018,June 10, 2020, Generation announcedfiled a complaint with FERC against ISO-NE stating that it would permanently cease generation operations atISO-NE failed to follow its tariff with respect to its evaluation of Mystic 8 and 9 for transmission security for the Oyster Creek nuclear plant at2024 to 2025 Capacity Commitment Period and that the end ofmodifications that ISO-NE made to its current operating cycle and permanently ceased generation operations on September 17, 2018.
unfiled planning procedures to avoid
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 67 — Early Plant Retirements
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, Generation announced it will permanently cease generation operations at Mystic 8 and 9 at the expiration of the cost of service commitment in May 2024.
As a result of thesethe decision to early nuclear plant retirement decisions,retire Mystic 8 and 9, Exelon recognized $22 million of one-time charges for the year ended December 31, 2020, related to materials and Generation recognized incremental non-cash charges to earningssupplies inventory reserve adjustments, among other items. In addition, there are annual financial impacts stemming from shortening the expected economic useful liveslife of Mystic 8 and 9 primarily related to accelerated depreciation of plant assets (including any ARC)assets. Exelon recorded incremental Depreciation and accelerated amortization expense of nuclear fuel, as well as operating$41 million and maintenance expenses. The total annual impact of these charges by year are summarized in the table below. | | | | | | | | | | | | | | Income statement expense (pre-tax) | | 2019(a) | | 2018(b) | | 2017(c) | Depreciation and Amortization | | | | | | | Accelerated depreciation | | $ | 216 |
| | $ | 539 |
| | $ | 250 |
| Accelerated nuclear fuel amortization | | 13 |
| | 57 |
| | 12 |
| Operating and Maintenance(d) | | (53 | ) | | 32 |
| | 77 |
| Total | | $ | 176 |
| | $ | 628 |
| | $ | 339 |
|
_________
| | (a) | Reflects incremental charges for TMI from January 1, 2019 through September 20, 2019. |
| | (b) | Reflects incremental charges for TMI in 2018 and Oyster Creek from February 2, 2018 through September 17, 2018. |
| | (c) | Reflects incremental charges for TMI from May 30, 2017 through December 31, 2017. |
| | (d) | In 2019, primarily reflects the net impacts associated with the remeasurements of the TMI ARO in the first and third quarters. In 2018 and 2017, primarily reflects materials and supplies inventory reserve adjustments, employee related costs and CWIP impairments associated with the early retirement decisions for TMI and Oyster Creek. Excludes the charges in the third quarter of 2018 and second quarter of 2019 for the ARO remeasurement due to the sale of Oyster Creek. See Note 2 — Mergers, Acquisitions and Dispositions and Note 9 — Asset Retirement Obligations for additional information. |
Generation’s Dresden, Byron, and Braidwood nuclear plants in Illinois are also showing increased signs of economic distress, which could lead to an early retirement, in a market that does not currently compensate them for their unique contribution to grid resiliency and their ability to produce large amounts of energy without carbon and air pollution. The May 2018 PJM capacity auction$26 million for the 2021-2022 planning year resulted in the largest volume of nuclear capacity ever not selected in the auction, including all of Dresden,years ended December 31, 2021 and portions of Byron and Braidwood. Exelon continues to work with stakeholders on state policy solutions, while also advocating2020, respectively. See Note 12 — Asset Impairments for broader market reforms at the regional and federal level.
Other Generation
On March 29, 2018, Generation notified grid operator ISO-NE of its plans to early retire Mystic Units 8 and 9 absent regulatory reforms on June 1, 2022, at the endimpairment assessment considerations of the then-current capacity commitment for Mystic Units 7 and 8. Mystic Unit 9 was then committed through May 2021.
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 and 9 for the period between June 1, 2022 - May 31, 2024. On December 20, 2018, FERC issued an order accepting the cost 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 Everett Marine Terminal. Those adjustments were reflected in a compliance filing filed on March 1, 2019. In the December 20, 2018 order, FERC also directed a paper hearing on ROE using a new methodology. On January 22, 2019, Exelon and several other parties filed requests for rehearing of certain findings in the order.
On March 25, 2019, ISO-NE filed the Inventoried Energy Program, which is intended to provide an interim fuel security program pending conclusion of the stakeholder process to develop a long-term, market-based solution to address fuel security. The Inventoried Energy Program went into effect on August 5, 2019. On October 7, 2019, requests for rehearing were denied and several parties have appealed to the D.C. Circuit Court. FERC ordered ISO-NE to file long-term, market-based fuel security rules by October 15, 2019; FERC has granted an extension to April 15, 2020.
The following table provides the balance sheet amounts as of December 31, 2019 for Exelon's and Generation’s significant assets and liabilities associated with the Mystic Units 8 and 9 and Everett Marine Terminal assets that would potentially be impacted by the failure to adopt long-term solutions for reliability and fuel security.
New England Asset Group.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 6 — Early Plant Retirements
| | | | | | | | December 31, 2019 | Asset Balances | | | Materials and supplies inventory | | $ | 31 |
| Fuel inventory | | 11 |
| Property, plant and equipment, net | | 902 |
| Liability Balances | | | Asset retirement obligation | | (3 | ) |
To ensure the continued reliable supply of fuel to Mystic Units 8 and 9 while they remain operating, on October 1, 2018, Generation acquired the Everett Marine Terminal in Massachusetts for a purchase price of $81 million, with the majority of the fair value allocated to Property, plant and equipment and no goodwill recorded. Generation also settled its existing long-term gas supply agreement, resulting in a pre-tax gain of $75 million, which is included within Purchased power and fuel expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.
See Note 11 — Asset Impairments for impairment assessment considerations on the New England Asset Group.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 7 — Property, Plant, and Equipment
7.8. Property, Plant, and Equipment (All Registrants)
The following tables present a summary of property, plant, and equipment by asset category as of December 31, 20192021 and 2018:2020: | | Asset Category | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Asset Category | Exelon(a) | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | December 31, 2019 | | | | | | | | | | | | | | | | | | | December 31, 2021 | | December 31, 2021 | | | | | | | | | | | | | | | | | Electric—transmission and distribution | $ | 56,809 |
| | $ | — |
| | $ | 27,566 |
| | $ | 8,957 |
| | $ | 8,326 |
| | $ | 13,809 |
| | $ | 9,734 |
| | $ | 4,464 |
| | $ | 4,207 |
| Electric—transmission and distribution | $ | 64,771 | | | | $ | 31,077 | | | $ | 10,076 | | | $ | 9,352 | | | $ | 16,062 | | | $ | 10,798 | | | $ | 4,957 | | | $ | 4,882 | | Electric—generation | 29,839 |
| | 29,839 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Electric—generation | 29,912 | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Gas—transportation and distribution | 6,147 |
| | — |
| | — |
| | 2,899 |
| | 2,999 |
| | 525 |
| | — |
| | 690 |
| | — |
| Gas—transportation and distribution | 7,429 | | | | — | | | 3,339 | | | 3,712 | | | 646 | | | — | | | 806 | | | — | | Common—electric and gas | 1,907 |
| | — |
| | — |
| | 877 |
| | 991 |
| | 146 |
| | — |
| | 160 |
| | — |
| Common—electric and gas | 2,335 | | | | — | | | 1,005 | | | 1,224 | | | 201 | | | — | | | 180 | | | — | | Nuclear fuel(a) | 5,656 |
| | 5,656 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | Nuclear fuel(b) | | Nuclear fuel(b) | 5,166 | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Construction work in progress | 3,055 |
| | 702 |
| | 662 |
| | 250 |
| | 483 |
| | 921 |
| | 628 |
| | 125 |
| | 166 |
| Construction work in progress | 4,097 | | | | 918 | | | 620 | | | 554 | | | 1,590 | | | 1,118 | | | 229 | | | 242 | | Other property, plant and equipment(b) | 799 |
| | 13 |
| | 47 |
| | 27 |
| | 25 |
| | 108 |
| | 64 |
| | 21 |
| | 27 |
| | Total property, plant and equipment | 104,212 |
| | 36,210 |
| | 28,275 |
| | 13,010 |
| | 12,824 |
| | 15,509 |
| | 10,426 |
| | 5,460 |
| | 4,400 |
| | Less: accumulated depreciation(c) | 23,979 |
| | 12,017 |
| | 5,168 |
| | 3,718 |
| | 3,834 |
| | 1,213 |
| | 3,517 |
| | 1,425 |
| | 1,210 |
| | Property, plant and equipment, net | $ | 80,233 |
| | $ | 24,193 |
| | $ | 23,107 |
| | $ | 9,292 |
| | $ | 8,990 |
| | $ | 14,296 |
| | $ | 6,909 |
| | $ | 4,035 |
| | $ | 3,190 |
| | Other property, plant, and equipment(c) | | Other property, plant, and equipment(c) | 827 | | | | 99 | | | 41 | | | 34 | | | 107 | | | 63 | | | 23 | | | 25 | | Total property, plant, and equipment | | Total property, plant, and equipment | 114,537 | | | | 32,094 | | | 15,081 | | | 14,876 | | | 18,606 | | | 11,979 | | | 6,195 | | | 5,149 | | Less: accumulated depreciation(d) | | Less: accumulated depreciation(d) | 30,318 | | | | 6,099 | | | 3,964 | | | 4,299 | | | 2,108 | | | 3,875 | | | 1,635 | | | 1,420 | | Property, plant, and equipment, net | | Property, plant, and equipment, net | $ | 84,219 | | | | $ | 25,995 | | | $ | 11,117 | | | $ | 10,577 | | | $ | 16,498 | | | $ | 8,104 | | | $ | 4,560 | | | $ | 3,729 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2018 | | | | | | | | | | | | | | | | | | | December 31, 2020 | | December 31, 2020 | | | | Electric—transmission and distribution | $ | 53,090 |
| | $ | — |
| | $ | 25,991 |
| | $ | 8,359 |
| | $ | 7,951 |
| | $ | 12,664 |
| | $ | 9,217 |
| | $ | 4,195 |
| | $ | 3,866 |
| Electric—transmission and distribution | $ | 60,946 | | | | $ | 29,371 | | | $ | 9,462 | | | $ | 8,797 | | | $ | 15,137 | | | $ | 10,264 | | | $ | 4,730 | | | $ | 4,568 | | Electric—generation | 29,170 |
| | 29,170 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Electric—generation | 29,725 | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Gas—transportation and distribution | 5,530 |
| | — |
| | — |
| | 2,694 |
| | 2,630 |
| | 486 |
| | — |
| | 651 |
| | — |
| Gas—transportation and distribution | 6,733 | | | | — | | | 3,098 | | | 3,315 | | | 591 | | | — | | | 751 | | | — | | Common—electric and gas | 1,627 |
| | — |
| | — |
| | 756 |
| | 860 |
| | 126 |
| | — |
| | 136 |
| | — |
| Common—electric and gas | 2,170 | | | | — | | | 956 | | | 1,138 | | | 178 | | | — | | | 180 | | | — | | Nuclear fuel(a) | 5,957 |
| | 5,957 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | Nuclear fuel(b) | | Nuclear fuel(b) | 5,399 | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Construction work in progress | 3,377 |
| | 997 |
| | 705 |
| | 343 |
| | 410 |
| | 912 |
| | 536 |
| | 151 |
| | 209 |
| Construction work in progress | 3,576 | | | | 799 | | | 474 | | | 627 | | | 1,174 | | | 824 | | | 163 | | | 182 | | Other property, plant and equipment(b) | 858 |
| | 63 |
| | 46 |
| | 19 |
| | 25 |
| | 99 |
| | 61 |
| | 17 |
| | 28 |
| | Other property, plant and equipment(c) | | Other property, plant and equipment(c) | 762 | | | | 59 | | | 34 | | | 29 | | | 108 | | | 65 | | | 23 | | | 28 | | Total property, plant and equipment | 99,609 |
| | 36,187 |
| | 26,742 |
| | 12,171 |
| | 11,876 |
| | 14,287 |
| | 9,814 |
| | 5,150 |
| | 4,103 |
| Total property, plant and equipment | 109,311 | | | | 30,229 | | | 14,024 | | | 13,906 | | | 17,188 | | | 11,153 | | | 5,847 | | | 4,778 | | Less: accumulated depreciation(c) | 22,902 |
| | 12,206 |
| | 4,684 |
| | 3,561 |
| | 3,633 |
| | 841 |
| | 3,354 |
| | 1,329 |
| | 1,137 |
| | Property, plant and equipment, net | $ | 76,707 |
| | $ | 23,981 |
| | $ | 22,058 |
| | $ | 8,610 |
| | $ | 8,243 |
| | $ | 13,446 |
| | $ | 6,460 |
| | $ | 3,821 |
| | $ | 2,966 |
| | Less: accumulated depreciation(d) | | Less: accumulated depreciation(d) | 26,727 | | | | 5,672 | | | 3,843 | | | 4,034 | | | 1,811 | | | 3,697 | | | 1,533 | | | 1,303 | | Property, plant, and equipment, net | | Property, plant, and equipment, net | $ | 82,584 | | | | $ | 24,557 | | | $ | 10,181 | | | $ | 9,872 | | | $ | 15,377 | | | $ | 7,456 | | | $ | 4,314 | | | $ | 3,475 | |
__________ | | (a) | Includes nuclear fuel that is in the fabrication and installation phase of $1,025 million and $1,004 million at December 31, 2019 and 2018, respectively. |
| | (b) | Primarily composed of land and non-utility property. |
| | (c) | Includes accumulated amortization of nuclear fuel in the reactor core at Generation of $2,867 million and $2,969 million as of December 31, 2019 and 2018, respectively. |
(a)As of December 31, 2021, includes $19,612 million of Property, plant, and equipment, net related to Generation.
(b)Includes nuclear fuel that is in the fabrication and installation phase of $859 million and $939 million as of December 31, 2021 and 2020, respectively. (c)Primarily composed of land and non-utility property. (d)At Exelon, includes accumulated amortization of nuclear fuel in the reactor core of $2,765 million and $2,774 million as of December 31, 2021 and 2020, respectively.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 78 — Property, Plant, and Equipment
The following table presents the average service life for each asset category in number of years: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Average Service Life (years) | Asset Category | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Electric - transmission and distribution | 5-80 | | N/A | | 5-80 | | 5-655-70 | | 5-755-80 | | 5-75 | | 5-75 | | 5-70 | | 5-65 | Electric - generation | 1-561-52 | | 1-56 | | N/A | | N/A | | N/A | | N/A | | N/A | | N/A | | N/A | Gas - transportation and distribution | 5-80 | | | | N/A | | 5-70 | | 5-80 | | 5-75 | | N/A | | 5-705-75 | | 5-80 | | 5-75 | | N/A | | 5-75 | | N/A | Common - electric and gas | 4-75 | | | | N/A | | 5-55 | | 4-50 | | 5-75 | | N/A | | 5-505-75 | | 4-50 | | 5-75 | | N/A | | 5-75 | | N/A | Nuclear fuel | 1-8 | | 1-8 | | N/A | | N/A | | N/A | | N/A | | N/A | | N/A | | N/A | Other property, plant, and equipment | 1-501-61 | | 1-10 | | 34-5032-50 | | 50 | | 20-50 | | 3-50 | | 33-50 | | 8-50 | | 13-15 |
Depreciation provisions are based on the estimated useful lives of the stations, which reflectcorresponds with the first renewalterm of the NRC operating licenses for all of Generation's operatingthe nuclear generating stations except for Clintonunits. Beginning August 2020, Byron, Dresden, and Peach Bottom. Clinton depreciation provisions are based on an estimated useful life through 2027, which is the last year of the Illinois ZES. Peach Bottom depreciation provisions are based on estimated useful life of 2053 and 2054 for Unit 2 and Unit 3, respectively, which reflects the anticipated second renewal of its operating licenses. Beginning in 2017, TMI and Oyster CreekMystic depreciation provisions were based on their 2019 expected shutdown dates. Beginning February 2018, Oyster Creek depreciation provisions were based on its announced shutdown datedates of September 2018.2021, November 2021, and May 2024, respectively. On September 15, 2021, Generation updated the expected useful lives for Byron and Dresden to reflect the end of the available NRC operating license for each unit. See Note 3 — Regulatory Matters for additional information regarding license renewals and the Illinois ZECsrenewal and Note 67 — Early Plant Retirements for additional information on the impacts of early plant retirements.related to Byron, Dresden, and Mystic. The following table presents the annual depreciation rates for each asset category. Nuclear fuel amortization is charged to fuel expense using the unit-of-production method and not included in the below table. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Annual Depreciation Rates | | Exelon | | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | December 31, 2021 | | | | | | | | | | | | | | | | | | Electric—transmission and distribution | 2.81 | % | | | | 2.94 | % | | 2.28 | % | | 2.80 | % | | 2.87 | % | | 2.56 | % | | 2.86 | % | | 3.21 | % | Electric—generation | 8.67 | % | | | | N/A | | N/A | | N/A | | N/A | | N/A | | N/A | | N/A | Gas—transportation and distribution | 2.13 | % | | | | N/A | | 1.84 | % | | 2.54 | % | | 1.47 | % | | N/A | | 1.47 | % | | N/A | Common—electric and gas | 7.31 | % | | | | N/A | | 6.34 | % | | 7.88 | % | | 8.33 | % | | N/A | | 8.69 | % | | N/A | | | | | | | | | | | | | | | | | | | December 31, 2020 | | | | | | | | | | | | | | | | | | Electric—transmission and distribution | 2.79 | % | | | | 2.95 | % | | 2.31 | % | | 2.69 | % | | 2.81 | % | | 2.53 | % | | 2.85 | % | | 3.08 | % | Electric—generation | 6.11 | % | | | | N/A | | N/A | | N/A | | N/A | | N/A | | N/A | | N/A | Gas—transportation and distribution | 2.14 | % | | | | N/A | | 1.85 | % | | 2.56 | % | | 1.50 | % | | N/A | | 1.50 | % | | N/A | Common—electric and gas | 7.01 | % | | | | N/A | | 6.39 | % | | 7.45 | % | | 7.36 | % | | N/A | | 6.72 | % | | N/A | | | | | | | | | | | | | | | | | | | December 31, 2019 | | | | | | | | | | | | | | | | | | Electric—transmission and distribution | 2.80 | % | | | | 2.99 | % | | 2.36 | % | | 2.60 | % | | 2.77 | % | | 2.47 | % | | 2.86 | % | | 2.94 | % | Electric—generation | 4.35 | % | | | | N/A | | N/A | | N/A | | N/A | | N/A | | N/A | | N/A | Gas—transportation and distribution | 2.04 | % | | | | N/A | | 1.89 | % | | 2.30 | % | | 1.55 | % | | N/A | | 1.55 | % | | N/A | Common—electric and gas | 7.37 | % | | | | N/A | | 6.06 | % | | 8.30 | % | | 8.25 | % | | N/A | | 6.24 | % | | N/A |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | Annual Depreciation Rates | | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | December 31, 2019 | | | | | | | | | | | | | | | | | | Electric—transmission and distribution | 2.80 | % | | N/A |
| | 2.99 | % | | 2.36 | % | | 2.60 | % | | 2.77 | % | | 2.47 | % | | 2.86 | % | | 2.94 | % | Electric—generation | 4.35 | % | | 4.35 | % | | N/A |
| | N/A |
| | N/A |
| | N/A |
| | N/A |
| | N/A |
| | N/A |
| Gas—transportation and distribution | 2.04 | % | | N/A |
| | N/A |
| | 1.89 | % | | 2.30 | % | | 1.55 | % | | N/A |
| | 1.55 | % | | N/A |
| Common—electric and gas | 7.37 | % | | N/A |
| | N/A |
| | 6.06 | % | | 8.30 | % | | 8.25 | % | | N/A |
| | 6.24 | % | | N/A |
| | | | | | | | | | | | | | | | | | | December 31, 2018 | | | | | | | | | | | | | | | | | | Electric—transmission and distribution | 2.73 | % | | N/A |
| | 2.95 | % | | 2.35 | % | | 2.61 | % | | 2.61 | % | | 2.40 | % | | 2.77 | % | | 2.45 | % | Electric—generation | 5.37 | % | | 5.37 | % | | N/A |
| | N/A |
| | N/A |
| | N/A |
| | N/A |
| | N/A |
| | N/A |
| Gas—transportation and distribution | 2.07 | % | | N/A |
| | N/A |
| | 1.90 | % | | 2.36 | % | | 1.59 | % | | N/A |
| | 1.59 | % | | N/A |
| Common—electric and gas | 6.98 | % | | N/A |
| | N/A |
| | 5.44 | % | | 8.50 | % | | 6.30 | % | | N/A |
| | 3.70 | % | | N/A |
| | | | | | | | | | | | | | | | | | | December 31, 2017 | | | | | | | | | | | | | | | | | | Electric—transmission and distribution | 2.75 | % | | N/A |
| | 2.99 | % | | 2.37 | % | | 2.58 | % | | 2.63 | % | | 2.35 | % | | 2.75 | % | | 2.46 | % | Electric—generation | 4.36 | % | | 4.36 | % | | N/A |
| | N/A |
| | N/A |
| | N/A |
| | N/A |
| | N/A |
| | N/A |
| Gas—transportation and distribution | 2.10 | % | | N/A |
| | N/A |
| | 1.89 | % | | 2.33 | % | | 2.07 | % | | N/A |
| | 2.07 | % | | N/A |
| Common—electric and gas | 7.05 | % | | N/A |
| | N/A |
| | 5.47 | % | | 8.64 | % | | 6.50 | % | | N/A |
| | 4.14 | % | | N/A |
|
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 78 — Property, Plant, and Equipment
Capitalized Interest and AFUDC (All Registrants) The following table summarizes capitalized interest and credits to AFUDC by year: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | December 31, 2019 | | | | | | | | | | | | | | | | | | Capitalized interest | $ | 24 |
| | $ | 24 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| AFUDC debt and equity | 132 |
| | — |
| | 32 |
| | 17 |
| | 29 |
| | 54 |
| | 39 |
| | 6 |
| | 9 |
| | | | | | | | | | | | | | | | | | | December 31, 2018 | | | | | | | | | | | | | | | | | | Capitalized interest | $ | 31 |
| | $ | 31 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| AFUDC debt and equity | 109 |
| | — |
| | 30 |
| | 12 |
| | 24 |
| | 44 |
| | 34 |
| | 4 |
| | 4 |
| | | | | | | | | | | | | | | | | | | December 31, 2017 | | | | | | | | | | | | | | | | | | Capitalized interest | $ | 63 |
| | $ | 63 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| AFUDC debt and equity | 108 |
| | — |
| | 20 |
| | 12 |
| | 22 |
| | 54 |
| | 34 |
| | 10 |
| | 9 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exelon | | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | December 31, 2021 | | | | | | | | | | | | | | | | | | Capitalized interest | $ | 16 | | | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | AFUDC debt and equity | 189 | | | | | 47 | | | 34 | | | 36 | | | 72 | | | 59 | | | 8 | | | 5 | | | | | | | | | | | | | | | | | | | | December 31, 2020 | | | | | | | | | | | | | | | | | | Capitalized interest | $ | 22 | | | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | AFUDC debt and equity | 150 | | | | | 42 | | | 23 | | | 30 | | | 55 | | | 42 | | | 6 | | | 7 | | | | | | | | | | | | | | | | | | | | December 31, 2019 | | | | | | | | | | | | | | | | | | Capitalized interest | $ | 24 | | | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | AFUDC debt and equity | 132 | | | | | 32 | | | 17 | | | 29 | | | 54 | | | 39 | | | 6 | | | 9 | |
See Note 1 — Significant Accounting Policies for additional information regarding property, plant and equipment policies. See Note 1617 — Debt and Credit Agreements for additional information regarding Exelon’s, ComEd’s, PECO's, Pepco's, DPL's, and PECO’sACE’s property, plant and equipment subject to mortgage liens. 8.9. Jointly Owned Electric Utility Plant (Exelon, Generation, PECO, DPL, and ACE)
Exelon's, Generation's, PECO's, DPL's, and ACE's material undivided ownership interests in jointly owned electric plants and transmission facilities atas of December 31, 20192021 and 20182020 were as follows: | | | Nuclear Generation | | Transmission | | Nuclear Generation | | Transmission | | Quad Cities | | Peach Bottom | | Salem | | Nine Mile Point Unit 2 | | NJ/DE(a) | | Quad Cities | | Peach Bottom | | Salem | | Nine Mile Point Unit 2 | | NJ/DE(a) | Operator | Generation | | Generation | | PSEG Nuclear | | Generation | | PSEG/DPL | Operator | Generation | | Generation | | PSEG Nuclear | | Generation | | PSEG/DPL | Ownership interest | 75.00 | % | | 50.00 | % | | 42.59 | % | | 82.00 | % | | various |
| Ownership interest | 75.00 | % | | 50.00 | % | | 42.59 | % | | 82.00 | % | | various | Exelon’s share at December 31, 2019: | | | | | | | | | | | Exelon’s share as of December 31, 2021: | | Exelon’s share as of December 31, 2021: | | Plant in service | $ | 1,161 |
| | $ | 1,466 |
| | $ | 663 |
| | $ | 951 |
| | $ | 102 |
| Plant in service | $ | 1,211 | | | $ | 1,515 | | | $ | 756 | | | $ | 1,002 | | | $ | 103 | | Accumulated depreciation | 627 |
| | 571 |
| | 249 |
| | 156 |
| | 53 |
| Accumulated depreciation | 715 | | | 628 | | | 299 | | | 222 | | | 55 | | Construction work in progress | 13 |
| | 21 |
| | 53 |
| | 27 |
| | — |
| Construction work in progress | 11 | | | 12 | | | 20 | | | 41 | | | — | | Exelon’s share at December 31, 2018: | | | | | | | | | | | Exelon’s share as of December 31, 2020: | | Exelon’s share as of December 31, 2020: | | Plant in service | $ | 1,131 |
| | $ | 1,451 |
| | $ | 648 |
| | $ | 910 |
| | $ | 103 |
| Plant in service | $ | 1,188 | | | $ | 1,506 | | | $ | 717 | | | $ | 990 | | | $ | 103 | | Accumulated depreciation | 587 |
| | 523 |
| | 227 |
| | 126 |
| | 53 |
| Accumulated depreciation | 670 | | | 601 | | | 265 | | | 187 | | | 54 | | Construction work in progress | 13 |
| | 15 |
| | 44 |
| | 56 |
| | — |
| Construction work in progress | 13 | | | 13 | | | 39 | | | 25 | | | — | |
__________ | | (a) | PECO, DPL and ACE own a 42.55%, 1% and 13.9% share, respectively in 151.3 miles of 500kV lines located in New Jersey and of the Salem generating plant substation. PECO, DPL and ACE also own a 42.55%, 7.45% and 7.45% share, respectively, in 2.5 miles of 500kV line located over the Delaware River. ACE also has a 21.78% share in a 500kV New Freedom Switching substation. |
(a)PECO, DPL, and ACE own a 42.55%, 1%, and 13.9% share, respectively in 151.3 miles of 500kV lines located in New Jersey and of the Salem generating plant substation. PECO, DPL, and ACE also own a 42.55%, 7.45%, and 7.45% share, respectively, in 2.5 miles of 500kV line located over the Delaware River. ACE also has a 21.78% share in a 500kV New Freedom Switching substation. Exelon’s, Generation’s, PECO's, DPL's, and ACE's undivided ownership interests are financed with their funds and all operations are accounted for as if such participating interests were wholly owned facilities. Exelon’s, Generation’s, PECO's, DPL's, and ACE's share of direct expenses of the jointly owned plants are included in Purchased power and fuel and Operating and maintenance expenses in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income and in Operating and maintenance expenses in PECO's, PHI's, DPL's, and ACE'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 910 — Asset Retirement Obligations
9.10. Asset Retirement Obligations (All Registrants)
Nuclear Decommissioning Asset Retirement Obligations (Exelon and Generation)(Exelon) Generation has a legal obligation to decommission its nuclear power plants following the expirationpermanent cessation of their operating licenses.operations. To estimate its decommissioning obligationobligations 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 AROAROs annually, unless circumstances warrant more frequent updates, based on its review of updated cost studies and its annual evaluation of cost escalation factors and probabilities assigned to various scenarios. Generation began decommissioning the TMI nuclear plant upon permanently ceasing operations in 2019. See below section for decommissioning of Zion Station. 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 withinin Property, plant, and equipment onin 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 a decrease in Operating and maintenance expense withinin Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. The following table provides a rollforward of the nuclear decommissioning AROAROs reflected in Exelon’s and Generation’s Consolidated Balance Sheets from January 1, 2018December 31, 2019 to December 31, 2019:2021: | | | | | Nuclear decommissioning ARO at January 1, 2018 | $ | 9,662 |
| Accretion expense | 478 |
| Net decrease due to changes in, and timing of, estimated future cash flows | (77 | ) | Costs incurred related to decommissioning plants | (58 | ) | Nuclear decommissioning ARO at December 31, 2018 (a) (b) | 10,005 |
| Net increase due to changes in, and timing of, estimated future cash flows
| 864 |
| Sale of Oyster Creek | (755 | ) | Accretion Expense | 479 |
| Costs incurred related to decommissioning plants | (89 | ) | Nuclear decommissioning ARO at December 31, 2019 (a) | $ | 10,504 |
|
__________
| | | | | | (a) | Includes $112 million and $22 millionNuclear decommissioning AROs as the current portion of the ARO at December 31, 2019 | $ | 10,504 | | Net increase due to changes in, and 2018, respectively, which is includedtiming of, estimated future cash flows | 1,022 | | Accretion expense | 489 | | Costs incurred related to decommissioning plants | (93) | | Nuclear decommissioning AROs as of December 31, 2020(a) | 11,922 | | Net increase due to changes in, Other current liabilities in Exelon’s and Generation’s Consolidated Balance Sheets.timing of, estimated future cash flows | 324 | |
Accretion expense | 503 | | Costs incurred related to decommissioning plants | (73) | | Nuclear decommissioning AROs as of December 31, 2021(a) | $ | 12,676 | | | | (b) | Includes $772 million of ARO related to Oyster Creek which is classified as Liabilities held for sale in Exelon's and Generation's Consolidated Balance Sheets at December 31, 2018. See Note 2 — Mergers, Acquisitions and Dispositions for additional information. |
__________ (a)Includes $72 million and $80 million as the current portion of the ARO as of December 31, 2021 and 2020, respectively, which is included in Other current liabilities in Exelon’s Consolidated Balance Sheets. The net $864$324 million increase in the ARO during 20192021 for changes in the amounts and timing of estimated decommissioning cash flows was driven by multiple adjustments throughout the year, some with offsetting impacts.year. These adjustments primarily include: •An increase of approximately $780$550 million for changes in the assumed retirement timing probabilities for sites including certain economically challenged nuclear plants and the extension of Peach Bottom’s operating life; and An increase of approximately $490 million for other impacts that included updated cost escalation rates, primarily for labor equipment and materials,energy, and currenta decrease in discount rates; partially offsetrates.
•An increase of approximately $90 million due to revisions to assumed retirement dates for several nuclear plants. •A net decrease of approximately $170 million was driven by Lower estimated costs updates to decommission TMI, Nine Mile Point, Ginna, Braidwood, Byron and LaSalle nuclear unitsDresden 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 $410$150 million due to lower estimated decommissioning costs resulting from the completion of updated cost studies.studies for seven nuclear plants.
The 2021 ARO updates resulted in a decrease of $51 million in Operating and maintenance expense for the year ended December 31, 2021 in Exelon's Consolidated Statement of Operations and Comprehensive Income.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 910 — Asset Retirement Obligations
The 2019 ARO updates resulted in a decrease of $150 million in Operating and maintenance expense for the year ended December 31, 2019 within Exelon and Generation's Consolidated Statements of Operations and Comprehensive Income. See Note 6—Early Plant Retirements for additional information regarding TMI and economically challenged nuclear plants and Note 3 - Regulatory Matters regarding the Peach Bottom second license renewal.
The net $77$1,022 million decreaseincrease in the ARO during 20182020 for changes in the amounts and timing of estimated decommissioning cash flows was driven by multiple adjustments throughout the year, some with offsetting impacts.year. These adjustments primarily include: •A net increase of approximately $800 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 announcement to early retire these plants in 2021. Refer to Note 7 — Early Plant Retirements for additional information. •An increase of approximately $360 million resulting from the change in the assumed DOE spent fuel acceptance date for disposal from 2030 to 2035. •A decrease of approximately $205$220 million primarily due to lower estimated decommissioning costs for the construction of interim spent fuel storage at TMI and a net decrease in estimated costs to decommission Calvert Cliffs, FitzPatrick, Limerick, and Salem nuclear units resulting from the completion of updated cost studies. There was also a decrease due to changesstudies primarily for two nuclear plants. The 2020 ARO updates resulted in decommissioning scenarios and their probabilities. These decreases were partially offset by Anan increase of approximately $115$60 million in Operating and maintenance expense for the impactyear ended December 31, 2020 in Exelon's Consolidated Statement of the early retirementOperations and the announced pending sale of Oyster Creek which closed on July 1, 2019; andComprehensive Income.
An increase of approximately $120 million for estimated cost escalation rates, primarily for labor, energy and waste burial costs.
See Note 2 — Mergers, Acquisitions and Dispositions and Note 6—Early Plant Retirements for additional information regarding Oyster Creek.
NDT Funds NDT funds have been established for each generation station nuclear unit to satisfy Generation’s nuclear decommissioning obligations.obligations, as required by the NRC, and withdrawals from these funds for reasons other than to pay for decommissioning are restricted pursuant to NRC requirements until all decommissioning activities have been completed. Generally, NDT funds established for a particular unit may not be used to fund the decommissioning obligations of any other unit. The NDT funds associated with Generation's nuclear units have been funded with amounts collected from the previous owners and their respective utility customers. PECO is authorized to collect funds, in revenues, through regulated rates for decommissioning the former PECO nuclear plants, through regulated rates, and these collections are scheduled through the operating lives of thethese former PECO plants. The amounts collected from PECO customers are remitted to Generation and deposited into the NDT funds for the unit for which funds are collected.collected. Every five years, PECO files a rate adjustment with the PAPUC that reflects PECO’s calculations of the estimated amount needed to decommission each of the former PECO units based on updated fund balances and estimated decommissioning costs. The rate adjustment is used to determine the amount collectible from PECO customers. On March 31, 2017, PECO filed its Nuclear Decommissioning Cost Adjustment with the PAPUC proposing an annual recovery from customers of approximately $4 million. This amount reflects a decrease from the previously approved annual collection of approximately $24 million primarily due to the removal of the collections for Limerick Units 1 and 2 as a result of the NRC approving the extension of the operating licenses for an additional 20 years. On August 8, 2017, the PAPUC approved the filing and the new rates became effective January 1, 2018. Any shortfall of funds necessary for decommissioning, determined for each generating station unit, is ultimatelyare generally required to be funded by Generation, with the exception of a shortfall for the current decommissioning activities at Zion Station, where certain decommissioning activities have been transferred to a third-party (see Zion Station Decommissioning below) and the CENG units,former PECO nuclear plants where, any shortfall is required to be funded by both Generation and EDF. Generation, through PECO, Generation has recourse to collect additional amounts from PECO customers related to a shortfall of NDT funds for the former PECOthose units, subject to certain limitations and thresholds, as prescribed by an order from the PAPUC. Generally, PECO, and likewise Generation will not be allowed to collectPAPUC that limits collection of amounts associated with the first $50 million of any shortfall of trust funds compared to decommissioning costs, as well as 5% of any additional shortfalls, on an aggregate basis for all former PECO units. The initial $50 million and up to 5% of any additional shortfalls would be borne by Generation. No recourse exists to collect additional amounts from utility customers for any of Generation's other nuclear units. With respect to the former ComEd and former PECO units, any funds remaining in the NDTs after all decommissioning has been completed are required to be refunded to ComEd’s or PECO’s customers, subject to certain limitations that allow sharing of excess funds with Generation related to the former PECO units. With respect to Generation's other nuclear units, Generation retains any funds remaining after decommissioning. However, in connection with CENG's acquisition of the Nine Mile Point and Ginna plants
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 9 — Asset Retirement Obligations
and settlements with certain regulatory agencies, CENG is subject to certain conditions pertaining to NDT funds apply that, if met, could possibly result in obligations to make payments to certain third parties (clawbacks). For Nine Mile Point and Ginna, the clawback provisions are triggered only in the event that the required decommissioning activities are discontinued or not started or completed in a timely manner. In the event that the clawback provisions are triggered for Nine Mile Point, then, depending upon the triggering event, an amount equal to 50% of the total amount withdrawn from the funds for non-decommissioning activities as defined in the agreementor 50% of any excess funds in the trust
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 10 — Asset Retirement Obligations funds above the amounts required for decommissioning (including spent fuelSNF management and decommissioning)site restoration) is to be paid to the Nine Mile Point sellers. In the event that the clawback provisions are triggered for Ginna, then an amount equal to any estimated cost savings realized by not completing any of the required decommissioning activities is to be paid to the Ginna sellers. The key criteria and assumptions used by Generation expects to comply with applicable regulationsdetermine the ARO and timely commence and complete all required decommissioning activities. Atto forecast the target growth in the NDT funds as of December 31, 20192021 include: (1) the use of site specific cost estimates that are updated at least once every five years; (2) the inclusion in the ARO estimate of all legally unavoidable costs required to decommission the unit (e.g., radiological decommissioning and 2018,full site restoration for certain units, on-site SNF maintenance and storage subsequent to ceasing operations and until DOE acceptance, and disposal of certain LLRW); (3) as applicable, the consideration of multiple scenarios where decommissioning and site restoration activities are completed under possible scenarios ranging from 10 to 70 years after the cessation of plant operations or the end of the current licensed operating life; (4) the consideration of multiple end of life scenarios; (5) the measurement of the obligation at the present value of the future estimated costs and an annual average accretion of the ARO of approximately 4% through a period of approximately 30 years after the end of the extended lives of the units; and (6) an estimated targeted annual pre-tax return on the NDT funds of 5.5% to 6.3% (as compared to a historical 5-year annual average pre-tax return of approximately 10.2%).
As of December 31, 2021 and 2020, Exelon and Generation had NDT funds totaling $13,353$16,064 million and $12,695$14,599 million, respectively. The NDT funds included $890 million at December 31, 2018, related to Oyster Creek NDT funds which were classified as Assets held for sale in Exelon's and Generation's Consolidated Balance Sheets. See Note 2 — Mergers, Acquisitions and Dispositions for additional information. The NDT fundsalso include $163$126 million and $144$134 million for the current portion of the NDT atfunds as of December 31, 20192021 and 2018,2020, respectively, which are included in Other current assets in Exelon's and Generation's Consolidated Balance Sheets. See Note 2324 — 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 withinin Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. For the former ComEd units, decommissioning-related activities are generally offset within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income and are recorded by the corresponding regulated utility as long asa component of the NDT funds are expected to exceedintercompany and regulatory balances in the total estimated decommissioning obligation. balance sheet. For the former PECO units, given the symmetric settlement provisions that allow for continued recovery of decommissioning costs from PECO customers in the event of a shortfall and the obligation for Generation to ultimately return excess funds to PECO customers (on an aggregate basis for all seven units), decommissioning-related activities are generally offset withinin Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income regardless of whether the NDT funds are expected to exceed or fall short of the total estimated decommissioning obligation. The offset of decommissioning-related activities withinin the Consolidated Statement of Operations and Comprehensive Income results in an equal adjustment to the noncurrent payables to affiliates at Generation. ComEdregulatory liabilities or regulatory assets and PECO have recorded an equal noncurrent affiliate receivable from or payable to Generation and corresponding regulatory liability.at PECO. ShouldFor the expected value of the NDT fund for any former ComEd unit fall belowunits, 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 amount ofextent the related NDT investment balances are expected to exceed the total estimated decommissioning obligation for thateach unit, the accounting to offset decommissioning-related activities in the Consolidated Statement of Operations and Comprehensive Income for that unit would be discontinued, the decommissioning-related activities would be recognizedare offset in the Consolidated Statements of Operations and Comprehensive Income which results in an adjustment to the regulatory liabilities and noncurrent receivables from Generation at ComEd. However, given the adverse impact to Exelon’s and Generation’s financial statements could be material. As of December 31, 2019, the NDT funds of each of the formerasymmetric settlement provision that does not allow for continued recovery from ComEd units, except for Zion (see Zion Station Decommissioning below), are expected to exceed the related decommissioning obligation for each of the units. For the purposes of making this determination, the decommissioning obligation referred to is different, as described below, from the calculation usedcustomers in the NRC minimum funding obligation filings based on NRC guidelines.
Any changes to the PECOevent of a shortfall, recognition of a regulatory agreements could impact Exelon’sasset at ComEd is not permissible and Generation’s ability to offsetaccounting for decommissioning-related activities withinfor that unit would not be offset. During the second and third quarter of 2021, a pre-tax charge of $53 million and $140 million, respectively, was recorded in Exelon’s Consolidated Statement 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 impact to Exelon’s and Generation’s financial statements could be material.
The decommissioning-related activities relatedcorresponding adjustment to the Non-Regulatory Agreement Units are reflected in Exelon’s and Generation’s Consolidated StatementsARO for Byron discussed previously, Generation resumed contractual offset for Byron as of Operations and Comprehensive Income.
See Note 3 — Regulatory Matters and Note 24 — Related Party Transactions for additional information regarding regulatory liabilities at ComEd and PECO and intercompany balances between Generation, ComEd and PECO reflecting the obligation to refund to customers any decommissioning-related assets in excess of the related decommissioning obligations.
that date.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 910 — Asset Retirement Obligations
As of December 31, 2021, decommissioning-related activities for all of the former ComEd units, except for Zion (see Zion Station Decommissioning below), are currently offset in Exelon’s Consolidated Statements of Operations and Comprehensive Income.
The decommissioning-related activities related to the Non-Regulatory Agreement Units are reflected in Exelon’s Consolidated Statements of Operations and Comprehensive Income. See Note 3 — Regulatory Matters for additional information regarding regulatory liabilities at ComEd and PECO. Zion Station Decommissioning In 2010, Generation completed an Asset Sale Agreement (ASA)ASA under which ZionSolutions assumed responsibility for decommissioning Zion Station and Generation transferred to ZionSolutions substantially all the Zion Station’s assets, including the related NDT funds. To reduce the risk of default by ZionSolutions, EnergySolutions has provided a $25 million letter of credit to be used to fund decommissioning costs in the event the NDT assets are insufficient. EnergySolutions and its parent company have also provided a performance guarantee. Following ZionSolutions' completion of its contractual obligations and transfer of the NRC license back to Generation, Generation will store the SNF at Zion Station until it is transferred to the DOE for ultimate disposal, and will complete all remaining decommissioning activities associated with the SNF dry storage facility. Generation had retained its obligation for the SNF upon transfer of the NRC license to Generationas well as certain NDT assets to fund its obligation to maintain the SNF at Zion Station until transfer to the DOE and to complete all remaining decommissioning activities for the SNF storage facility. Any shortage of funds necessary to maintain the SNF and decommission the SNF storage facility is ultimately required to be funded by Generation. Any Zion Station NDT funds remaining after the completionAs of all decommissioning activities will be returned to ComEd customers in accordance with the applicable orders. 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. The estimated decommissioning obligations as calculated using the NRC methodology differ fromDecember 31, 2021, the ARO recorded in Generation’sassociated with Zion's SNF storage facility is $140 million and Exelon’s Consolidated Balance Sheets primarily due to differences in the type of costs included in the estimates, the basis for estimating such costs, and assumptions regarding the decommissioning alternatives to be used, potential license renewals, decommissioning cost escalation, and the growth rate in the NDT funds. Under NRC regulations, if the minimum funding requirements calculated under the NRC methodology are less than the future value of the NDT funds also calculated under the NRC methodology, then the NRC requires either further funding or other financial guarantees.
Key assumptions used in the minimum funding calculation using the NRC methodology at December 31, 2019 include: (1) consideration of costs only for the removal of radiological contamination at each unit; (2) the option on a unit-by-unit basisavailable to use generic, non-site specific cost estimates; (3) consideration of only one decommissioning scenario for each unit; (4) the plants cease operation at the end of their current license lives (with no assumed license renewals for those units that have not already received renewals); (5) the assumption of current nominal dollar cost estimates thatfund this obligation are neither escalated through the anticipated period of decommissioning, nor discounted using the CARFR; and (6) assumed annual after-tax returns on the NDT funds of 2% (3% for the former PECO units, as specified by the PAPUC).
In contrast, the key criteria and assumptions used by Generation to determine the ARO and to forecast the target growth in the NDT funds at December 31, 2019 include: (1) the use of site specific cost estimates that are updated at least once every five years; (2) the inclusion in the ARO estimate of all legally unavoidable costs required to decommission the unit (e.g., radiological decommissioning and full site restoration for certain units, on-site spent fuel maintenance and storage subsequent to ceasing operations and until DOE acceptance, and disposal of certain low-level radioactive waste); (3) the consideration of multiple scenarios where decommissioning and site restoration activities, as applicable, are completed under possible scenarios ranging from 10 to 70 years after the cessation of plant operations; (4) the consideration of multiple end of life scenarios; (5) the measurement of the obligation at the present value of the future estimated costs and an annual average accretion of the ARO of approximately 5% through a period of approximately 30 years after the end of the extended lives of the units; and (6) an estimated targeted annual pre-tax return on the NDT funds of 5.4% to 6.5% (as compared to a historical 5-year annual average pre-tax return of approximately 6.7%).
Generation is required to provide to the NRC a biennial report by unit (annually for units that have been retired or are within five years of the current approved license life), based on values as of December 31, addressing Generation’s ability to meet the NRC minimum funding levels. Depending on the value of the trust funds, Generation may be required to take steps, such as providing financial guarantees through letters of credit or parent company guarantees or making additional contributions to the trusts, which could be significant, to ensure that the trusts are adequately funded and that NRC minimum funding requirements are met. As a result, Exelon’s and Generation’s cash flows and financial positions may be significantly adversely affected.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 9 — Asset Retirement Obligations
Generation filed its biennial decommissioning funding status report with the NRC on April 1, 2019 for all 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, 2018 for all units except for Clinton and Peach Bottom Unit 1. As of February 28, 2019, Clinton demonstrated adequate minimum funding assurance due to market recovery and no further action is required. This demonstration was also included in the April 1, 2019 submittal. As a former PECO plant, financial assurance for decommissioning Peach Bottom Unit 1 is provided by the NDT fund, collections from PECO ratepayers and the ability to adjust those collections in accordance with the approved PAPUC tariff. No additional actions are required aside from the PAPUC filing in accordance with the tariff. See NDT Funds section above for additional information.
Generation will file its next annual decommissioning funding status report with the NRC by March 31, 2020 for shutdown reactors, reactors within five years of shutdown except for Zion Station which is included in a separate report to the NRC submitted by EnergySolutions (see Zion Station Decommissioning above). This report will reflect the status of decommissioning funding assurance as of December 31, 2019 and will include an update for the retirement of TMI in 2019. A shortfall at any unit could necessitate that Exelon post a parental guarantee for Generation's share of the funding assurance. However, the amount of any required guarantee will ultimately depend on the decommissioning approach adopted, the associated level of costs, and the decommissioning trust fund investment performance going forward.
As the future values of trust funds change due to market conditions, the NRC minimum funding status of Generation’s units will change. In addition, if changes occur to the regulatory agreement with the PAPUC that currently allows amounts to be collected from PECO customers for decommissioning the former PECO units, the NRC minimum funding status of those plants could change at subsequent NRC filing dates.
Non-Nuclear Asset Retirement Obligations (All Registrants) GenerationThe Utility Registrants have AROs primarily associated with the abatement and disposal of equipment and buildings contaminated with asbestos and PCBs. In addition, Exelon has AROs for Generation's plant closure costs associated with its fossil and renewable generating facilities, including asbestos abatement, removal of certain storage tanks, restoring leased land to the condition it was in prior to construction of renewable generating stations, and other decommissioning-related activities. The Utility Registrants have AROs primarily associated with the abatement and disposal of equipment and buildings contaminated with asbestos and PCBs. See Note 1 — Significant Accounting Policies for additional information on the Registrants’ accounting policy for AROs.
The following table provides a rollforward of the non-nuclear AROs reflected in the Registrants’ Consolidated Balance Sheets from January 1, 2018December 31, 2019 to December 31, 2019:2021: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exelon | | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Non-nuclear AROs as of December 31, 2019 | $ | 460 | | | | | $ | 129 | | | $ | 28 | | | $ | 23 | | | $ | 57 | | | $ | 41 | | | $ | 12 | | | $ | 4 | | Net increase (decrease) due to changes in, and timing of, estimated future cash flows | 7 | | | | | — | | | 2 | | | 1 | | | 1 | | | (3) | | | 2 | | | 2 | | Development projects | 1 | | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Accretion expense(a) | 16 | | | | | 1 | | | 1 | | | 1 | | | 1 | | | 1 | | | — | | | — | | Asset divestitures | (4) | | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Payments | (9) | | | | | (1) | | | (2) | | | (2) | | | — | | | — | | | — | | | — | | AROs reclassified to liabilities held for sale | (10) | | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Non-nuclear AROs as of December 31, 2020 | 461 | | | | | 129 | | | 29 | | | 23 | | | 59 | | | 39 | | | 14 | | | 6 | | Net increase due to changes in, and timing of, estimated future cash flows | 31 | | | | | 15 | | | — | | | 2 | | | 10 | | | 5 | | | 2 | | | 3 | | | | | | | | | | | | | | | | | | | | Accretion expense(a) | 18 | | | | | 4 | | | 1 | | | 1 | | | 1 | | | 1 | | | — | | | — | | Asset divestitures | (19) | | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Payments | (11) | | | | | (2) | | | (1) | | | — | | | — | | | — | | | — | | | — | | AROs previously held for sale | 10 | | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Non-nuclear AROs as of December 31, 2021 | $ | 490 | | | | | $ | 146 | | | $ | 29 | | | $ | 26 | | | $ | 70 | | | $ | 45 | | | $ | 16 | | | $ | 9 | |
249 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Non-nuclear AROs at January 1, 2018 | $ | 384 |
| | $ | 197 |
|
| $ | 113 |
|
| $ | 27 |
|
| $ | 24 |
| | $ | 16 |
| | $ | 3 |
| | $ | 10 |
| | $ | 3 |
| Net increase due to changes in, and timing of, estimated future cash flows(a) | 80 |
| | 35 |
|
| 7 |
|
| — |
|
| 2 |
| | 36 |
| | 34 |
| | 1 |
| | 1 |
| Accretion expense(b) | 16 |
| | 10 |
| | 4 |
| | 1 |
| | 1 |
| | — |
| | — |
| | — |
| | — |
| Asset divestitures | (3 | ) | | (3 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Payments | (6 | ) | | (1 | ) |
| (3 | ) |
| — |
|
| (2 | ) | | — |
| | — |
| | — |
| | — |
| Non-nuclear AROs at December 31, 2018 | 471 |
| | 238 |
|
| 121 |
|
| 28 |
|
| 25 |
| | 52 |
| | 37 |
|
| 11 |
|
| 4 |
| Net (decrease) increase due to changes in, and timing of, estimated future cash flows | 17 |
| | 7 |
|
| 8 |
|
| — |
|
| (2 | ) | | 4 |
| | 3 |
| | 1 |
| | — |
| Development projects | 2 |
| | 2 |
|
| — |
|
| — |
|
| — |
| | — |
| | — |
| | — |
| | — |
| Accretion expense(b) | 16 |
| | 12 |
|
| 1 |
|
| 1 |
|
| 1 |
| | 1 |
| | 1 |
| | — |
| | — |
| Asset divestitures | (42 | ) | | (42 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Payments | (4 | ) | | (1 | ) |
| (1 | ) |
| (1 | ) |
| (1 | ) | | — |
| | — |
| | — |
| | — |
| Non-nuclear AROs at December 31, 2019 | $ | 460 |
| | $ | 216 |
|
| $ | 129 |
|
| $ | 28 |
|
| $ | 23 |
| | $ | 57 |
| | $ | 41 |
|
| $ | 12 |
|
| $ | 4 |
|
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 910 — Asset Retirement Obligations
__________ | | (a) | In 2018, Pepco recorded an increase of $22 million in Operating and maintenance expense primarily related to asbestos identified at its Buzzard Point property as part of an annual ARO study. Buzzard Point is a waterfront property in the District of Columbia occupied by an active substation and former Pepco operated steam plant building, which Pepco retired and closed in 1981. |
| | (b) | For ComEd and PECO, the majority of the accretion is recorded as an increase to a regulatory asset due to the associated regulatory treatment. |
10.(a)For ComEd, PECO, BGE, PHI, and Pepco, the majority of the accretion is recorded as an increase to a regulatory asset due to the associated regulatory treatment.
11. Leases (All Registrants) Lessee The Registrants have operating and finance leases for which they are the lessees. The following tables outline the significant types of operating leaseleases at each registrant and other terms and conditions of the lease agreements. The Registrants doagreements as of December 31, 2021. Exelon, ComEd, PECO, and BGE did not have material finance leases. leases in 2021, 2020, or in 2019. PHI, Pepco, DPL, and ACE also did not have material finance leases in 2019. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Contracted generation | ● | | ● | | | | | | | | | | | | | | | Real estate | ● | | ● | | ● | | ● | | ● | | ● | | ● | | ● | | ● | Vehicles and equipment | ● | | ● | | ● | | ● | | ● | | ● | | ● | | ● | | ● |
| | (in years) | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | (in years) | Exelon | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Remaining lease terms | 1-86 | | 1-36 | | 1-5 | | 1-14 | | 1-86 | | 1-12 | | 1-12 | | 1-12 | | 1-6 | Remaining lease terms | 1-84 | | | 1-3 | | 1-12 | | 1-84 | | 1-10 | | 1-10 | | 1-10 | | 1-7 | Options to extend the term | 3-30 | | 3-30 | | 5 | | N/A | | N/A | | 3-30 | | 5 | | 3-30 | | N/A | Options to extend the term | 1-30 | | | 5 | | N/A | | N/A | | 3-30 | | 5 | | 3-30 | | 5 | Options to terminate within | 1-13 | | 1 | | 3 | | N/A | | 2 | | N/A | | N/A | | N/A | | N/A | Options to terminate within | 1-11 | | | 1 | | N/A | | 1 | | N/A | | N/A | | N/A | | N/A |
The components of operating lease costs were as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exelon | | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | For the year ended December 31, 2021 | | | | | | | | | | | | | | | | | | Operating lease costs | $ | 245 | | | | | $ | 3 | | | $ | — | | | $ | 30 | | | $ | 43 | | | $ | 10 | | | $ | 12 | | | $ | 6 | | Variable lease costs | 175 | | | | | 1 | | | — | | | 1 | | | 1 | | | — | | | — | | | — | | Short-term lease costs | — | | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total lease costs(a) | $ | 420 | | | | | $ | 4 | | | $ | — | | | $ | 31 | | | $ | 44 | | | $ | 10 | | | $ | 12 | | | $ | 6 | | | | | | | | | | | | | | | | | | | | For the year ended December 31, 2020 | | | | | | | | | | | | | | | | | | Operating lease costs | $ | 292 | | | | | $ | 3 | | | $ | 1 | | | $ | 33 | | | $ | 46 | | | $ | 11 | | | $ | 13 | | | $ | 6 | | Variable lease costs | 241 | | | | | 1 | | | — | | | 1 | | | 2 | | | 1 | | | 1 | | | — | | Short-term lease costs | 2 | | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Total lease costs(a) | $ | 535 | | | | | $ | 4 | | | $ | 1 | | | $ | 34 | | | $ | 48 | | | $ | 12 | | | $ | 14 | | | $ | 6 | | | | | | | | | | | | | | | | | | | | For the year ended December 31, 2019 | | | | | | | | | | | | | | | | | | Operating lease costs | $ | 320 | | | | | $ | 3 | | | $ | 1 | | | $ | 33 | | | $ | 48 | | | $ | 12 | | | $ | 14 | | | $ | 7 | | Variable lease costs | 300 | | | | | 2 | | | — | | | 2 | | | 6 | | | 2 | | | 2 | | | 1 | | Short-term lease costs | 19 | | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Total lease costs(a) | $ | 639 | | | | | $ | 5 | | | $ | 1 | | | $ | 35 | | | $ | 54 | | | $ | 14 | | | $ | 16 | | | $ | 8 | |
__________ (a)Excludes sublease income recorded at Exelon, PHI, and DPL of $48 million, $4 million, and $4 million, respectively, for the year ended December 31, 2019 were as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Operating lease costs | $ | 320 |
| | $ | 222 |
| | $ | 3 |
| | $ | 1 |
| | $ | 33 |
| | $ | 48 |
| | $ | 12 |
| | $ | 14 |
| | $ | 7 |
| Variable lease costs | 300 |
| | 282 |
| | 2 |
| | — |
| | 2 |
| | 6 |
| | 2 |
| | 2 |
| | 1 |
| Short-term lease costs | 19 |
| | 19 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Total lease costs (a) | $ | 639 |
| | $ | 523 |
| | $ | 5 |
| | $ | 1 |
| | $ | 35 |
| | $ | 54 |
| | $ | 14 |
| | $ | 16 |
| | $ | 8 |
|
__________
| | (a) | Excludes $51 million, $44 million, $7 million and $7 million of sublease income recorded at Exelon, Generation, PHI and DPL. |
The following table presents the Registrants' rental expense under the prior lease accounting guidance2021, $48 million, $4 million, and $4 million, respectively, for the yearsyear ended December 31, 20182020, and 2017:$51 million, $7 million, and $7 million, respectively, for the year ended December 31, 2019.
PHI, Pepco, DPL, and ACE recorded finance lease costs of $13 million, $5 million, $5 million, and $3 million, respectively, for the year ended December 31, 2021 and $9 million, $3 million, $4 million, and $2 million, respectively, for the year ended December 31, 2020. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exelon | | Generation(a) | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | 2018 | $ | 670 |
| | $ | 558 |
| | $ | 7 |
| | $ | 10 |
| | $ | 35 |
| | $ | 48 |
| | $ | 10 |
| | $ | 13 |
| | $ | 8 |
| 2017 | 709 |
| | 578 |
| | 9 |
| | 9 |
| | 32 |
| | 63 |
| | 11 |
| | 16 |
| | 14 |
|
__________
| | (a) | Includes contingent operating lease payments associated with contracted generation agreements that are not included in the minimum future operating lease payments above. Payments made under Generation's contracted generation lease agreements totaled $493 million and $508 million during 2018 and 2017, respectively. |
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 1011 — Leases
The following table providestables provide additional information regarding the presentation of operating and finance lease ROU assets and lease liabilities within the Registrants’ Consolidated Balance SheetsSheets: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Operating Leases | | Exelon(a) | | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | As of December 31, 2021 | | | | | | | | | | | | | | | | | | Operating lease ROU assets | | | | | | | | | | | | | | | | | | Other deferred debits and other assets | $ | 875 | | | | | $ | 5 | | | $ | 1 | | | $ | 16 | | | $ | 209 | | | $ | 43 | | | $ | 46 | | | $ | 11 | | | | | | | | | | | | | | | | | | | | Operating lease liabilities | | | | | | | | | | | | | | | | | | Other current liabilities | 124 | | | | | 2 | | | — | | | 15 | | | 31 | | | 6 | | | 8 | | | 3 | | Other deferred credits and other liabilities | 968 | | | | | 3 | | | 1 | | | 4 | | | 195 | | | 40 | | | 49 | | | 9 | | Total operating lease liabilities | $ | 1,092 | | | | | $ | 5 | | | $ | 1 | | | $ | 19 | | | $ | 226 | | | $ | 46 | | | $ | 57 | | | $ | 12 | | | | | | | | | | | | | | | | | | | | As of December 31, 2020 | | | | | | | | | | | | | | | | | | Operating lease ROU assets | | | | | | | | | | | | | | | | | | Other deferred debits and other assets | $ | 1,064 | | | | | $ | 7 | | | $ | 1 | | | $ | 46 | | | $ | 241 | | | $ | 49 | | | $ | 54 | | | $ | 15 | | | | | | | | | | | | | | | | | | | | Operating lease liabilities | | | | | | | | | | | | | | | | | | Other current liabilities | 213 | | | | | 3 | | | — | | | 45 | | | 31 | | | 6 | | | 9 | | | 4 | | Other deferred credits and other liabilities | 1,089 | | | | | 5 | | | 1 | | | 19 | | | 224 | | | 46 | | | 56 | | | 11 | | Total operating lease liabilities | $ | 1,302 | | | | | $ | 8 | | | $ | 1 | | | $ | 64 | | | $ | 255 | | | $ | 52 | | | $ | 65 | | | $ | 15 | |
__________ (a)Exelon's operating ROU assets and lease liabilities include $293 million and $429 million, respectively, related to contracted generation as of December 31, 2019: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exelon(a) | | Generation(a) | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Operating lease ROU assets | | | | | | | | | | | | | | | | | | Other deferred debits and other assets | $ | 1,305 |
| | $ | 895 |
| | $ | 9 |
| | $ | 2 |
| | $ | 77 |
| | $ | 273 |
| | $ | 56 |
| | $ | 63 |
| | $ | 18 |
| | | | | | | | | | | | | | | | | | | Operating lease liabilities | | | | | | | | | | | | | | | | | | Other current liabilities | 225 |
| | 157 |
| | 3 |
| | — |
| | 32 |
| | 31 |
| | 6 |
| | 9 |
| | 4 |
| Other deferred credits and other liabilities | 1,307 |
| | 925 |
| | 8 |
| | 1 |
| | 50 |
| | 254 |
| | 51 |
| | 65 |
| | 14 |
| Total operating lease liabilities | $ | 1,532 |
| | $ | 1,082 |
| | $ | 11 |
| | $ | 1 |
| | $ | 82 |
| | $ | 285 |
| | $ | 57 |
| | $ | 74 |
| | $ | 18 |
|
__________ | | (a) | Exelon's and Generation's operating ROU assets and lease liabilities include $515 million and $6642021, and $387 million and $528 million, respectively, related to contracted generation. |
The weighted average remaining lease terms, in years, and discount rates for operating leases as of December 31, 2019 were as follows:2020.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Remaining lease term | 10.1 |
| | 10.6 |
| | 4.6 |
| | 4.4 |
| | 5.4 |
| | 9.0 |
| | 9.8 |
| | 9.7 |
| | 4.7 |
| Discount rate | 4.6 | % | | 4.8 | % | | 3.0 | % | | 3.2 | % | | 3.6 | % | | 4.2 | % | | 4.0 | % | | 4.0 | % | | 3.6 | % |
Future minimum lease payments for operating leases as of December 31, 2019 were as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Finance Leases | | | | | | | | | | | | PHI | | Pepco | | DPL | | ACE | As of December 31, 2021 | | | | | | | | | | | | | | | | | | Finance lease ROU assets | | | | | | | | | | | | | | | | | | Plant, property and equipment, net | | | | | | | | | | | $ | 73 | | | $ | 25 | | | $ | 29 | | | $ | 19 | | | | | | | | | | | | | | | | | | | | Finance lease liabilities | | | | | | | | | | | | | | | | | | Long-term debt due within one year | | | | | | | | | | | 10 | | | 3 | | | 4 | | | 3 | | Long-term debt | | | | | | | | | | | 64 | | | 23 | | | 25 | | | 16 | | Total finance lease liabilities | | | | | | | | | | | $ | 74 | | | $ | 26 | | | $ | 29 | | | $ | 19 | | | | | | | | | | | | | | | | | | | | As of December 31, 2020 | | | | | | | | | | | | | | | | | | Finance lease ROU assets | | | | | | | | | | | | | | | | | | Plant, property and equipment, net | | | | | | | | | | | $ | 50 | | | $ | 17 | | | $ | 20 | | | $ | 13 | | | | | | | | | | | | | | | | | | | | Finance lease liabilities | | | | | | | | | | | | | | | | | | Long-term debt due within one year | | | | | | | | | | | 7 | | | 2 | | | 3 | | | 2 | | Long-term debt | | | | | | | | | | | 43 | | | 15 | | | 17 | | | 11 | | Total finance lease liabilities | | | | | | | | | | | $ | 50 | | | $ | 17 | | | $ | 20 | | | $ | 13 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Year | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | 2020 | $ | 287 |
| | $ | 203 |
| | $ | 3 |
| | $ | — |
| | $ | 34 |
| | $ | 42 |
| | $ | 8 |
| | $ | 11 |
| | $ | 5 |
| 2021 | 243 |
| | 162 |
| | 4 |
| | 1 |
| | 31 |
| | 41 |
| | 8 |
| | 11 |
| | 4 |
| 2022 | 177 |
| | 113 |
| | 2 |
| | — |
| | 16 |
| | 38 |
| | 8 |
| | 10 |
| | 4 |
| 2023 | 145 |
| | 100 |
| | 1 |
| | — |
| | 1 |
| | 37 |
| | 7 |
| | 9 |
| | 3 |
| 2024 | 140 |
| | 97 |
| | 1 |
| | — |
| | — |
| | 35 |
| | 5 |
| | 9 |
| | 2 |
| Remaining years | 976 |
| | 741 |
| | 1 |
| | — |
| | 18 |
| | 153 |
| | 34 |
| | 41 |
| | 2 |
| Total | 1,968 |
| | 1,416 |
| | 12 |
| | 1 |
| | 100 |
| | 346 |
| | 70 |
| | 91 |
| | 20 |
| Interest | 436 |
| | 334 |
| | 1 |
| | — |
| | 18 |
| | 61 |
| | 13 |
| | 17 |
| | 2 |
| Total operating lease liabilities | $ | 1,532 |
| | $ | 1,082 |
| | $ | 11 |
| | $ | 1 |
| | $ | 82 |
| | $ | 285 |
| | $ | 57 |
| | $ | 74 |
| | $ | 18 |
|
251
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 1011 — Leases
The weighted average remaining lease terms, in years, for operating and finance leases were as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Operating Leases | | Exelon | | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | As of December 31, 2021 | 9.8 | | | | 3.3 | | 6.1 | | 13.7 | | 7.5 | | 8.6 | | 8.5 | | 3.5 | As of December 31, 2020 | 10.1 | | | | 3.8 | | 4.2 | | 8.3 | | 8.2 | | 9.1 | | 9.1 | | 4.0 | As of December 31, 2019 | 10.1 | | | | 4.6 | | 4.4 | | 5.4 | | 9.0 | | 9.8 | | 9.7 | | 4.7 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Finance Leases | | | | | | | | | | | | PHI | | Pepco | | DPL | | ACE | As of December 31, 2021 | | | | | | | | | | | 6.1 | | 5.9 | | 6.1 | | 6.3 | As of December 31, 2020 | | | | | | | | | | | 6.5 | | 6.3 | | 6.5 | | 6.5 |
The weighted average discount rates for operating and finance leases were as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Operating Leases | | Exelon | | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | As of December 31, 2021 | 4.7 | % | | | | 2.8 | % | | 2.2 | % | | 4.0 | % | | 4.2 | % | | 4.0 | % | | 4.0 | % | | 3.4 | % | As of December 31, 2020 | 4.7 | % | | | | 3.0 | % | | 2.9 | % | | 3.8 | % | | 4.2 | % | | 4.0 | % | | 4.0 | % | | 3.5 | % | As of December 31, 2019 | 4.6 | % | | | | 3.0 | % | | 3.2 | % | | 3.6 | % | | 4.2 | % | | 4.0 | % | | 4.0 | % | | 3.6 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Finance Leases | | | | | | | | | | | | PHI | | Pepco | | DPL | | ACE | As of December 31, 2021 | | | | | | | | | | | 2.2 | % | | 2.3 | % | | 2.1 | % | | 2.1 | % | As of December 31, 2020 | | | | | | | | | | | 2.5 | % | | 2.6 | % | | 2.4 | % | | 2.4 | % |
Future minimum lease payments for operating and finance leases under the prior lease accounting guidance as of December 31, 20182021 were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Operating Leases | Year | Exelon | | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | 2022 | $ | 156 | | | | | $ | 2 | | | $ | — | | | $ | 16 | | | $ | 38 | | | $ | 8 | | | $ | 10 | | | $ | 4 | | 2023 | 144 | | | | | 1 | | | — | | | 1 | | | 37 | | | 7 | | | 10 | | | 3 | | 2024 | 140 | | | | | 1 | | | — | | | — | | | 36 | | | 7 | | | 8 | | | 3 | | 2025 | 140 | | | | | 1 | | | — | | | — | | | 34 | | | 6 | | | 7 | | | 2 | | 2026 | 135 | | | | | — | | | — | | | — | | | 29 | | | 5 | | | 5 | | | 1 | | Remaining years | 693 | | | | | — | | | 1 | | | 18 | | | 94 | | | 22 | | | 30 | | | — | | Total | 1,408 | | | | | 5 | | | 1 | | | 35 | | | 268 | | | 55 | | | 70 | | | 13 | | Interest | 316 | | | | | — | | | — | | | 16 | | | 42 | | | 9 | | | 13 | | | 1 | | Total operating lease liabilities | $ | 1,092 | | | | | $ | 5 | | | $ | 1 | | | $ | 19 | | | $ | 226 | | | $ | 46 | | | $ | 57 | | | $ | 12 | |
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 11 — Leases | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exelon(a)(b) | | Generation(a)(b) | | ComEd(a)(c) | | PECO(a)(c) | | BGE(a)(c)(d)(e) | | PHI(a) | | Pepco(a) | | DPL(a)(c) | | ACE(a) | 2019 | $ | 140 |
| | $ | 33 |
| | $ | 7 |
| | $ | 5 |
| | $ | 35 |
| | $ | 48 |
| | $ | 11 |
| | $ | 14 |
| | $ | 7 |
| 2020 | 149 |
| | 46 |
| | 5 |
| | 5 |
| | 35 |
| | 46 |
| | 10 |
| | 13 |
| | 6 |
| 2021 | 143 |
| | 46 |
| | 4 |
| | 5 |
| | 33 |
| | 43 |
| | 9 |
| | 12 |
| | 5 |
| 2022 | 126 |
| | 47 |
| | 4 |
| | 5 |
| | 18 |
| | 42 |
| | 8 |
| | 12 |
| | 5 |
| 2023 | 97 |
| | 46 |
| | 3 |
| | 5 |
| | 3 |
| | 39 |
| | 8 |
| | 10 |
| | 4 |
| Remaining years | 723 |
| | 545 |
| | — |
| | — |
| | 19 |
| | 159 |
| | 40 |
| | 35 |
| | 5 |
| Total minimum future lease payments | $ | 1,378 |
| | $ | 763 |
| | $ | 23 |
| | $ | 25 |
| | $ | 143 |
| | $ | 377 |
| | $ | 86 |
| | $ | 96 |
| | $ | 32 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Finance Leases | Year | | | | | | | | | | | PHI | | Pepco | | DPL | | ACE | 2022 | | | | | | | | | | | $ | 12 | | | $ | 4 | | | $ | 5 | | | $ | 3 | | 2023 | | | | | | | | | | | 12 | | | 4 | | | 5 | | | 3 | | 2024 | | | | | | | | | | | 13 | | | 5 | | | 5 | | | 3 | | 2025 | | | | | | | | | | | 12 | | | 4 | | | 5 | | | 3 | | 2026 | | | | | | | | | | | 12 | | | 4 | | | 5 | | | 3 | | Remaining years | | | | | | | | | | | 18 | | | 6 | | | 7 | | | 5 | | Total | | | | | | | | | | | 79 | | | 27 | | | 32 | | | 20 | | Interest | | | | | | | | | | | 5 | | | 1 | | | 3 | | | 1 | | Total finance lease liabilities | | | | | | | | | | | $ | 74 | | | $ | 26 | | | $ | 29 | | | $ | 19 | |
__________
| | (a) | Includes amounts related to shared use land arrangements. |
| | (b) | Excludes Generation’s contingent operating lease payments associated with contracted generation. |
| | (c) | Amounts related to certain real estate leases and railroad licenses effectively have indefinite payment periods. As a result, ComEd, PECO, BGE and DPL have excluded these payments from the remaining years as such amounts would not be meaningful. ComEd's, PECO’s, BGE’s and DPL's average annual obligation for these arrangements, included in each of the years 2019 - 2023, was $3 million, $5 million, $1 million and $1 million respectively. Also includes amounts related to shared use land arrangements. |
| | (d) | Includes all future lease payments on a 99-year real estate lease that expires in 2106. |
| | (e) | The BGE column above includes minimum future lease payments associated with a 6-year lease for the Baltimore City conduit system that became effective during the fourth quarter of 2016. BGE's total commitments under the lease agreement are $26 million, $28 million, $28 million and $14 million related to years 2019 - 2022, respectively. |
Cash paid for amounts included in the measurement of operating and finance lease liabilities for the year ended December 31, 2019 were as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Operating cash flows from operating leases | | Exelon | | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | For the year ended December 31, 2021 | $ | 255 | | | | | $ | 3 | | | $ | — | | | $ | 46 | | | $ | 39 | | | $ | 8 | | | $ | 9 | | | $ | 4 | | For the year ended December 31, 2020 | 271 | | | | | 3 | | | 1 | | | 20 | | | 39 | | | 8 | | | 9 | | | 4 | | For the year ended December 31, 2019 | 287 | | | | | 3 | | | — | | | 33 | | | 37 | | | 9 | | | 6 | | | 5 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Operating cash flows from operating leases | $ | 287 |
| | $ | 206 |
| | $ | 3 |
| | $ | — |
| | $ | 33 |
| | $ | 37 |
| | $ | 9 |
| | $ | 6 |
| | $ | 5 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Financing cash flows from finance leases | | | | | | | | | | | | PHI | | Pepco | | DPL | | ACE | | | | | | | | | | | | | | | | | | | For the year ended December 31, 2021 | | | | | | | | | | | $ | 10 | | | $ | 3 | | | $ | 4 | | | $ | 3 | | | | | | | | | | | | | | | | | | | | For the year ended December 31, 2020 | | | | | | | | | | | 6 | | | 2 | | | 3 | | | 1 | |
ROU assets obtained in exchange for operating and finance lease obligations for the year ended December 31, 2019 were as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Operating Leases | | Exelon | | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | For the year ended December 31, 2021 | $ | (1) | | | | | $ | — | | | $ | — | | | $ | (1) | | | $ | 1 | | | $ | — | | | $ | 1 | | | $ | — | | For the year ended December 31, 2020 | 1 | | | | | — | | | 1 | | | — | | | (1) | | | — | | | (1) | | | — | | For the year ended December 31, 2019 | 52 | | | | | 6 | | | — | | | 2 | | | (3) | | | (1) | | | (2) | | | (1) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Operating leases | $ | 52 |
| | $ | 14 |
| | $ | 6 |
| | $ | — |
| | $ | 2 |
| | $ | (3 | ) | | $ | (1 | ) | | $ | (2 | ) | | $ | (1 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Finance Leases | | | | | | | | | | | | PHI | | Pepco | | DPL | | ACE | For the year ended December 31, 2021 | | | | | | | | | | | $ | 32 | | | $ | 12 | | | $ | 12 | | | $ | 8 | | For the year ended December 31, 2020 | | | | | | | | | | | 29 | | | 8 | | | 14 | | | 7 | |
Lessor The Registrants have operating leases for which they are the lessors. The following tables outline the significant types of leases at each registrant and other terms and conditions of their lease agreements. agreements as of December 31, 2021. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exelon | | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Contracted generation | ● | | | | | | | | | | | | | | | | | Real estate | ● | | | | ● | | ● | | ● | | ● | | ● | | ● | | 0 | | | | | | | | | | | | | | | | | | | | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Contracted generation | ● | | ● | | | | | | | | | | | | | | | Real estate | ● | | ● | | ● | | ● | | ● | | ● | | ● | | ● | | ● |
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 11 — Leases | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (in years) | Exelon | | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Remaining lease terms | 1-81 | | | | 1-15 | | 1-81 | | 21 | | 1-11 | | 1-4 | | 10-11 | | N/A | Options to extend the term | 1-79 | | | | 5-79 | | 5-50 | | N/A | | 5 | | N/A | | N/A | | N/A | | | | | | | | | | | | | | | | | | | (in years) | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Remaining lease terms | 1-83 | | 1-32 | | 1-17 | | 1-83 | | 23 | | 1-13 | | 1-6 | | 12-13 | | 1-2 | Options to extend the term | 1-79 | | 1-5 | | 5-79 | | 5-50 | | N/A | | 5 | | N/A | | N/A | | N/A |
The components of lease income were as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exelon | | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | For the year ended December 31, 2021 | | | | | | | | | | | | | | | | | | Operating lease income | $ | 52 | | | | | $ | — | | | $ | — | | | $ | — | | | $ | 4 | | | $ | — | | | $ | 3 | | | $ | — | | Variable lease income | 262 | | | | | — | | | — | | | — | | | 1 | | | — | | | 1 | | | — | | | | | | | | | | | | | | | | | | | | For the year ended December 31, 2020 | | | | | | | | | | | | | | | | | | Operating lease income | $ | 52 | | | | | $ | — | | | $ | — | | | $ | — | | | $ | 3 | | | $ | — | | | $ | 3 | | | $ | — | | Variable lease income | 283 | | | | | — | | | — | | | — | | | 1 | | | — | | | 1 | | | — | | | | | | | | | | | | | | | | | | | | For the year ended December 31, 2019 | | | | | | | | | | | | | | | | | | Operating lease income | $ | 54 | | | | | $ | — | | | $ | — | | | $ | — | | | $ | 5 | | | $ | — | | | $ | 4 | | | $ | — | | Variable lease income | 261 | | | | | — | | | — | | | — | | | 3 | | | — | | | 3 | | | — | |
Future minimum lease payments to be recovered under operating leases as of December 31, 2021 were as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Year | Exelon | | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | 2022 | $ | 50 | | | | | $ | — | | | $ | — | | | $ | — | | | $ | 4 | | | $ | — | | | $ | 3 | | | $ | — | | 2023 | 49 | | | | | — | | | — | | | — | | | 3 | | | — | | | 3 | | | — | | 2024 | 49 | | | | | — | | | — | | | — | | | 4 | | | — | | | 4 | | | — | | 2025 | 49 | | | | | — | | | — | | | — | | | 4 | | | — | | | 4 | | | — | | 2026 | 49 | | | | | — | | | — | | | — | | | 4 | | | — | | | 4 | | | — | | Remaining years | 169 | | | | | 1 | | | 4 | | | 1 | | | 26 | | | — | | | 26 | | | — | | Total | $ | 415 | | | | | $ | 1 | | | $ | 4 | | | $ | 1 | | | $ | 45 | | | $ | — | | | $ | 44 | | | $ | — | |
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 10 — Leases
The components of lease income for the year ended December 31, 2019 were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Operating lease income | $ | 54 |
| | $ | 47 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 5 |
| | $ | — |
| | $ | 4 |
| | $ | — |
| Variable lease income | $ | 261 |
| | $ | 258 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 3 |
| | $ | — |
| | $ | 3 |
| | $ | — |
|
Future minimum lease payments to be recovered under operating leases as of December 31, 2019 were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Year | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | 2020 | $ | 51 |
| | $ | 46 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 4 |
| | $ | — |
| | $ | 3 |
| | $ | — |
| 2021 | 51 |
| | 45 |
| | — |
| | — |
| | — |
| | 4 |
| | 1 |
| | 3 |
| | — |
| 2022 | 50 |
| | 45 |
| | — |
| | — |
| | — |
| | 4 |
| | — |
| | 3 |
| | — |
| 2023 | 49 |
| | 44 |
| | — |
| | — |
| | — |
| | 5 |
| | — |
| | 4 |
| | — |
| 2024 | 48 |
| | 44 |
| | — |
| | — |
| | — |
| | 4 |
| | — |
| | 4 |
| | — |
| Remaining years | 265 |
| | 226 |
| | 1 |
| | 3 |
| | 1 |
| | 34 |
| | — |
| | 34 |
| | — |
| Total | $ | 514 |
| | $ | 450 |
| | $ | 1 |
| | $ | 3 |
| | $ | 1 |
| | $ | 55 |
| | $ | 1 |
| | $ | 51 |
| | $ | �� |
|
11.Note 12 — Asset Impairments (Exelon, Generation and PHI)
The Registrants evaluate12. Asset Impairments (Exelon)
Exelon evaluates 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 determineExelon determines if long-lived assets or asset groups are potentially impaired by comparing the undiscounted expected future cash flows to the carrying value.value when indicators of impairment exist. When the undiscounted cash flow analysis indicates a long-lived asset or asset group ismay not be 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 regarding the recoverability of an asset or asset group and, thus, could potentially result in material future impairments of the Registrant'sExelon'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 Consolidated Statement 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 Consolidated Statement 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 CRP 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 Consolidated Statement of Operations and Comprehensive Income. Equity Method Investments in Certain Distributed Energy Companies (Exelon and Generation) In the third quarter of 2019, Generation’s equity method investments in certain distributed energy companies were fully impaired due to an other-than-temporary decline in market conditions and underperforming projects. Exelon and Generation recorded a pre-tax impairment charge of $164 million in Equity in losses of unconsolidated affiliates and an offsetting pre-tax $96 million in Net income attributable to noncontrolling interests in theirthe Consolidated StatementsStatement of Operations and Comprehensive Income. As a result, Generation accelerated the amortization of investment tax credits associated with these companies and Exelon and Generation recorded a benefit of $46 million in Income taxes. The impairment charge and the accelerated amortization of investment tax credits resulted in a net $15 million decrease to Exelon’s and Generation’s earnings. See Note 2223 — Variable Interest Entities for additional information. Antelope Valley Solar Facility (Exelon and Generation)
Generation’s Antelope Valley, a 242 MW solar facility in Lancaster, CA, sells all of its output to PG&E through a PPA. As of December 31, 2019, Generation had approximately $725 million of net long-lived assets related to Antelope Valley. As a result of the PG&E bankruptcy filing in the first quarter of 2019, Generation completed a comprehensive review of Antelope Valley's estimated undiscounted future cash flows and no impairment charge was recorded. Significant changes in assumptions such as the likelihood of the PPA being rejected as part of the bankruptcy proceedings could potentially result in future impairments of Antelope Valley’s net long-lived assets, which could be material.
Antelope Valley is a wholly owned indirect subsidiary of EGR IV, which had approximately $1,893 million of additional net long-lived assets as of December 31, 2019. EGR IV is a wholly owned indirect subsidiary of Exelon and Generation and includes Generation's interest in EGRP and other projects with non-controlling interests. To date, there have been no indicators to suggest that the carrying amount of other net long-lived assets of EGR IV may not be recoverable.
Generation will continue to monitor the bankruptcy proceedings for any changes in circumstances that may indicate the carrying amount of the net long-lived assets of Antelope Valley or other long-lived assets of EGR IV may not be recoverable.
See Note 16 — Debt and Credit Agreements for additional information on the PG&E bankruptcy.
New England Asset Group (Exelon and Generation)
During the first quarter of 2018, Mystic Unit 9 did not clear in the ISO-NE capacity auction for the 2021 - 2022 planning year. On March 29, 2018, Generation notified ISO-NE of the early retirement of its Mystic Generating Station's Units 7, 8, 9 and the Mystic Jet Unit (Mystic Generating Station assets) absent regulatory reforms. These events suggested that the carrying value of its 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 no impairment charge was required. Further developments such as the failure of ISO-NE to adopt long-term solutions for reliability and fuel security could potentially result in material future impairments of the New England asset group. See Note 6 — Early Plant Retirements for additional information.
District of Columbia Sponsorship (Exelon and PHI)
In the third quarter of 2015, PHI entered into a sponsorship agreement with the District of Columbia for future sponsorship rights associated with public property within the District of Columbia, which Exelon and PHI had recorded as a finite-lived intangible asset as of December 31, 2016. The specific sponsorship rights were to be determined through future negotiations. In the fourth quarter of 2017, based upon the lack of available sponsorship opportunities at that time, the asset was written off and a pre-tax impairment charge of $25 million was recorded within Operating and maintenance expense in Exelon’s and PHI's Consolidated Statements of Operations and Comprehensive Income.
ExGen Texas Power (Exelon and Generation)
On May 2, 2017, EGTP entered into a consent agreement with its lenders to initiate the sale of the assets of its wholly owned subsidiaries. As a result, Exelon and Generation classified certain of EGTP's assets and liabilities as held for sale at their respective fair values less costs to sell and recorded a pre-tax impairment charge in 2017 of $460 million within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income. On November 7, 2017, EGTP and its wholly owned subsidiaries filed voluntary petitions for relief under Chapter 11 of Title 11 of the United States Code in the United States Bankruptcy Court for the District of Delaware and, as a result, Exelon and Generation deconsolidated EGTP's assets and liabilities from their consolidated financial statements. See Note 2 — Mergers, Acquisitions and Dispositions for additional information.
12.13. Intangible Assets
Goodwill (Exelon, Generation, ComEd, PHI, Pepco, DPL, and ACE)
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 13 — Intangible Assets The following table presents the gross amount, of goodwill, accumulated impairment loss, and carrying amount of goodwill ofat Exelon, ComEd, and PHI as of December 31, 20192021 and 2018.2020. There were no additions impairments or measurement period adjustmentsimpairments during the years ended December 31, 20192021 and 2018.2020. | | | | | | | | | | | | | | Gross amount | | Accumulated impairment loss | | Carrying amount | Exelon | $ | 8,660 |
| | $ | 1,983 |
| | $ | 6,677 |
| ComEd(a) | 4,608 |
| | 1,983 |
| | 2,625 |
| PHI(b) | 4,005 |
| | — |
| | 4,005 |
|
| | | | | | | | | | | | | | | | | | | Gross Amount | | Accumulated Impairment Loss | | Carrying Amount | Exelon | $ | 8,660 | | | $ | 1,983 | | | $ | 6,677 | | ComEd(a) | 4,608 | | | 1,983 | | | 2,625 | | PHI(b) | 4,005 | | | — | | | 4,005 | |
__________ | | (a) | Reflects goodwill recorded in 2000 from the PECO/Unicom merger (predecessor parent company of ComEd). |
| | (b) | Reflects goodwill recorded in 2016 from the PHI merger. |
(a)Reflects goodwill recorded in 2000 from the PECO/Unicom merger (predecessor parent company of ComEd). (b)Reflects goodwill recorded in 2016 from the PHI merger. Goodwill is not amortized, but is subject to an assessment for impairment at least annually, or more frequently if events occur or circumstances change that would more likely than not reduce the fair value of ComEd's and PHI's reporting units below their carrying amounts. A reporting unit is an operating segment or one level below an operating segment (known as a component) and is the level at which goodwill is testedassessed for impairment. A component of an operating segment is a reporting unit if the component constitutes a business for which discrete financial information is available and its operating results are regularly reviewed by segment management. ComEd has a single operating segment. PHI's operating segments are Pepco, DPL, and ACE. See Note 5 — Segment Information for additional information. There is no level below these operating segments for which operating results are regularly reviewed by segment management. Therefore, the ComEd, Pepco, DPL, and ACE operating segments are also considered reporting units for goodwill impairment testingassessment purposes. Exelon's and ComEd's $2.6 billion of goodwill has been assigned entirely to the ComEd reporting unit, while Exelon's and PHI's $4.0 billion of goodwill has been assigned to the Pepco, DPL, and ACE reporting units in the amounts of $2.1 billion, $1.4 billion, and $0.5 billion, respectively. Entities assessing goodwill for impairment have the option of first performing a qualitative assessment to determine whether a quantitative assessment is necessary. As part of the qualitative assessments, Exelon, ComEd, and PHI evaluate, among other things, management's best estimate of projected operating and capital cash flows for their businesses, outcomes of recent regulatory proceedings, changes in certain market conditions, including the discount rate and regulated utility peer EBITDA multiples, and the passing margin from their last quantitative assessments
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 12 — Intangible Assets
performed. If an entity bypasses the qualitative assessment, a quantitative, two-step, fair value-based testassessment is performed. The first stepperformed, which compares the fair value of the reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, the second stepentity recognizes an impairment charge, which is performed. The second step requires an allocation of fair valuelimited to the individual assets and liabilities using purchase price allocation authoritative guidance in orderamount of goodwill allocated to determine the implied fair value of goodwill.reporting unit. Application of the goodwill impairment testassessment requires management judgment, including the identification of reporting units and determining the fair value of the reporting unit, which management estimates using a weighted combination of a discounted cash flow analysis and a market multiples analysis. Significant assumptions used in these fair value analyses include discount and growth rates, utility sector market performance and transactions, projected operating and capital cash flows for ComEd's, Pepco's, DPL's, and ACE's businesses, and the fair value of debt. In applying the second step, if needed, management must estimate the fair value of specific assets 2021 and liabilities of the reporting unit. 2019 and 20182020 Goodwill Impairment Assessment. ComEd and PHI qualitatively determined that it was more likely than not that the fair values of their reporting units exceeded their carrying values and, therefore, did not perform quantitative assessments as of November 1, 20192021 and 2018 for ComEd and as of November 1, 2019 for PHI.2020. The last quantitative assessments performed were as of November 1, 2016 for ComEd and November 1, 2018 for PHI.
PHI performed a quantitative test for its 2018 annual goodwill impairment assessment as of November 1, 2018. The first step of the test comparing the estimated fair values of the Pepco, DPL and ACE reporting units to their carrying values, including goodwill, indicated no impairments of goodwill; therefore, no second step was required.
While the annual assessments indicated no impairments, certain assumptions used to estimate reporting unit fair values are highly sensitive to changes. Adverse regulatory actions or changes in significant assumptions could potentially result in future impairments of Exelon's, ComEd's, and PHI’s goodwill, which could be material. Based on the results of the last quantitative goodwill test performed, the estimated fair values of the ComEd, Pepco, DPL and ACE reporting units would have needed to decrease by more than 30%, 30%, 20% and 30%, respectively, for ComEd and PHI to fail the first step of their respective impairment tests. Other Intangible Assets and Liabilities (Exelon and PHI) Exelon’s Generation’s, ComEd’s and PHI's other intangible assets, and liabilities, included in Unamortized energy contractOther current assets and liabilities and Other deferred debits and other assets in the Consolidated Balance Sheets, consisted of the following as of December 31, 2021 and 2020. Exelon's and PHI's other intangible liabilities, included in current and noncurrent Unamortized energy contract liabilities in their Consolidated Balance Sheets, consisted of the following as of December 31, 20192021 and 2018.2020. The intangible
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 13 — Intangible Assets assets and liabilities shown below are amortized on a straight linestraight-line basis, except for unamortized energy contracts which are amortized in relation to the expected realization of the underlying cash flows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2019 | | December 31, 2018 | | | Gross | | Accumulated Amortization | | Net | | Gross | | Accumulated Amortization | | Net | Generation | | | | | |
| | | | | |
| Unamortized Energy Contracts | | 1,967 |
| | (1,612 | ) | | 355 |
| | 1,957 |
| | (1,588 | ) | | 369 |
| Customer Relationships | | 343 |
| | (190 | ) | | 153 |
| | 325 |
| | (162 | ) | | 163 |
| Trade Name | | 243 |
| | (193 | ) | | 50 |
| | 243 |
| | (171 | ) | | 72 |
| ComEd | | | | | |
| | | | | |
| Chicago Settlement Agreements | | 162 |
| | (155 | ) | | 7 |
| | 162 |
| | (148 | ) | | 14 |
| PHI | | | | | |
| | | | | |
| Unamortized Energy Contracts | | (1,515 | ) | | 1,073 |
| | (442 | ) | | (1,515 | ) | | 954 |
| | (561 | ) | Exelon Corporate | | | | | | | | | | | | | Software License | | 95 |
| | (44 | ) | | 51 |
| | 95 |
| | (34 | ) | | 61 |
| Exelon | | $ | 1,295 |
| | $ | (1,121 | ) | | $ | 174 |
| | $ | 1,267 |
| | $ | (1,149 | ) | | $ | 118 |
|
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 12 — Intangible Assets
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2021 | | December 31, 2020 | | | Gross | | Accumulated Amortization | | Net | | Gross | | Accumulated Amortization | | Net | Exelon | | | | | | | | | | | | | Unamortized Energy Contracts | | $ | 448 | | | $ | (393) | | | $ | 55 | | | $ | 448 | | | $ | (454) | | | $ | (6) | | Customer Relationships | | 330 | | | (243) | | | 87 | | | 326 | | | (215) | | | 111 | | Trade Name | | 222 | | | (218) | | | 4 | | | 222 | | | (197) | | | 25 | | Software License | | 95 | | | (62) | | | 33 | | | 95 | | | (53) | | | 42 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exelon Total | | $ | 1,095 | | | $ | (916) | | | $ | 179 | | | $ | 1,091 | | | $ | (919) | | | $ | 172 | | PHI | | | | | | | | | | | | | Unamortized Energy Contracts | | $ | (1,515) | | | $ | 1,280 | | | $ | (235) | | | $ | (1,515) | | | $ | 1,188 | | | $ | (327) | | | | | | | | | | | | | | | | | | | | | | | | | | | |
The following table summarizes the amortization expense related to intangible assets and liabilities for each of the years ended December 31, 2019, 20182021, 2020, and 2017:2019: | | For the Years Ended December 31, | | Exelon (a)(b) | | Generation (a) | | ComEd | | PHI(b) | For the Years Ended December 31, | | Exelon(a)(b) | | | PHI(b) | 2021 | | 2021 | | $ | (3) | | | | $ | (92) | | 2020 | | 2020 | | (17) | | | | (115) | | 2019 | | $ | (28 | ) | | $ | 74 |
| | $ | 7 |
| | $ | (119 | ) | 2019 | | (28) | | | | (119) | | 2018 | | (109 | ) | | 63 |
| | 7 |
| | (188 | ) | | 2017 | | (237 | ) | | 83 |
| | 7 |
| | (336 | ) | |
__________ | | (a) | At Exelon and Generation, amortization of unamortized energy contracts totaling $21 million, $14 million and $35 million for the years ended December 31, 2019, 2018 and 2017, respectively, was recorded in Operating revenues or Purchased power and fuel expense in their Consolidated Statements of Operations and Comprehensive Income. |
| | (b) | At Exelon and PHI, amortization of the unamortized energy contract fair value adjustment amounts and the corresponding offsetting regulatory asset and liability amounts are amortized through Purchased power and fuel expense in their Consolidated Statements of Operations and Comprehensive Income. |
(a)See Note 24 - Supplemental Financial Information for additional information related to the amortization of unamortized energy contracts.
(b)For PHI unamortized energy contracts, the amortization of the fair value adjustment amounts and the corresponding offsetting regulatory asset amounts are amortized through Purchased power and fuel expense in their Consolidated Statements of Operations and Comprehensive Income resulting in no effect to net income. The following table summarizes the estimated future amortization expense related to intangible assets and liabilities as of December 31, 2019:2021: | | For the Years Ending December 31, | | Exelon | | Generation | | ComEd | | PHI | For the Years Ending December 31, | | Exelon | | | PHI | 2020 | | $ | (13 | ) | | $ | 85 |
| | $ | 7 |
| | $ | (115 | ) | | 2021 | | 2 |
| | 84 |
| | — |
| | (92 | ) | | 2022 | | (21 | ) | | 58 |
| | — |
| | (89 | ) | 2022 | | $ | (19) | | | | $ | (89) | | 2023 | | (18 | ) | | 53 |
| | — |
| | (81 | ) | 2023 | | (18) | | | | (81) | | 2024 | | 22 |
| | 50 |
| | — |
| | (38 | ) | 2024 | | 22 | | | | (38) | | 2025 | | 2025 | | 43 | | | | (5) | | 2026 | | 2026 | | 32 | | | | (5) | |
Renewable Energy Credits (Exelon and Generation)(Exelon) Exelon’s and Generation’s RECs are included in Other current assets and Other deferred debits and other assetsRenewable energy credits in theExelon's Consolidated Balance Sheets. Purchased RECs are recorded at cost on the date they are purchased. The cost of RECs purchased on a stand-alone basis is based on the transaction price, while the cost of RECs acquired through PPAs represents the difference between the total contract price and the market price of energy at contract inception. Generally, revenue for RECs that are sold to a counterparty under a contract that specifically identifies a power plant is recognized at a point in time when the power is produced. This includes both bundled and unbundled REC sales. Otherwise, the revenue is recognized upon physical transfer of the REC to the customer.
The following table presents the current and noncurrent Renewable Energy CreditsRECs as of December 31, 20192021 and 2018:2020: | | | | | | | | | | | | | | | | | | | As of December 31, 2021 | | As of December 31, 2020 | | | | | | | | | Current REC's | $ | 529 | | | | | $ | 632 | | | | | | | | | | | |
| | | | | | | | | | | | | | As of December 31, 2019 | | As of December 31, 2018 | | Exelon | | Generation | | Exelon | | Generation | Current REC's | 345 |
| | 336 |
| | 279 |
| | 270 |
| Noncurrent REC's | 86 |
| | 86 |
| | 52 |
| | 52 |
|
257
282
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 1314 — Income Taxes
13.14. Income Taxes (All Registrants)
Components of Income Tax Expense or Benefit Income tax expense (benefit) from continuing operations is comprised of the following components: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | For the Year Ended December 31, 2021 | | Exelon | | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Included in operations: | | | | | | | | | | | | | | | | | | Federal | | | | | | | | | | | | | | | | | | Current | $ | 322 | | | | | $ | (30) | | | $ | 1 | | | $ | (18) | | | $ | 18 | | | $ | 22 | | | $ | 2 | | | $ | 1 | | Deferred | (66) | | | | | 113 | | | 20 | | | 34 | | | (52) | | | (17) | | | (14) | | | (26) | | Investment tax credit amortization | (18) | | | | | (1) | | | — | | | — | | | (1) | | | — | | | — | | | — | | State | | | | | | | | | | | | | | | | | | Current | 32 | | | | | (41) | | | — | | | — | | | — | | | 1 | | | 1 | | | — | | Deferred | 100 | | | | | 131 | | | (9) | | | (51) | | | 77 | | | 9 | | | 53 | | | 12 | | Total | $ | 370 | | | | | $ | 172 | | | $ | 12 | | | $ | (35) | | | $ | 42 | | | $ | 15 | | | $ | 42 | | | $ | (13) | |
| | | For the Year Ended December 31, 2019 | | For the Year Ended December 31, 2020 | | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | | Exelon | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Included in operations: | | | | | | | | | | | | | | | | | | Included in operations: | | | | | | | | | | | | | | | | | Federal | | | | | | | | | | | | | | | | | | Federal | | | | Current | $ | 85 |
| | $ | 147 |
| | $ | 59 |
| | $ | 45 |
| | $ | (51 | ) | | $ | 43 |
| | $ | 16 |
| | $ | 29 |
| | $ | (3 | ) | Current | $ | 26 | | | | $ | (24) | | | $ | (7) | | | $ | 4 | | | $ | 25 | | | $ | 40 | | | $ | (13) | | | $ | (4) | | Deferred | 489 |
| | 346 |
| | 15 |
| | 20 |
| | 95 |
| | (34 | ) | | (6 | ) | | (21 | ) | | (6 | ) | Deferred | 156 | | | | 112 | | | 1 | | | 10 | | | (129) | | | (62) | | | (20) | | | (43) | | Investment tax credit amortization | (72 | ) | | (69 | ) | | (2 | ) | | — |
| | — |
| | (1 | ) | | — |
| | — |
| | — |
| Investment tax credit amortization | (28) | | | | (2) | | | — | | | — | | | (1) | | | — | | | — | | | — | | State | | | | | | | | | | | | | | | | | | State | | | | Current | 5 |
| | 10 |
| | (5 | ) | | — |
| | — |
| | 3 |
| | — |
| | — |
| | — |
| Current | 42 | | | | (27) | | | — | | | — | | | (5) | | | — | | | — | | | — | | Deferred | 267 |
| | 82 |
| | 96 |
| | — |
| | 35 |
| | 27 |
| | 6 |
| | 14 |
| | 9 |
| Deferred | 177 | | | | 118 | | | (24) | | | 27 | | | 33 | | | 15 | | | 8 | | | 6 | | Total | $ | 774 |
| | $ | 516 |
| | $ | 163 |
| | $ | 65 |
| | $ | 79 |
| | $ | 38 |
| | $ | 16 |
| | $ | 22 |
| | $ | — |
| Total | $ | 373 | | | | $ | 177 | | | $ | (30) | | | $ | 41 | | | $ | (77) | | | $ | (7) | | | $ | (25) | | | $ | (41) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | For the Year Ended December 31, 2019 | | Exelon | | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Included in operations: | | | | | | | | | | | | | | | | | | Federal | | | | | | | | | | | | | | | | | | Current | $ | 85 | | | | | $ | 59 | | | $ | 45 | | | $ | (51) | | | $ | 43 | | | $ | 16 | | | $ | 29 | | | $ | (3) | | Deferred | 489 | | | | | 15 | | | 20 | | | 95 | | | (34) | | | (6) | | | (21) | | | (6) | | Investment tax credit amortization | (72) | | | | | (2) | | | — | | | — | | | (1) | | | — | | | — | | | — | | State | | | | | | | | | | | | | | | | | | Current | 5 | | | | | (5) | | | — | | | — | | | 3 | | | — | | | — | | | — | | Deferred | 267 | | | | | 96 | | | — | | | 35 | | | 27 | | | 6 | | | 14 | | | 9 | | Total | $ | 774 | | | | | $ | 163 | | | $ | 65 | | | $ | 79 | | | $ | 38 | | | $ | 16 | | | $ | 22 | | | $ | — | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | For the Year Ended December 31, 2018 | | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Included in operations: | | | | | | | | | | | | | | | | | | Federal | | | | | | | | | | | | | | | | | | Current | $ | 226 |
| | $ | 337 |
| | $ | (63 | ) | | $ | 11 |
| | $ | (5 | ) | | $ | (4 | ) | | $ | 28 |
| | $ | (3 | ) | | $ | (14 | ) | Deferred | (99 | ) | | (347 | ) | | 145 |
| | 10 |
| | 47 |
| | 23 |
| | (22 | ) | | 13 |
| | 18 |
| Investment tax credit amortization | (24 | ) | | (21 | ) | | (2 | ) | | — |
| | — |
| | (1 | ) | | — |
| | — |
| | — |
| State | | | | | | | | | | | | | | | | | | Current | (1 | ) | | 6 |
| | (29 | ) | | 1 |
| | — |
| | 7 |
| | — |
| | — |
| | — |
| Deferred | 16 |
| | (83 | ) | | 117 |
| | (16 | ) | | 32 |
| | 8 |
| | 5 |
| | 12 |
| | 8 |
| Total | $ | 118 |
| | $ | (108 | ) | | $ | 168 |
| | $ | 6 |
| | $ | 74 |
| | $ | 33 |
| | $ | 11 |
| | $ | 22 |
| | $ | 12 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | For the Year Ended December 31, 2017 | | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Included in operations: | | | | | | | | | | | | | | | | | | Federal | | | | | | | | | | | | | | | | | | Current | $ | 194 |
| | $ | 584 |
| | $ | (191 | ) | | $ | 71 |
| | $ | 74 |
| | $ | (60 | ) | | $ | (20 | ) | | $ | (24 | ) | | $ | (12 | ) | Deferred | (470 | ) | | (2,005 | ) | | 523 |
| | 28 |
| | 101 |
| | 251 |
| | 115 |
| | 82 |
| | 34 |
| Investment tax credit amortization | (25 | ) | | (21 | ) | | (2 | ) | | — |
| | (1 | ) | | (1 | ) | | — |
| | — |
| | — |
| State | | | | | | | | | | | | | | | | |
| Current | 14 |
| | 65 |
| | (49 | ) | | 14 |
| | (5 | ) | | (4 | ) | | (2 | ) | | — |
| | — |
| Deferred | 161 |
| | 1 |
| | 136 |
| | (9 | ) | | 49 |
| | 31 |
| | 12 |
| | 13 |
| | 4 |
| Total | $ | (126 | ) | | $ | (1,376 | ) | | $ | 417 |
| | $ | 104 |
| | $ | 218 |
| | $ | 217 |
| | $ | 105 |
| | $ | 71 |
| | $ | 26 |
|
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 13 — Income Taxes
Rate Reconciliation The effective income tax rate from continuing operations varies from the U.S. federal statutory rate principally due to the following: 258 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | For the Year Ended December 31, 2019 | | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | 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 | 5.4 |
| | 3.8 |
| | 8.5 |
| | — |
| | 6.4 |
| | 4.7 |
| | 2.0 |
| | 6.8 |
| | 7.0 |
| Qualified NDT fund income | 5.9 |
| | 12.3 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Amortization of investment tax credit, including deferred taxes on basis difference | (1.5 | ) | | (3.0 | ) | | (0.2 | ) | | — |
| | (0.1 | ) | | (0.2 | ) | | (0.1 | ) | | (0.2 | ) | | (0.3 | ) | Plant basis differences | (1.4 | ) | | — |
| | — |
| | (7.2 | ) | | (1.2 | ) | | (1.2 | ) | | (1.8 | ) | | (0.4 | ) | | (0.7 | ) | Production tax credits and other credits | (3.1 | ) | | (4.8 | ) | | (1.2 | ) | | — |
| | (1.3 | ) | | (0.2 | ) | | (0.1 | ) | | — |
| | (0.1 | ) | Noncontrolling interests | (0.6 | ) | | (1.2 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Excess deferred tax amortization | (5.5 | ) | | — |
| | (9.7 | ) | | (2.8 | ) | | (6.8 | ) | | (17.5 | ) | | (15.1 | ) | | (14.2 | ) | | (27.0 | ) | Other | (0.8 | ) | | (1.2 | ) | | 0.8 |
| | — |
| | — |
| | 0.8 |
| | 0.3 |
| | — |
| | 0.1 |
| Effective income tax rate | 19.4 | % | | 26.9 | % | | 19.2 | % | | 11.0 | % | | 18.0 | % | | 7.4 | % | | 6.2 | % | | 13.0 | % | | — | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | For the Year Ended December 31, 2018 | | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | 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 | 0.5 |
| | (16.6 | ) | | 8.3 |
| | (2.6 | ) | | 6.6 |
| | 2.9 |
| | 2.0 |
| | 6.7 |
| | 7.4 |
| Qualified NDT fund income | (1.9 | ) | | (11.8 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Amortization of investment tax credit, including deferred taxes on basis difference | (1.2 | ) | | (6.5 | ) | | (0.2 | ) | | (0.1 | ) | | (0.1 | ) | | (0.2 | ) | | (0.1 | ) | | (0.3 | ) | | (0.4 | ) | Plant basis differences | (3.5 | ) | | — |
| | (0.2 | ) | | (14.1 | ) | | (1.3 | ) | | (1.6 | ) | | (2.8 | ) | | (0.3 | ) | | (0.5 | ) | Production tax credits and other credits | (2.2 | ) | | (13.5 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Noncontrolling interests | (1.0 | ) | | (6.1 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Excess deferred tax amortization | (8.3 | ) | | — |
| | (9.1 | ) | | (3.2 | ) | | (8.0 | ) | | (14.8 | ) | | (15.3 | ) | | (12.0 | ) | | (14.9 | ) | Tax Cuts and Jobs Act of 2017 | 0.9 |
| | 2.7 |
| | (0.1 | ) | | — |
| | — |
| | 0.1 |
| | — |
| | — |
| | — |
| Other | 1.0 |
| | 1.3 |
| | 0.5 |
| | 0.3 |
| | 0.9 |
| | 0.4 |
| | 0.3 |
| | 0.4 |
| | 1.2 |
| Effective income tax rate | 5.3 | % | | (29.5 | )% | | 20.2 | % | | 1.3 | % | | 19.1 | % | | 7.8 | % | | 5.1 | % | | 15.5 | % | | 13.8 | % |
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 1314 — Income Taxes
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | For the Year Ended December 31, 2021(a) | | Exelon | | | | ComEd | | PECO(b) | | BGE(b) | | PHI | | Pepco | | DPL(b) | | 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 | 4.8 | | | | | 7.8 | | | (1.4) | | | (10.8) | | | 10.1 | | | 2.7 | | | 25.0 | | | 7.4 | | Qualified NDT fund income | 11.3 | | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Amortization of investment tax credit, including deferred taxes on basis differences | (0.7) | | | | | (0.1) | | | — | | | (0.1) | | | (0.1) | | | — | | | (0.2) | | | (0.2) | | Plant basis differences | (4.1) | | | | | (0.8) | | | (13.6) | | | (1.7) | | | (1.1) | | | (1.6) | | | (0.8) | | | (0.2) | | Production tax credits and other credits | (2.5) | | | | | (0.5) | | | — | | | (0.9) | | | (0.5) | | | (0.5) | | | (0.4) | | | (0.5) | | Excess deferred tax amortization | (12.9) | | | | | (7.6) | | | (3.8) | | | (16.3) | | | (22.4) | | | (16.4) | | | (20.0) | | | (37.1) | | | | | | | | | | | | | | | | | | | | Other | (0.1) | | | | | (1.0) | | | 0.1 | | | (0.6) | | | — | | | (0.4) | | | 0.1 | | | (0.2) | | Effective income tax rate | 16.8 | % | | | | 18.8 | % | | 2.3 | % | | (9.4) | % | | 7.0 | % | | 4.8 | % | | 24.7 | % | | (9.8) | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | For the Year Ended December 31, 2020(a) | | Exelon | | | | ComEd(c) | | PECO(c) | | BGE(d) | | PHI(d) | | Pepco(d) | | DPL(d) | | ACE(d) | 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 | 7.8 | | | | | 11.6 | | | (4.5) | | | 5.5 | | | 5.1 | | | 4.5 | | | 6.6 | | | 7.0 | | Qualified NDT fund income | 8.4 | | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Deferred Prosecution Agreement payments | 1.8 | | | | | 6.8 | | | — | | | — | | | — | | | — | | | — | | | — | | Amortization of investment tax credit, including deferred taxes on basis differences | (1.1) | | | | | (0.3) | | | — | | | (0.1) | | | (0.2) | | | (0.1) | | | (0.3) | | | (0.5) | | Plant basis differences | (4.0) | | | | | (0.6) | | | (18.7) | | | (1.5) | | | (1.6) | | | (1.7) | | | (0.4) | | | (3.0) | | Production tax credits and other credits | (2.2) | | | | | (0.3) | | | — | | | (0.4) | | | (0.3) | | | (0.3) | | | (0.3) | | | (0.5) | | Noncontrolling interests | 1.1 | | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Excess deferred tax amortization | (13.6) | | | | | (11.2) | | | (4.6) | | | (13.9) | | | (42.0) | | | (25.4) | | | (51.7) | | | (82.1) | | Tax Settlements(e) | (3.7) | | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Other | 0.5 | | | | | 1.8 | | | (0.4) | | | (0.1) | | | (0.4) | | | (0.7) | | | 0.1 | | | 0.4 | | Effective income tax rate | 16.0 | % | | | | 28.8 | % | | (7.2) | % | | 10.5 | % | | (18.4) | % | | (2.7) | % | | (25.0) | % | | (57.7) | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | For the Year Ended December 31, 2019(a) | | Exelon | | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | 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 | 5.4 | | | | | 8.5 | | | — | | | 6.4 | | | 4.7 | | | 2.0 | | | 6.8 | | | 7.0 | | Qualified NDT fund income | 5.9 | | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Amortization of investment tax credit, including deferred taxes on basis differences | (1.5) | | | | | (0.2) | | | — | | | (0.1) | | | (0.2) | | | (0.1) | | | (0.2) | | | (0.3) | | Plant basis differences | (1.4) | | | | | — | | | (7.2) | | | (1.2) | | | (1.2) | | | (1.8) | | | (0.4) | | | (0.7) | | Production tax credits and other credits | (3.1) | | | | | (1.2) | | | — | | | (1.3) | | | (0.2) | | | (0.1) | | | — | | | (0.1) | | Noncontrolling interests | (0.6) | | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Excess deferred tax amortization | (5.5) | | | | | (9.7) | | | (2.8) | | | (6.8) | | | (17.5) | | | (15.1) | | | (14.2) | | | (27.0) | | | | | | | | | | | | | | | | | | | | Other | (0.8) | | | | | 0.8 | | | — | | | — | | | 0.8 | | | 0.3 | | | — | | | 0.1 | | Effective income tax rate | 19.4 | % | | | | 19.2 | % | | 11.0 | % | | 18.0 | % | | 7.4 | % | | 6.2 | % | | 13.0 | % | | — | % |
__________ (a)Positive percentages represent income tax expense. Negative percentages represent income tax benefit. (b)For PECO, the lower effective tax rate is primarily related to 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 DPL, the higher effective tax rate is primarily related to a state income tax expense, net of federal income tax benefit, due to the recognition of a valuation allowance of approximately $31 million against a deferred tax asset associated with Delaware net operating loss carryforwards as a result of a change in Delaware tax law. For ACE, the income tax benefit is primarily due to a distribution rate case settlement which allows ACE to retain certain tax benefits. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | For the Year Ended December 31, 2017 | | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | U.S. Federal statutory rate | 35.0 | % | | 35.0 | % | | 35.0 | % | | 35.0 | % | | 35.0 | % | | 35.0 | % | | 35.0 | % | | 35.0 | % | | 35.0 | % | Increase (decrease) due to: | | | | | | | | | | | | | | | | | | State income taxes, net of Federal income tax benefit | 2.2 |
| | 2.9 |
| | 5.7 |
| | 0.6 |
| | 5.4 |
| | 4.8 |
| | 3.1 |
| | 5.4 |
| | 5.6 |
| Qualified NDT fund income | 3.8 |
| | 9.9 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Amortization of investment tax credit, including deferred taxes on basis difference | (0.9 | ) | | (2.1 | ) | | (0.2 | ) | | (0.1 | ) | | (0.1 | ) | | (0.2 | ) | | (0.1 | ) | | (0.2 | ) | | (0.4 | ) | Plant basis differences(a) | (1.7 | ) | | — |
| | 0.3 |
| | (13.8 | ) | | 0.1 |
| | 1.1 |
| | (0.4 | ) | | 2.0 |
| | 3.6 |
| Production tax credits and other credits | (1.8 | ) | | (4.7 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Like-kind exchange | (1.2 | ) | | — |
| | 1.3 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Merger expenses | (3.6 | ) | | (1.2 | ) | | — |
| | — |
| | — |
| | (9.6 | ) | | (6.4 | ) | | (7.8 | ) | | (19.8 | ) | FitzPatrick bargain purchase gain | (2.2 | ) | | (5.6 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Tax Cuts and Jobs Act of 2017(b) | (33.1 | ) | | (128.3 | ) | | 0.1 |
| | (2.3 | ) | | 0.9 |
| | 6.4 |
| | 2.8 |
| | 2.5 |
| | 1.6 |
| Other | 0.2 |
| | (0.5 | ) | | 0.2 |
| | (0.1 | ) | | 0.2 |
| | 0.5 |
| | 0.7 |
| | 0.1 |
| | (0.4 | ) | Effective income tax rate | (3.3 | )% | | (94.6 | )% | | 42.4 | % | | 19.3 | % | | 41.5 | % |
| 38.0 | % | | 34.7 | % |
| 37.0 | % |
| 25.2 | % |
259
__________
| | (a) | Includes the charges related to the transmission-related income tax regulatory asset for Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE of $35 million, $3 million, $5 million, $27 million, $14 million, $6 million and $7 million, respectively. See Note 3 - Regulatory Matters for additional information. |
| | (b) | As a result of TCJA, Generation recorded a net decrease to income tax expense, while the Utility Registrants recorded corresponding regulatory liabilities or assets to the extent such amounts are probable of settlement or recovery through customer rates and an adjustment to income tax expense for all other amounts. |
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 1314 — Income Taxes
(c)At ComEd, the higher effective tax rate is primarily related to the nondeductible Deferred Prosecution Agreement payments. At PECO, the negative effective tax rate is primarily related to an increase in plant basis differences attributable to tax repair deductions related to an increase in storms and qualifying projects in 2021.
(d)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. See Note 3 — Regulatory Matters for additional information. (e)Exelon's unrecognized federal and state tax benefits decreased in the first quarter of 2020 by approximately $411 million due to the settlement of a federal refund claim with IRS Appeals. The recognition of these benefits resulted in an increase to Exelon’s net income of $76 million for the first quarter of 2020, reflecting a decrease to Exelon’s income tax expense of $67 million. Tax Differences and Carryforwards The tax effects of temporary differences and carryforwards, which give rise to significant portions of the deferred tax assets (liabilities), as of December 31, 20192021 and 20182020 are presented below: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | As of December 31, 2021 | | Exelon | | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Plant basis differences | $ | (14,429) | | | | | $ | (4,648) | | | $ | (2,271) | | | $ | (1,826) | | | $ | (2,976) | | | $ | (1,321) | | | $ | (853) | | | $ | (777) | | Accrual based contracts | 18 | | | | | — | | | — | | | — | | | 56 | | | — | | | — | | | — | | Derivatives and other financial instruments | (109) | | | | | 61 | | | — | | | — | | | 2 | | | — | | | — | | | — | | Deferred pension and postretirement obligation | 1,054 | | | | | (308) | | | (32) | | | (37) | | | (90) | | | (76) | | | (40) | | | (6) | | Nuclear decommissioning activities | (912) | | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Deferred debt refinancing costs | 161 | | | | | (6) | | | — | | | (2) | | | 123 | | | (2) | | | (1) | | | (1) | | Regulatory assets and liabilities | (1,130) | | | | | 8 | | | (280) | | | 92 | | | (53) | | | 24 | | | 55 | | | 31 | | Tax loss carryforward, net of valuation allowances | 295 | | | | | — | | | 65 | | | 68 | | | 64 | | | 2 | | | 18 | | | 42 | | Tax credit carryforward | 778 | | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Investment in partnerships | (273) | | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Other, net | 789 | | | | | 216 | | | 97 | | | 21 | | | 212 | | | 99 | | | 19 | | | 34 | | Deferred income tax liabilities (net) | $ | (13,758) | | | | | $ | (4,677) | | | $ | (2,421) | | | $ | (1,684) | | | $ | (2,662) | | | $ | (1,274) | | | $ | (802) | | | $ | (677) | | Unamortized investment tax credits | (384) | | | | | (8) | | | — | | | (2) | | | (5) | | | (1) | | | (1) | | | (2) | | Total deferred income tax liabilities (net) and unamortized investment tax credits | $ | (14,142) | | | | | $ | (4,685) | | | $ | (2,421) | | | $ | (1,686) | | | $ | (2,667) | | | $ | (1,275) | | | $ | (803) | | | $ | (679) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | As of December 31, 2019 | | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Plant basis differences | $ | (13,413 | ) | | $ | (2,814 | ) | | $ | (4,197 | ) | | $ | (1,978 | ) | | $ | (1,578 | ) | | $ | (2,681 | ) | | $ | (1,204 | ) | | $ | (753 | ) | | $ | (687 | ) | Accrual based contracts | 61 |
| | (43 | ) | | — |
| | — |
| | — |
| | 104 |
| | — |
| | — |
| | — |
| Derivatives and other financial instruments | 165 |
| | 88 |
| | 84 |
| | — |
| | — |
| | 2 |
| | — |
| | — |
| | — |
| Deferred pension and postretirement obligation | 1,504 |
| | (220 | ) | | (270 | ) | | (28 | ) | | (28 | ) | | (89 | ) | | (75 | ) | | (42 | ) | | (10 | ) | Nuclear decommissioning activities | (503 | ) | | (503 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Deferred debt refinancing costs | 183 |
| | 20 |
| | (7 | ) | | — |
| | (3 | ) | | 142 |
| | (3 | ) | | (2 | ) | | (1 | ) | Regulatory assets and liabilities | (884 | ) | | — |
| | 183 |
| | (169 | ) | | 157 |
| | (10 | ) | | 55 |
| | 88 |
| | 77 |
| Tax loss carryforward | 240 |
| | 55 |
| | — |
| | 25 |
| | 49 |
| | 93 |
| | 13 |
| | 44 |
| | 31 |
| Tax credit carryforward | 892 |
| | 897 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Investment in partnerships | (830 | ) | | (808 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Other, net | 926 |
| | 236 |
| | 196 |
| | 70 |
| | 10 |
| | 181 |
| | 85 |
| | 12 |
| | 16 |
| Deferred income tax liabilities (net) | $ | (11,659 | ) | | $ | (3,092 | ) | | $ | (4,011 | ) | | $ | (2,080 | ) | | $ | (1,393 | ) |
| $ | (2,258 | ) |
| $ | (1,129 | ) |
| $ | (653 | ) |
| $ | (574 | ) | Unamortized investment tax credits | (668 | ) | | (648 | ) | | (10 | ) | | (1 | ) | | (3 | ) | | (7 | ) | | (2 | ) | | (2 | ) | | (3 | ) | Total deferred income tax liabilities (net) and unamortized investment tax credits | $ | (12,327 | ) | | $ | (3,740 | ) | | $ | (4,021 | ) | | $ | (2,081 | ) | | $ | (1,396 | ) |
| $ | (2,265 | ) |
| $ | (1,131 | ) |
| $ | (655 | ) |
| $ | (577 | ) |
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 1314 — Income Taxes
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | As of December 31, 2020 | | Exelon | | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Plant basis differences | $ | (13,868) | | | | | $ | (4,432) | | | $ | (2,131) | | | $ | (1,711) | | | $ | (2,822) | | | $ | (1,259) | | | $ | (806) | | | $ | (725) | | Accrual based contracts | 40 | | | | | — | | | — | | | — | | | 77 | | | — | | | — | | | — | | Derivatives and other financial instruments | 41 | | | | | 84 | | | — | | | — | | | 2 | | | — | | | — | | | — | | Deferred pension and postretirement obligation | 1,559 | | | | | (288) | | | (30) | | | (33) | | | (80) | | | (74) | | | (40) | | | (7) | | Nuclear decommissioning activities | (742) | | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Deferred debt refinancing costs | 169 | | | | | (6) | | | — | | | (2) | | | 131 | | | (3) | | | (1) | | | (1) | | Regulatory assets and liabilities | (1,107) | | | | | 87 | | | (231) | | | 142 | | | (41) | | | 38 | | | 67 | | | 46 | | Tax loss carryforward, net of valuation allowances | 286 | | | | | — | | | 47 | | | 57 | | | 90 | | | 4 | | | 49 | | | 38 | | Tax credit carryforward | 841 | | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Investment in partnerships | (835) | | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Other, net | 1,070 | | | | | 223 | | | 104 | | | 29 | | | 220 | | | 107 | | | 18 | | | 27 | | Deferred income tax liabilities (net) | $ | (12,546) | | | | | $ | (4,332) | | | $ | (2,241) | | | $ | (1,518) | | | $ | (2,423) | | | $ | (1,187) | | | $ | (713) | | | $ | (622) | | Unamortized investment tax credits(a) | (464) | | | | | (9) | | | (1) | | | (3) | | | (6) | | | (2) | | | (2) | | | (3) | | Total deferred income tax liabilities (net) and unamortized investment tax credits | $ | (13,010) | | | | | $ | (4,341) | | | $ | (2,242) | | | $ | (1,521) | | | $ | (2,429) | | | $ | (1,189) | | | $ | (715) | | | $ | (625) | |
_________ | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | As of December 31, 2018 | | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Plant basis differences | $ | (12,533 | ) | | $ | (2,495 | ) | | $ | (4,059 | ) | | $ | (1,862 | ) | | $ | (1,399 | ) | | $ | (2,577 | ) | | $ | (1,148 | ) | | $ | (743 | ) | | $ | (645 | ) | Accrual based contracts | 117 |
| | (44 | ) | | — |
| | — |
| | — |
| | 161 |
| | — |
| | — |
| | — |
| Derivatives and other financial instruments | 89 |
| | 35 |
| | 69 |
| | — |
| | — |
| | 3 |
| | — |
| | — |
| | — |
| Deferred pension and postretirement obligation | 1,435 |
| | (188 | ) | | (255 | ) | | (26 | ) | | (26 | ) | | (102 | ) | | (78 | ) | | (46 | ) | | (14 | ) | Nuclear decommissioning activities | (351 | ) | | (351 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Deferred debt refinancing costs | 234 |
| | 23 |
| | (7 | ) | | — |
| | (3 | ) | | 187 |
| | (4 | ) | | (2 | ) | | (1 | ) | Regulatory assets and liabilities | (740 | ) | | — |
| | 300 |
| | (129 | ) | | 172 |
| | (81 | ) | | 67 |
| | 96 |
| | 83 |
| Tax loss carryforward | 237 |
| | 78 |
| | — |
| | 18 |
| | 25 |
| | 96 |
| | 12 |
| | 52 |
| | 26 |
| Tax credit carryforward | 811 |
| | 816 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Investment in partnerships | (797 | ) | | (775 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Other, net | 934 |
| | 239 |
| | 151 |
| | 67 |
| | 12 |
| | 196 |
| | 98 |
| | 17 |
| | 19 |
| Deferred income tax liabilities (net) | $ | (10,564 | ) | | $ | (2,662 | ) | | $ | (3,801 | ) | | $ | (1,932 | ) | | $ | (1,219 | ) |
| $ | (2,117 | ) |
| $ | (1,053 | ) |
| $ | (626 | ) |
| $ | (532 | ) | Unamortized investment tax credits | (724 | ) | | (700 | ) | | (12 | ) | | (1 | ) | | (3 | ) | | (8 | ) | | (2 | ) | | (2 | ) | | (3 | ) | Total deferred income tax liabilities (net) and unamortized investment tax credits | $ | (11,288 | ) | | $ | (3,362 | ) | | $ | (3,813 | ) | | $ | (1,933 | ) | | $ | (1,222 | ) |
| $ | (2,125 | ) |
| $ | (1,055 | ) |
| $ | (628 | ) |
| $ | (535 | ) |
(a)Does not include unamortized investment tax credits reclassified to liabilities held for sale.The following table provides Exelon’s, Generation’s, PECO’s, BGE’s, PHI’s, Pepco’s, DPL’s, and ACE’s carryforwards, of which the state related items are presented on a post-apportioned basis, and any corresponding valuation allowances as of December 31, 2019.2021. ComEd does not have net operating losses or credit carryforwards for the year ended December 31, 2019.2021. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exelon | | Generation | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Federal | | | | | | | | | | | | | | | | Federal general business credits carryforwards(a) | $ | 891 |
| | $ | 897 |
|
| $ | — |
|
| $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| State | | | | | | | | | | | | | | | | State net operating losses | 3,986 |
| | 1,142 |
| | 312 |
| | 762 |
| | 1,360 |
| | 202 |
| | 654 |
| | 438 |
| Deferred taxes on state tax attributes (net) | 264 |
| | 78 |
| | 25 |
| | 50 |
| | 93 |
| | 13 |
| | 44 |
| | 31 |
| Valuation allowance on state tax attributes | 26 |
| | 24 |
| | — |
| | 1 |
| | — |
| | — |
| | — |
| | — |
| Year in which net operating loss or credit carryforwards will begin to expire | 2025 |
| | 2029 |
| | 2031 |
| | 2026 |
| | 2028 |
| | 2028 |
| | 2030 |
| | 2031 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exelon | | | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Federal | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Federal general business credits carryforwards and other carryforwards(a) | $ | 806 | | | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | State | | | | | | | | | | | | | | | | State net operating losses and other carryforwards | 5,485 | | | | | 890 | | | 1,098 | | | 1,512 | | | 42 | | | 736 | | | 605 | | Deferred taxes on state tax attributes (net of federal taxes) | 365 | | | | | 70 | | | 72 | | | 104 | | | 3 | | | 50 | | | 43 | | Valuation allowance on state tax attributes (net of federal taxes)(b) | 59 | | | | | 3 | | | — | | | 31 | | | — | | | 31 | | | — | | Year in which net operating loss or credit carryforwards will begin to expire(c) | 2035 | | | | 2032 | | 2033 | | 2029 | | N/A | | 2032 | | 2031 |
__________ | | (a) | Exelon's and Generation's federal general business credit carryforwards will begin expiring in 2034. |
(a)For Exelon, the federal general business credit carryforward will begin expiring in 2035. (b)At Exelon, a full valuation allowance has been recorded against certain separate company state net operating loss carryforwards that are expected to expire before realization. At PECO, a full valuation allowance has been recorded against Pennsylvania charitable contributions carryforwards that are expected to expire before realization. At DPL, a full valuation allowance has been recorded against Delaware net operating losses carryforwards due to a change in Delaware tax law. (c)A portion of Exelon's, BGE's, Pepco's, and DPL's Maryland state net operating loss carryforward have an indefinite carryforward period. Tabular Reconciliation of Unrecognized Tax Benefits The following table presents changes in unrecognized tax benefits, by Registrant.
for Exelon, PHI, and ACE. ComEd's, PECO's, BGE's, Pepco's, and DPL's amounts are not material.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 1314 — Income Taxes
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Balance at January 1, 2017 | $ | 916 |
| | $ | 490 |
| | $ | (12 | ) | | $ | — |
| | $ | 120 |
|
| $ | 172 |
|
| $ | 80 |
|
| $ | 37 |
|
| $ | 22 |
| Increases based on tax positions prior to 2017 | 28 |
| | — |
| | 14 |
| | — |
| | — |
| | 14 |
| | — |
| | — |
| | 14 |
| Decreases based on tax positions prior to 2017(a) | (196 | ) | | (17 | ) | | — |
| | — |
| | — |
| | (61 | ) | | (21 | ) | | (16 | ) | | (22 | ) | Decrease from settlements with taxing authorities | (5 | ) | | (5 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Balance at December 31, 2017 | 743 |
| | 468 |
| | 2 |
| | — |
| | 120 |
| | 125 |
| | 59 |
| | 21 |
| | 14 |
| Change to positions that only affect timing | 15 |
| | 15 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Increases based on tax positions prior to 2018 | 30 |
| | 21 |
| | — |
| | — |
| | — |
| | 8 |
| | 7 |
| | 1 |
| | — |
| Decreases based on tax positions prior to 2018(b) | (251 | ) | | (36 | ) | | — |
| | — |
| | (120 | ) | | (88 | ) | | (66 | ) | | (22 | ) | | — |
| Decrease from settlements with taxing authorities | (53 | ) | | (53 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Decreases from expiration of statute of limitations | (7 | ) | | (7 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Balance at December 31, 2018 | 477 |
| | 408 |
| | 2 |
| | — |
| | — |
| | 45 |
| | — |
| | — |
| | 14 |
| Change to positions that only affect timing | 26 |
| | 12 |
| | 3 |
| | 1 |
| | 4 |
| | 3 |
| | 2 |
| | 1 |
| | — |
| Increases based on tax positions related to 2019 | 2 |
| | 1 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Increases based on tax positions prior to 2019 | 34 |
| | 19 |
| | 3 |
| | 2 |
| | 3 |
| | — |
| | — |
| | — |
| | — |
| Decreases based on tax positions prior to 2019 | (3 | ) | | (3 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Decrease from settlements with taxing authorities | (29 | ) | | 4 |
| | (2 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Balance at December 31, 2019 | $ | 507 |
| | $ | 441 |
| | $ | 6 |
| | $ | 3 |
| | $ | 7 |
| | $ | 48 |
| | $ | 2 |
| | $ | 1 |
| | $ | 14 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exelon | | | | | | | | | | PHI | | | | | | ACE | Balance at January 1, 2019 | $ | 477 | | | | | | | | | | | $ | 45 | | | | | | | $ | 14 | | Change to positions that only affect timing | 26 | | | | | | | | | | | 3 | | | | | | | — | | Increases based on tax positions related to 2019 | 2 | | | | | | | | | | | — | | | | | | | — | | Increases based on tax positions prior to 2019 | 34 | | | | | | | | | | | — | | | | | | | — | | Decreases based on tax positions prior to 2019 | (3) | | | | | | | | | | | — | | | | | | | — | | Decrease from settlements with taxing authorities | (29) | | | | | | | | | | | — | | | | | | | — | | Balance at December 31, 2019 | 507 | | | | | | | | | | | 48 | | | | | | | 14 | | Change to positions that only affect timing | 6 | | | | | | | | | | | 3 | | | | | | | 1 | | Increases based on tax positions related to 2020 | 3 | | | | | | | | | | | — | | | | | | | — | | Increases based on tax positions prior to 2020 | 26 | | | | | | | | | | | 1 | | | | | | | — | | Decreases based on tax positions prior to 2020(a) | (348) | | | | | | | | | | | — | | | | | | | — | | Decrease from settlements with taxing authorities(a) | (69) | | | | | | | | | | | — | | | | | | | — | | Balance at December 31, 2020 | 125 | | | | | | | | | | | 52 | | | | | | | 15 | | Change to positions that only affect timing | 13 | | | | | | | | | | | 3 | | | | | | | 1 | | Increases based on tax positions related to 2021 | 4 | | | | | | | | | | | 1 | | | | | | | — | | Increases based on tax positions prior to 2021 | 4 | | | | | | | | | | | — | | | | | | | — | | Decreases based on tax positions prior to 2021 | (3) | | | | | | | | | | | — | | | | | | | — | | Decrease from settlements with taxing authorities | — | | | | | | | | | | | — | | | | | | | — | | | | | | | | | | | | | | | | | | | | Balance at December 31, 2021 | $ | 143 | | | | | | | | | | | $ | 56 | | | | | | | $ | 16 | |
__________ | | (a) | Exelon established a liability for an uncertain tax position associated with the tax deductibility of certain merger commitments incurred by Exelon in connection with the acquisitions of Constellation(a)Exelon's unrecognized federal and PHI. In 2017, as a part of its examination of Exelon's return, the IRS National Office issued guidance concurring with Exelon's position that the merger commitments were deductible. As a result, Exelon, Generation, PHI, Pepco, DPL, and ACE decreased their liability for unrecognized tax benefits by $146 million, $19 million, $59 million, $21 million, $16 million and $22 million, respectively, resulting in a benefit to Income taxes on Exelon's, Generation's, PHI's, Pepco's, DPL's, and ACE's Consolidated Statements of Operations and Comprehensive Income and corresponding decreases in their effective tax rates. |
| | (b) | Exelon, Generation, BGE, PHI, Pepco, and DPL decreased their unrecognized state tax benefits primarily due to the receipt of favorable guidance with respect to the deductibility of certain depreciable fixed assets. The recognition of the tax benefits related to BGE, PHI, Pepco, and DPL was offset by corresponding regulatory liabilities and that portion had no immediate impact to their effective tax rate. |
Like-Kind Exchange
In 2016, the Tax Court held that Exelon was not entitled to defer a gain on its 1999 like-kind exchange transaction. In addition to the tax and interest related to the gain deferral, the Tax Court also ruled that Exelon was liable for penalties and interest on the penalties. Exelon had fully paid the amounts assessed resulting from the Tax Court decision in 2017. In September 2017, Exelon appealed the Tax Court decision to the U.S. Court of Appeals for the Seventh Circuit. In October 2018, the U.S. Court of Appeals for the Seventh Circuit affirmed the Tax Court’s decision. Exelon filed a petition seeking rehearing of the Seventh Circuit’s decision, but the Seventh Circuit denied that petition in December 2018. In the first quarter of 2019, Exelon elected not to seek a further review by the U.S. Supreme
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 13 — Income Taxes
Court. As a result, Exelon's and ComEd's unrecognized tax benefits decreased by approximately $33 million and $2 million, respectively, in the first quarter of 2019.2020 by approximately $411 million due to the settlement of a federal refund claim with IRS Appeals. The recognition of these tax benefits resulted in an increase to Exelon's net income of $76 million in the first quarter of 2020, reflecting a decrease to Exelon's income tax expense of $67 million.
Recognition of unrecognized tax benefits The following table presents Exelon's Generation's and PHI's unrecognized tax benefits that, if recognized, would decrease the effectiveeffective tax rate. ComEd's, PECO's, BGE's, Pepco's, DPL's and ACE'sThe Utility Registrants' amounts are not material. | | | | | | | | | | | | | | Exelon | | Generation | | PHI(a) | December 31, 2019 | $ | 462 |
| | $ | 429 |
| | $ | 32 |
| December 31, 2018 | 463 |
| | 408 |
| | 31 |
| December 31, 2017 | 523 |
| | 461 |
| | 32 |
|
__________
| | | | | | | | | | | | | | | | (a) | PHI has $21 million of unrecognized state tax benefits that, if recognized, $14 million would be in the form of a net operating loss carryforward, which is expected to require a full valuation allowance based on present circumstances.Exelon | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2021 | $ | 77 | | | | | | | | | | | | December 31, 2020 | 73 | | | | | | | | | | | | December 31, 2019 | 462 | | | | | | | | | | | |
The following table presents Exelon's, BGE's, PHI's, Pepco's, DPL's and ACE’s unrecognized tax benefits that, if recognized, may be included in future base rates and that portion would have no impact to the effective tax rate. ComEd's and PECO's amounts are not material.
| | | | | | | | | | | | | | | | | | | | | | | | | | Exelon | | BGE | | PHI | | Pepco | | DPL | | ACE | December 31, 2019 | $ | 19 |
| | $ | 1 |
| | $ | 14 |
| | $ | — |
| | $ | — |
| | $ | 14 |
| December 31, 2018 | 14 |
| | — |
| | 14 |
| | — |
| | — |
| | 14 |
| December 31, 2017 | 214 |
| | 120 |
| | 94 |
| | 59 |
| | 21 |
| | 14 |
|
Reasonably possible the total amount of unrecognized tax benefits could significantly increase or decrease within 12 months after the reporting date SettlementAs of Income Tax Audits, Refund Claims, and Litigation
The following table represents Exelon's, Generation's and ACE'sDecember 31, 2021, ACE has approximately $14 million of unrecognized federal and state tax benefits that could significantly decrease within the 12 months after the reporting date as a result of completing audits, potential settlements, refund claims, andbased on the outcomesoutcome of pending court cases as of December 31, 2019. ComEd's, PECO's, BGE's, PHI's, Pepco'sinvolving other taxpayers. The unrecognized tax benefit, if recognized, may be included in future base rates and DPL's amounts are not material.that portion would have no impact to the effective tax rate.
| | | | | | | | | | | | Exelon(a) | | Generation(a) | | ACE(b) | $ | 425 |
| | $ | 411 |
| | $ | 14 |
|
__________
| | (a) | Exelon and Generation have $411 million that, if recognized, would decrease the effective tax rate. |
| | (b) | The unrecognized tax benefit related to ACE, if recognized, may be included in future base rates and that portion would have no impact to the effective tax rate. |
Total amounts of interest and penalties recognized The following table represents the net interest and penalties receivable (payable) related to tax positions reflected in Exelon's Consolidated Balance Sheets. Generation's and theThe Utility Registrants' amounts are not material. | | | | | | Net interest and penalties receivable as of | Exelon | December 31, 2021(a) | $ | 43 | | December 31, 2020 | 314 | |
| | | | | Net interest and penalties receivable as of | Exelon | December 31, 2019 | $ | 318 |
| December 31, 2018 | 219 |
|
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 1314 — Income Taxes
__________
(a)As of December 31, 2021, the interest receivable balance is not expected to be settled in cash within the next twelve months and therefore classified as non-current receivable. In December of 2021, Exelon received a refund of approximately $272 million related to an interest netting refund claim. The Registrants did not record material interest and penalty expense related to tax positions reflected in their Consolidated Balance Sheets. Interest expense and penalty expense are recorded in Interest expense, net and Other, net, respectively,respectively, in Other income and deductions in the Registrants' Consolidated Statements of Operations and Comprehensive Income. Description of tax years open to assessment by major jurisdiction | | | | | | | | | | | | Major Jurisdiction | Open Years | | Registrants Impacted | Federal consolidated income tax returns(a) | 2002-20182010-2020 | | All Registrants | PHI Holdings and subsidiaries consolidated federal income tax returns | 2016 | Exelon, Generation, PHI, Pepco, DPL, ACE | Delaware separate corporate income tax returns | Same as federal | | DPL | District of Columbia combined corporate income tax returns | 2016-20182018-2020 | | Exelon, PHI, Pepco | Illinois unitary corporate income tax returns | 2010-20182012-2020 | | Exelon, Generation, ComEd | Maryland separate company corporate net income tax returns | Same as federal | | BGE, Pepco, DPL | New Jersey separate corporate income tax returns | 2013-20182017-2018 | | Exelon Generation | New Jersey combined corporate income tax returns | 2019-2020 | | Exelon | New Jersey separate corporate income tax returns | 2014-20182017-2020 | | ACE | New York combined corporate income tax returns | 2010-March 20122011-2020 | | Exelon Generation | New York combined corporate income tax returns | 2011-2018 | Exelon, Generation | Pennsylvania separate corporate income tax returns | 2011-20182011-2016 | | Exelon Generation | Pennsylvania separate corporate income tax returns | 2016-20182018-2020 | | Exelon | Pennsylvania separate corporate income tax returns | 2018-2020 | | PECO |
__________
(a)Certain registrants are only open to assessment for tax years since joining the Exelon federal consolidated group; BGE beginning in 2012 and PHI, Pepco, DPL, and ACE beginning in 2016.
Other Tax Matters Federal Income Tax Law ChangesCENG Put Option (Exelon)
On December 22, 2017, President Trump signedAugust 6, 2021, Generation entered into a settlement agreement pursuant to which Generation purchased EDF’s equity interest in CENG. Exelon recorded deferred tax liabilities of $290 million against Common Stock in Exelon’s Consolidated Balance Sheet. The deferred tax liabilities represent the TCJA into law. Pursuant totax effect on the enactmentdifference between the net purchase price and EDF’s noncontrolling interest as of August 6, 2021. The deferred tax liabilities will reverse during the remaining operating lives and during decommissioning of the TCJA, the Registrants remeasured their existing deferred income tax balances as of December 31, 2017 to reflect the decrease in the corporate income tax rate from 35% to 21%, which resulted in a material decrease to their net deferred income tax liability balances as shown in the table below. Generation recorded a corresponding net decrease to income tax expense, while the Utility Registrants recorded corresponding regulatory liabilities or assets to the extent such amounts are probable of settlement or recovery through customer ratesCENG nuclear plants. See Note 2 — Mergers, Acquisitions, and an adjustment to income tax expenseDispositions for all other amounts. The one-time impacts recorded by the Registrants to remeasure their deferred income tax balances at the 21% corporate federal income tax rate as of December 31, 2017 are presented below:
| | | | | | | | | | | | | | | | | | | | Exelon(b) | | Generation | | ComEd | | PECO(c) | | BGE | | PHI | | Pepco | | DPL | | ACE | Net Decrease to Deferred Income Tax Liability Balances
| $8,624 | | $1,895 | | $2,819 | | $1,407 | | $1,120 | | $1,944 | | $968 | | $540 | | $456 | Net Increase to Regulatory Liabilities Recorded(a) | 7,315 | | N/A | | 2,818 | | 1,394 | | 1,124 | | 1,979 | | 976 | | 545 | | 458 | Net Deferred Income Tax Benefit/(Expense) Recorded | $1,309 | | $1,895 | | $1 | | $13 | | $(4) | | $(35) | | $(8) | | $(5) | | $(2) |
__________
| | (a) | Reflects the net regulatory liabilities recorded on a pre-tax basis before taking into consideration the income tax benefits associated with the ultimate settlement with customers. |
| | (b) | Amounts do not sum across due to deferred tax adjustments recorded at the Exelon Corporation parent company, primarily related to certain employee compensation plans. |
| | (c) | Given the regulatory treatment of income tax benefits related to electric and gas distribution repairs, PECO remained in an overall net regulatory asset position as of December 31, 2017 after recording the impacts related to the TCJA. |
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 13 — Income Taxes
State Income Tax Law Changes
Illinois - On June 5, 2019, the Governor of Illinois signed a tax bill which would increase the Illinois corporate income tax rate from 9.50% to 10.49% effective for tax years beginning on or after January 1, 2021. The tax rate is contingent upon ratification of state constitutional amendments in November 2020. The effect of the rate change will be recognized in the period in which the new legislation is enacted. Exelon, Generation and ComEd do not expect a material impact to their financial statements as a result of the rate change.
In 2017, Exelon reviewed and updated its marginal state income tax rates based on 2016 state apportionment rates. In addition, Exelon, Generation and ComEd recorded the impacts of Illinois’ statutory rate change, which increased the total corporate income tax rate from 7.75% to 9.50% effective July 1, 2017. The following table provides the one-time impact of the rate changes in 2017 for Exelon, Generation and ComEd:
| | | | | | | | | | | | | | Exelon | | Generation | | ComEd | Increase to Deferred Income Taxes | $ | 250 |
| | $ | 20 |
| | $ | 270 |
| Increase in Regulatory Assets | 270 |
| | — |
| | 270 |
| (Decrease)/Increase to Income Tax Expense | (20 | ) | | 20 |
| | — |
|
additional information.Long-Term Marginal State Income Tax Rate (All Registrants) Quarterly, Exelon reviews and updates its marginal state income tax rates and updates for material changes in state tax laws and state apportionment. The Registrants remeasure their existing deferred income tax balances to reflect the changes in marginal rates, which results in either an increase or a decrease to their net deferred income tax liability balances. Utility Registrants record corresponding regulatory liabilities or assets to the extent such amounts are probable of settlement or recovery through customer rates and an adjustment to income tax expense for all other amounts. The impacts to the Utility Registrants for the years ended December 31, 2021, 2020, and 2019 were not material. | | | | | | | | | | | | December 31, 2021 | Exelon | | | | | | | Increase to Deferred Income Tax Liability and Income Tax Expense, Net of Federal Taxes | $ | 27 | | | | | | | | | | | | | | | | December 31, 2020 | | | | | | | | Increase to Deferred Income Tax Liability and Income Tax Expense, Net of Federal Taxes | $ | 66 | | | | | | | | | | | | | | | | December 31, 2019 | | | | | | | | Increase to Deferred Income Tax Liability and Income Tax Expense, Net of Federal Taxes | $ | 20 | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | December 31, 2019 | Exelon | | Generation | | PHI | | DPL | Increase to Deferred Income Tax Liability | $ | 23 |
| | $ | 9 |
| | $ | — |
| | $ | — |
| Increase to Income Tax Expense, Net of Federal Taxes | 23 |
| | 9 |
| | — |
| | — |
| December 31, 2018 | | | | | | | | Decrease to Deferred Income Tax Liability | $ | 50 |
| | $ | 53 |
| | $ | 4 |
| | $ | 2 |
| Decrease to Income Tax Expense, Net of Federal Taxes | 50 |
| | 53 |
| | 3 |
| | — |
|
263
There were no material adjustments
Combined Notes to income tax expenseConsolidated Financial Statements (Dollars in 2017 as a result of changes in state apportionment.millions, except per share data unless otherwise noted)
Note 14 — Income Taxes Allocation of Tax Benefits (All Registrants) Generation and theThe 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). The Tax Sharing Agreement provides that each party is allocated an amount of tax similar to that which would be owed had the party been separately subject to tax. In addition, any net benefitfederal and state benefits attributable to Exelon isare reallocated to the other Registrants. That allocation is treated as a contribution from Exelon 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 | December 31, 2019(a) | $ | 41 |
| | $ | — |
| | $ | 14 |
| | $ | 3 |
| | $ | 7 |
| | $ | 6 |
| | $ | 1 |
| December 31, 2018(b) | 155 |
| | 1 |
| | 48 |
| | 26 |
| | 2 |
| | — |
| | — |
| December 31, 2017(c) | 102 |
| | — |
| | 16 |
| | 10 |
| | 7 |
| | — |
| | — |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ComEd | | PECO | | BGE | | | | PHI | | Pepco | | DPL | | ACE | December 31, 2021(a) | $ | 1 | | | $ | 19 | | | $ | — | | | | | $ | 17 | | | $ | 16 | | | $ | — | | | $ | — | | December 31, 2020(b) | 14 | | | 17 | | | — | | | | | 17 | | | 8 | | | 6 | | | 1 | | December 31, 2019(c) | — | | | 14 | | | 3 | | | | | 7 | | | 6 | | | 1 | | | — | |
__________ | | (a) | ACE did not record an allocation of federal tax benefits from Exelon under the Tax Sharing Agreement as a result of a tax net operating loss. |
| | (b) | Pepco, DPL and ACE did not record an allocation of federal tax benefits from Exelon under the Tax Sharing Agreement as a result of a tax net operating loss. |
(a)BGE, DPL, and ACE did not record an allocation of federal tax benefits from Exelon under the Tax Sharing Agreement as a result of a tax net operating loss.
Combined Notes to Consolidated Financial Statements(c)ComEd and ACE did not record an allocation of federal tax benefits from Exelon under the Tax Sharing Agreement as a result of a tax net operating loss.
(Dollars in millions, except per share data unless otherwise noted)
Note 13 — Income Taxes
| | (c) | ComEd, Pepco, DPL and ACE did not record an allocation of federal tax benefits from Exelon under the Tax Sharing Agreement as a result of a tax net operating loss. |
Research and Development Activities In the fourth quarter of 2019, Exelon and Generation recognized additional tax benefits related to certain research and development activities that qualify for federal and state tax incentives for the 2010 through 2018 tax years, which resulted in an increase to Exelon’s and Generation’s net income of $108 million and $75 million, respectively, for the year ended December 31, 2019, reflecting a decrease to Exelon’s and Generation’s Income tax expense of $97 million and $66 million, respectively.million.
14.15. Retirement Benefits (All Registrants)
Exelon sponsors defined benefit pension plans and OPEB plans for essentially all current employees. Substantially all non-union employees and electing union employees hired on or after January 1, 2001 participate in cash balance pension plans. Effective January 1, 2009, substantially all newly-hired union-represented employees participate in cash balance pension plans. Effective February 1, 2018 for most newly-hired Generation and BSC non-represented, non-craft, employees, January 1, 2021 for most newly-hired utility management employees, and for certain newly-hired union employees pursuant to their collective bargaining agreements, these newly-hired employees are not eligible for pension benefits, and will instead be eligible to receive an enhanced non-discretionary employer contribution in an Exelon defined contribution savings plan. Effective January 1, 2018, most newly-hired non-represented, non-craft, employees are not eligible for OPEB benefits and employees represented by Local 614 are not eligible for retiree health care benefits. Effective January 1, 2021, most non-represented, non-craft, employees who are under the age of 40 are not eligible for retiree health care benefits. Effective January 1, 2022, management employees retiring on or after that date are no longer eligible for retiree life insurance benefits. Effective January 1, 2019, Exelon merged the Exelon Corporation Cash Balance Pension Plan (CBPP) into the Exelon Corporation Retirement Program (ECRP). The merging of the plans did not change the benefits offered to the plan participants and, thus, had no impact on Exelon's pension obligation. However, beginning in 2019, actuarial losses and gains related to the CBPP and ECRP are amortized over participants’ average remaining service period of the merged ECRP rather than each individual plan. Effective February 1, 2022, in connection with the separation, pension and OPEB obligations and assets for current and former Generation employees and shared service employees supporting Generation, were transferred to pension and OPEB plans and trusts established by Generation.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 1415 — Retirement Benefits
The tabletables below showsshow the pension and OPEB plans in which employees of each operating company participated atas of December 31, 2019: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Operating Company(e) | Name of Plan: | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | | Generation | Qualified Pension Plans: | | | | | | | | | | | | | | | | | | | Exelon Corporation Retirement Program(a) | | X | | X | | X | | X | | X | | X | | X | | X | | X | Exelon Corporation Pension Plan for Bargaining Unit Employees(a) | | X | | X | | | | | | | | | | | | | | X | Exelon New England Union Employees Pension Plan(a) | | X | | | | | | | | | | | | | | | | X | Exelon Employee Pension Plan for Clinton, TMI, and Oyster Creek(a) | | X | | X | | X | | X | | X | | X | | | | X | | X | Pension Plan of Constellation Energy Group, Inc.(b) | | X | | X | | X | | X | | X | | X | | X | | | | X | Pension Plan of Constellation Energy Nuclear Group, LLC(c) | | X | | X | | | | X | | X | | X | | | | | | X | Nine Mile Point Pension Plan(c) | | X | | | | | | | | | | | | | | | | X | Constellation Mystic Power, LLC Union Employees Pension Plan Including Plan A and Plan B(b) | | X | | | | | | | | | | | | | | | | X | Pepco Holdings LLC Retirement Plan(d) | | X | | X | | X | | X | | X | | X | | X | | X | | X | Non-Qualified Pension Plans: | | | | | | | | | | | | | | | | | | | Exelon Corporation Supplemental Pension Benefit Plan and 2000 Excess Benefit Plan(a) | | X | | X | | X | | | | X | | | | | | | | X | Exelon Corporation Supplemental Management Retirement Plan(a) | | X | | X | | X | | X | | X | | X | | | | X | | X | Constellation Energy Group, Inc. Senior Executive Supplemental Plan(b) | | X | | | | | | X | | X | | | | | | | | X | Constellation Energy Group, Inc. Supplemental Pension Plan(b) | | X | | | | | | X | | X | | | | | | | | X | Constellation Energy Group, Inc. Benefits Restoration Plan(b) | | X | | X | | X | | X | | X | | | | | | | | X | Constellation Energy Nuclear Plan, LLC Executive Retirement Plan(c) | | X | | | | | | | | X | | | | | | | | X | Constellation Energy Nuclear Plan, LLC Benefits Restoration Plan(c) | | X | | | | | | | | X | | | | | | | | X | Baltimore Gas & Electric Company Executive Benefit Plan(b) | | X | | | | | | X | | | | | | | | | | X | Baltimore Gas & Electric Company Manager Benefit Plan(b) | | X | | X | | X | | X | | | | | | | | | | X | Pepco Holdings LLC 2011 Supplemental Executive Retirement Plan(d) | | | | | | | | | | X | | X | | X | | X | | X | Conectiv Supplemental Executive Retirement Plan(d) | | X | | | | | | | | X | | | | X | | X | | X | Pepco Holdings LLC Combined Executive Retirement Plan(d) | | | | | | | | | | X | | X | | | | | | | Atlantic City Electric Director Retirement Plan(d) | | | | | | | | | | | | | | | | X | | |
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 1415 — Retirement Benefits
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Operating Company(e) | Name of Plan: | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | | Generation | OPEB Plans: | | | | | | | | | | | | | | | | | | | PECO Energy Company Retiree Medical Plan(a) | | X | | X | | X | | X | | X | | X | | X | | X | | X | Exelon Corporation Health Care Program(a) | | X | | X | | X | | X | | X | | X | | X | | X | | X | Exelon Corporation Employees’ Life Insurance Plan(a) | | X | | X | | X | | X | | | | | | | | | | X | Exelon Corporation Health Reimbursement Arrangement Plan(a) | | X | | X | | X | | X | | | | | | | | | | X | Constellation Energy Group, Inc. Retiree Medical Plan(b) | | X | | X | | X | | X | | X | | X | | X | | | | X | Constellation Energy Group, Inc. Retiree Dental Plan(b) | | X | | | | | | X | | | | | | | | | | X | Constellation Energy Group, Inc. Employee Life Insurance Plan and Family Life Insurance Plan(b) | | X | | X | | X | | X | | X | | X | | X | | | | X | Constellation Mystic Power, LLC Post-Employment Medical Account Savings Plan(b) | | X | | | | | | X | | | | | | | | | | X | Exelon New England Union Post-Employment Medical Savings Account Plan(a) | | X | | | | | | | | | | | | | | | | X | Retiree Medical Plan of Constellation Energy Nuclear Group, LLC(c) | | X | | X | | | | X | | X | | X | | | | | | X | Retiree Dental Plan of Constellation Energy Nuclear Group, LLC(c) | | X | | X | | | | X | | X | | X | | | | | | X | Nine Mile Point Nuclear Station, LLC Medical Care and Prescription Drug Plan for Retired Employees(c) | | X | | | | | | | | | | | | | | | | X | Pepco Holdings LLC Welfare Plan for Retirees(d) | | X | | X | | X | | X | | X | | X | | X | | X | | X |
__________ | | (a) | These plans are collectively referred to as the legacy Exelon plans. |
| | (b) | These plans are collectively referred to as the legacy Constellation Energy Group (CEG) Plans. |
| | (c) | These plans are collectively referred to as the legacy CENG plans. |
| | (d) | These plans are collectively referred to as the legacy PHI plans. |
| | (e) | Employees generally remain in their legacy benefit plans when transferring between operating companies. |
(a)These plans are collectively referred to as the legacy Exelon plans. (b)These plans are collectively referred to as the legacy Constellation Energy Group (CEG) Plans. (c)These plans are collectively referred to as the legacy CENG plans. (d)These plans are collectively referred to as the legacy PHI plans. (e)Employees generally remain in their legacy benefit plans when transferring between operating companies. Exelon’s traditional and cash balance pension plans are intended to be tax-qualified defined benefit plans. Exelon has elected that the trusts underlying these plans be treated as qualified trusts under the IRC. If certain conditions are met, Exelon can deduct payments made to the qualified trusts, subject to certain IRC limitations. Benefit Obligations, Plan Assets, and Funded Status During the first quarter of 2019,2021, Exelon received an updated valuation of its pension and OPEB to reflect actual census data as of January 1, 2019.2021. This valuation resulted in an increase to the pension obligations of $33 million and a decrease to the OPEB obligations of $75 million and $36 million, respectively.$9 million. Additionally, accumulated other comprehensive loss increased by $39$1 million (after-tax) and regulatory assets and liabilities increased by $53$21 million and decreased by $5$1 million, respectively.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 1415 — Retirement Benefits
The following tables provide a rollforward of the changes in the benefit obligations and plan assets of Exelon for the most recent two years for all plans combined: | | | | | | | | | | | | | | | | | | | | | | | | | Pension Benefits | | OPEB | | 2021 | | 2020 | | 2021 | | 2020 | Change in benefit obligation: | | | | | | | | Net benefit obligation as of the beginning of year | $ | 24,894 | | | $ | 22,868 | | | $ | 4,604 | | | $ | 4,658 | | Service cost | 439 | | | 387 | | | 80 | | | 90 | | Interest cost | 641 | | | 757 | | | 114 | | | 154 | | Plan participants’ contributions | — | | | — | | | 50 | | | 49 | | Actuarial (gain) loss(a) | (630) | | | 2,217 | | | (223) | | | 49 | | Plan amendments | — | | | — | | | — | | | (111) | | | | | | | | | | | | | | | | | | Settlements | (88) | | | (45) | | | (5) | | | (5) | | | | | | | | | | Gross benefits paid | (1,410) | | | (1,290) | | | (292) | | | (280) | | Net benefit obligation as of the end of year | $ | 23,846 | | | $ | 24,894 | | | $ | 4,328 | | | $ | 4,604 | |
| | | | | | | | | | | | | | | | | | Pension Benefits | | OPEB | | 2019 | | 2018 | | 2019 | | 2018 | Change in benefit obligation: | | | | | | | | Net benefit obligation at beginning of year | $ | 20,692 |
| | $ | 22,337 |
| | $ | 4,369 |
| | $ | 4,856 |
| Service cost | 357 |
| | 405 |
|
| 93 |
| | 112 |
| Interest cost | 883 |
| | 802 |
|
| 188 |
| | 175 |
| Plan participants’ contributions | — |
| | — |
| | 44 |
| | 45 |
| Actuarial (gain) loss(a) | 2,322 |
| | (1,561 | ) | | 250 |
| | (540 | ) | Plan amendments | 68 |
| | (4 | ) | | — |
| | — |
| Curtailments | (3 | ) | | — |
| | — |
| | — |
| Settlements | (35 | ) | | (48 | ) |
| (4 | ) | | (4 | ) | Contractual termination benefits | 1 |
| | — |
| | — |
| | — |
| Gross benefits paid | (1,417 | ) | | (1,239 | ) |
| (282 | ) | | (275 | ) | Net benefit obligation at end of year | $ | 22,868 |
| | $ | 20,692 |
| | $ | 4,658 |
| | $ | 4,369 |
|
| | | Pension Benefits | | OPEB | | Pension Benefits | | OPEB | | 2019 | | 2018 | | 2019 | | 2018 | | 2021 | | 2020 | | 2021 | | 2020 | Change in plan assets: | | | | | | | | Change in plan assets: | | | | | | | | Fair value of net plan assets at beginning of year | $ | 16,678 |
| | $ | 18,573 |
| | $ | 2,408 |
| | $ | 2,732 |
| | Fair value of net plan assets as of the beginning of year | | Fair value of net plan assets as of the beginning of year | $ | 20,344 | | | $ | 18,590 | | | $ | 2,554 | | | $ | 2,541 | | Actual return on plan assets | 3,008 |
| | (945 | ) | | 324 |
| | (136 | ) | Actual return on plan assets | 1,407 | | | 2,547 | | | 203 | | | 190 | | Employer contributions | 356 |
|
| 337 |
|
| 51 |
|
| 46 |
| Employer contributions | 574 | | | 542 | | | 91 | | | 59 | | Plan participants’ contributions | — |
| | — |
| | 44 |
| | 45 |
| Plan participants’ contributions | — | | | — | | | 50 | | | 49 | | Gross benefits paid | (1,417 | ) |
| (1,239 | ) |
| (282 | ) |
| (275 | ) | Gross benefits paid | (1,410) | | | (1,290) | | | (292) | | | (280) | | | Settlements | (35 | ) |
| (48 | ) |
| (4 | ) |
| (4 | ) | Settlements | (88) | | | (45) | | | (5) | | | (5) | | Fair value of net plan assets at end of year | $ | 18,590 |
| | $ | 16,678 |
| | $ | 2,541 |
| | $ | 2,408 |
| | Fair value of net plan assets as of the end of year | | Fair value of net plan assets as of the end of year | $ | 20,827 | | | $ | 20,344 | | | $ | 2,601 | | | $ | 2,554 | |
__________ | | (a) | The pension actuarial loss in 2019 primarily reflects a decrease in the discount rate. The OPEB actuarial loss in 2019 primarily reflects a decrease in the discount rate. The pension actuarial gain in 2018 primarily reflects an increase in the discount rate. The OPEB actuarial gain in 2018 primarily reflects an increase in the discount rate and favorable health care claims experience. |
(a)The pension and OPEB gains in 2021 primarily reflect an increase in the discount rate. In 2020, the actuarial losses primarily reflect a decrease in the discount rate. OPEB losses in 2020 were offset by gains related to plan changes. Exelon presents its benefit obligations and plan assets net on its balance sheet within the following line items: | | | | | | | | | | | | | | | | | | | | | | | | | Pension Benefits | | OPEB | | 2021 | | 2020 | | 2021 | | 2020 | Other current liabilities | $ | 29 | | | $ | 47 | | | $ | 42 | | | $ | 42 | | Pension obligations | 2,990 | | | 4,503 | | | — | | | — | | Non-pension postretirement benefit obligations | — | | | — | | | 1,685 | | | 2,008 | | Unfunded status (net benefit obligation less plan assets) | $ | 3,019 | | | $ | 4,550 | | | $ | 1,727 | | | $ | 2,050 | |
| | | | | | | | | | | | | | | | | | Pension Benefits | | OPEB | | 2019 | | 2018 | | 2019 | | 2018 | Other current liabilities | $ | 31 |
| | $ | 26 |
| | $ | 41 |
| | $ | 33 |
| Pension obligations | 4,247 |
|
| 3,988 |
|
| — |
|
| — |
| Non-pension postretirement benefit obligations | — |
| | — |
| | 2,076 |
|
| 1,928 |
| Unfunded status (net benefit obligation less plan assets) | $ | 4,278 |
|
| $ | 4,014 |
|
| $ | 2,117 |
|
| $ | 1,961 |
|
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 1415 — Retirement Benefits
The following table provides the accumulated benefit obligation (ABO)ABO and fair value of plan assets for all pension plans with an ABO in excess of plan assets. Information for pension and OPEB plans with projected benefit obligations (PBO) and accumulated postretirement benefit obligation (APBO), respectively, in excess of plan assets has been disclosed in the Obligations and Plan Assets table above as all pension and OPEB plans are underfunded. | | | | | | | ABO in excess of plan assets | Exelon | | 2019 | | 2018 | Accumulated benefit obligation | 21,727 |
| | 19,656 |
| Fair value of net plan assets | 18,590 |
| | 16,678 |
|
| | | | | | | | | | | | | | | Exelon | | | ABO in Excess of Plan Assets | 2021 | | 2020 | | | | | | | | | ABO | $ | 22,609 | | | $ | 23,514 | | | | Fair value of net plan assets | 20,827 | | | 20,344 | | | |
Components of Net Periodic Benefit Costs The majority of the 20192021 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 4.31%2.58%. The majority of the 20192021 OPEB cost is calculated using an expected long-term rate of return on plan assets of 6.67%6.46% for funded plans and a discount rate of 4.30%2.51%. A portion of the net periodic benefit cost for all plans is capitalized withinin the Consolidated Balance Sheets. The following tables presenttable presents the components of Exelon’s net periodic benefit costs, prior to capitalization, for the years ended December 31, 2019, 20182021, 2020, and 2017.2019. | | | Pension Benefits | | OPEB | | Pension Benefits | | OPEB | | 2019 | | 2018 | | 2017(a) | | 2019 | | 2018 | | 2017(a) | | 2021 | | 2020 | | 2019 | | 2021 | | 2020 | | 2019 | Components of net periodic benefit cost: | | | | | | | | | | | | Components of net periodic benefit cost: | | | | | | | | | | | | Service cost | $ | 357 |
|
| $ | 405 |
|
| $ | 387 |
|
| $ | 93 |
|
| $ | 112 |
|
| $ | 106 |
| Service cost | $ | 439 | | | $ | 387 | | | $ | 357 | | | $ | 80 | | | $ | 90 | | | $ | 93 | | Interest cost | 883 |
|
| 802 |
|
| 842 |
|
| 188 |
|
| 175 |
|
| 182 |
| Interest cost | 641 | | | 757 | | | 883 | | | 114 | | | 154 | | | 188 | | Expected return on assets | (1,225 | ) | | (1,252 | ) | | (1,196 | ) | | (153 | ) | | (173 | ) | | (162 | ) | Expected return on assets | (1,336) | | | (1,270) | | | (1,225) | | | (158) | | | (163) | | | (153) | | Amortization of: | | | | | | | | | | | | Amortization of: | | | Prior service cost (credit) | — |
| | 2 |
| | 1 |
| | (179 | ) | | (186 | ) | | (188 | ) | Prior service cost (credit) | 3 | | | 4 | | | — | | | (34) | | | (124) | | | (179) | | Actuarial loss | 414 |
| | 629 |
| | 607 |
| | 45 |
| | 66 |
| | 61 |
| Actuarial loss | 598 | | | 512 | | | 414 | | | 37 | | | 49 | | | 45 | | Curtailment benefits | | Curtailment benefits | — | | | — | | | — | | | — | | | (1) | | | — | | Settlement and other charges | 17 |
| | 3 |
| | 3 |
| | 1 |
| | 1 |
| | — |
| Settlement and other charges | 27 | | | 14 | | | 17 | | | 1 | | | 1 | | | 1 | | Contractual termination benefits | 1 |
| | — |
| | — |
| | — |
| | — |
| | — |
| Contractual termination benefits | — | | | — | | | 1 | | | — | | | — | | | — | | Net periodic benefit cost | $ | 447 |
| | $ | 589 |
| | $ | 644 |
| | $ | (5 | ) | | $ | (5 | ) | | $ | (1 | ) | Net periodic benefit cost | $ | 372 | | | $ | 404 | | | $ | 447 | | | $ | 40 | | | $ | 6 | | | $ | (5) | |
__________
| | (a) | FitzPatrick net benefit costs are included for the period after acquisition. |
Cost Allocation to Exelon Subsidiaries All Registrants account for their participation in Exelon’s pension and OPEB plans by applying multi-employer accounting. Exelon allocates costs related to its pension and OPEB plans to its subsidiaries based on both active and retired employee participation in each plan. The amounts below represent the Registrants’Registrants' allocated pension and OPEB costs. As a result of new pension guidance effective on January 1, 2018, certain balances have been reclassified on Exelon’s Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2017. For Exelon, the service cost component is included in Operating and maintenance expense and Property, plant, and equipment, net while the non–servicenon-service cost components are included in Other, net and Regulatory assets for the years ended December 31, 2019 and December 31, 2018 and in Other, net and Property, plant and equipment, net, for the year ended December 31, 2017.assets. For Generation and the Utility Registrants, the service cost and non–servicenon-service cost components are included
in Operating and maintenance expense and Property, plant, and equipment, net in their consolidated financial statements.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 1415 — Retirement Benefits
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | Exelon | | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | 2021 | $ | 411 | | | | | $ | 129 | | | $ | 8 | | | $ | 64 | | | $ | 49 | | | $ | 6 | | | $ | 2 | | | $ | 11 | | 2020 | 411 | | | | | 114 | | | 5 | | | 64 | | | 70 | | | 15 | | | 7 | | | 14 | | 2019 | 442 | | | | | 96 | | | 12 | | | 61 | | | 95 | | | 25 | | | 15 | | | 16 | |
in Operating and maintenance expense and Property, plant and equipment, net on their consolidated financial statements.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | Exelon | | Generation(a) | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | 2019 | $ | 442 |
| | $ | 135 |
| | $ | 96 |
| | $ | 12 |
| | $ | 61 |
| | $ | 95 |
| | $ | 25 |
| | $ | 15 |
| | $ | 16 |
| 2018 | 583 |
| | 204 |
| | 177 |
| | 18 |
| | 60 |
| | 67 |
| | 15 |
| | 6 |
| | 12 |
| 2017 | 643 |
| | 227 |
| | 176 |
| | 29 |
| | 64 |
| | 94 |
| | 25 |
| | 13 |
| | 13 |
|
__________
| | (a) | FitzPatrick net benefit costs are included for the period after acquisition. |
Components of AOCI and Regulatory Assets Exelon recognizes the overfunded or underfunded status of defined benefit pension and OPEB plans as an asset or liability on its balance sheet, with offsetting entries to AOCI and regulatory assets (liabilities). A portion of current year actuarial gains and(gains) losses and prior service costs (credits) is capitalized withinin Exelon’s Consolidated Balance Sheets to reflect the expected regulatory recovery of these amounts, which would otherwise be recorded to AOCI. The following tables provide the components of AOCI and regulatory assets (liabilities) for Exelon for the years ended December 31, 2019, 20182021, 2020, and 20172019 for all plans combined. | | | | | | | | | | | | | | | | | | | | | | | | | | Pension Benefits | | OPEB | | 2019 | | 2018 | | 2017 | | 2019 | | 2018 | | 2017 | Changes in plan assets and benefit obligations recognized in AOCI and regulatory assets (liabilities): | | | | | | | | | | | | Current year actuarial (gain) loss | $ | 538 |
| | $ | 635 |
| | $ | (222 | ) | | $ | 80 |
| | $ | (232 | ) | | $ | 166 |
| Amortization of actuarial loss | (414 | ) | | (629 | ) | | (607 | ) | | (45 | ) | | (66 | ) | | (61 | ) | Current year prior service cost (credit) | 68 |
| | (4 | ) | | 9 |
| | — |
| | — |
| | — |
| Amortization of prior service (cost) credit | — |
| | (2 | ) | | (1 | ) | | 179 |
| | 186 |
| | 188 |
| Curtailments | (3 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| Settlements | (17 | ) | | (3 | ) | | (3 | ) | | (1 | ) | | — |
| | — |
| Total recognized in AOCI and regulatory assets (liabilities) | $ | 172 |
|
| $ | (3 | ) | | $ | (824 | ) | | $ | 213 |
|
| $ | (112 | ) | | $ | 293 |
| | | | | | | | | | | | | Total recognized in AOCI | $ | 169 |
| | $ | 3 |
| | $ | (401 | ) | | $ | 107 |
| | $ | (55 | ) | | $ | 168 |
| Total recognized in regulatory assets (liabilities) | $ | 3 |
| | $ | (6 | ) | | $ | (423 | ) | | $ | 106 |
| | $ | (57 | ) | | $ | 125 |
|
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 14 — Retirement Benefits
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Pension Benefits | | OPEB | | 2021 | | 2020 | | 2019 | | 2021 | | 2020 | | 2019 | Changes in plan assets and benefit obligations recognized in AOCI and regulatory assets (liabilities): | | | | | | | | | | | | Current year actuarial (gain) loss | $ | (700) | | | $ | 941 | | | $ | 538 | | | $ | (270) | | | $ | 22 | | | $ | 80 | | Amortization of actuarial loss | (598) | | | (512) | | | (414) | | | (37) | | | (49) | | | (45) | | Current year prior service cost (credit) | — | | | — | | | 68 | | | — | | | (111) | | | — | | Amortization of prior service (cost) credit | (3) | | | (4) | | | — | | | 34 | | | 124 | | | 179 | | | | | | | | | | | | | | | | | | | | | | | | | | Curtailments | — | | | — | | | (3) | | | — | | | 1 | | | — | | Settlements | (27) | | | (14) | | | (17) | | | (1) | | | (1) | | | (1) | | | | | | | | | | | | | | Total recognized in AOCI and regulatory assets (liabilities) | $ | (1,328) | | | $ | 411 | | | $ | 172 | | | $ | (274) | | | $ | (14) | | | $ | 213 | | | | | | | | | | | | | | Total recognized in AOCI | $ | (747) | | | $ | 271 | | | $ | 169 | | | $ | (130) | | | $ | 6 | | | $ | 107 | | Total recognized in regulatory assets (liabilities) | $ | (581) | | | $ | 140 | | | $ | 3 | | | $ | (144) | | | $ | (20) | | | $ | 106 | |
The following table provides the components of gross accumulated other comprehensive loss and regulatory assets (liabilities) for Exelon that have not been recognized as components of periodic benefit cost atas of December 31, 20192021 and 2018,2020, respectively, for all plans combined: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Pension Benefits | | | | OPEB | | | | 2021 | | 2020 | | | | 2021 | | 2020 | | | Prior service cost (credit) | $ | 32 | | | $ | 35 | | | | | $ | (111) | | | $ | (145) | | | | Actuarial loss | 6,752 | | | 8,077 | | | | | 230 | | | 538 | | | | Total | $ | 6,784 | | | $ | 8,112 | | | | | $ | 119 | | | $ | 393 | | | | | | | | | | | | | | | | Total included in AOCI | $ | 3,592 | | | $ | 4,339 | | | | | $ | 53 | | | $ | 183 | | | | Total included in regulatory assets (liabilities) | $ | 3,192 | | | $ | 3,773 | | | | | $ | 66 | | | $ | 210 | | | |
| | | | | | | | | | | | | | | | | | Pension Benefits | | OPEB | | 2019 |
| 2018 | | 2019 | | 2018 | Prior service (credit) cost | $ | 39 |
|
| $ | (29 | ) | | $ | (158 | ) | | $ | (337 | ) | Actuarial loss | 7,662 |
| | 7,558 |
| | 565 |
| | 531 |
| Total | $ | 7,701 |
| | $ | 7,529 |
| | $ | 407 |
| | $ | 194 |
| | | | | | | | | Total included in AOCI | $ | 4,068 |
| | $ | 3,899 |
| | $ | 177 |
| | $ | 70 |
| Total included in regulatory assets (liabilities) | $ | 3,633 |
| | $ | 3,630 |
| | $ | 230 |
| | $ | 124 |
|
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 15 — Retirement Benefits Average Remaining Service Period For pension benefits, Exelon amortizes its unrecognized prior service costs (credits) and certain actuarial gains and(gains) losses, as applicable, based on participants’ average remaining service periods. For OPEB, Exelon amortizes its unrecognized prior service costs (credits) over participants’ average remaining service period to benefit eligibility age and amortizes certain actuarial gains and(gains) losses over participants’ average remaining service period to expected retirement. The resulting average remaining service periods for pension and OPEB were as follows: | | | | 2019 | | 2018 | | 2017 | | 2021 | | 2020 | | 2019 | Pension plans | | 11.7 |
| | 12.0 |
| | 11.8 |
| Pension plans | | 12.4 | | | 12.3 | | | 11.7 | | OPEB plans: | | | | | | | OPEB plans: | | Benefit Eligibility Age | | 8.7 |
| | 8.8 |
| | 8.8 |
| Benefit Eligibility Age | | 7.6 | | | 9.0 | | | 8.7 | | Expected Retirement | | 9.3 |
| | 9.5 |
| | 9.6 |
| Expected Retirement | | 8.8 | | | 10.2 | | | 9.3 | |
Assumptions The measurement of the plan obligations and costs of providing benefits under Exelon’s defined benefit and other postretirementOPEB plans involves various factors, including the development of valuation assumptions and inputs and accounting policy elections. The measurement of benefit obligations and costs is impacted by several assumptions and inputs, as shown below, among other factors. When developing the required assumptions, Exelon considers historical information as well as future expectations. Expected Rate of Return. In selectingdetermining the EROA, Exelon considers historical economic indicators (including inflation and GDP growth) that impact asset returns, as well as expectations regarding future long-term capital market performance, weighted by Exelon’s target asset class allocations. Mortality. The mortality assumption is composed of a base table that represents the current expectation of life expectancy of the population adjusted by an improvement scale that attempts to anticipate future improvements in life expectancy. For the year endedDecember 31, 2018,2021, Exelon’s mortality assumption was supported by an actuarial experience study of Exelon's plan participants and utilizedutilizes the IRS's RP–2000SOA 2019 base table projected to 2012 with(Pri-2012) and MP-2021 improvement scale AA and projected thereafter with generational improvement scale BB two-dimensional adjusted to a 0.75% long-term rate reached in 2027. use Proxy SSA ultimate improvement rates.For the year ended December 31, 2019,2020, Exelon's mortality assumption utilizes the Society of Actuaries'SOA 2019 base table (Pri-2012) and MP-2019MP-2020 improvement scale adjusted to a 0.75% long-term rate reached in 2035.use Proxy SSA ultimate improvement rates. For Exelon, the following assumptions were used to determine the benefit obligations for the plans atas of December 31, 20192021 and 2018.2020. Assumptions used to determine year-end benefit obligations are the assumptions used to estimate the subsequent year’s net periodic benefit costs. | | | | | | | | | | | | | | | | | | | | | | | | | | | | Pension Benefits | | OPEB | | | 2021 | | 2020 | | 2021 | | 2020 | | Discount rate | 2.92 | % | (a) | 2.58 | % | (a) | 2.88 | % | (a) | 2.51 | % | (a) | Investment crediting rate | 3.75 | % | (b) | 3.72 | % | (b) | N/A | | N/A | | Rate of compensation increase | 3.75 | % | | 3.75 | % | | 3.75 | % | | 3.75 | % | | Mortality table | Pri-2012 table with MP- 2021 improvement scale (adjusted) | | Pri-2012 table with MP- 2020 improvement scale (adjusted) | | Pri-2012 table with MP- 2021 improvement scale (adjusted) | | Pri-2012 table with MP- 2020 improvement scale (adjusted) | | Health care cost trend on covered charges | N/A | | N/A | | Initial and ultimate rate of 5.00% | |
Initial and ultimate trend of 5.00% | |
__________ (a)The discount rates above represent the blended rates used to determine the majority of Exelon’s pension and OPEB obligations. Certain benefit plans used individual rates, which range from 2.55% - 3.02% and 2.84% - 2.92% for pension and OPEB plans, respectively, as of December 31, 2021 and 2.11% - 2.73% and 2.45% - 2.63% for pension and OPEB plans, respectively, as of December 31, 2020. (b)The investment crediting rate above represents a weighted average rate.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 1415 — Retirement Benefits
| | | | | | | | | | | | | | | Pension Benefits | OPEB | | 2019 | | 2018 | | 2019 | | 2018 | | Discount rate | 3.34 | % | (a) | 4.31 | % | (a) | 3.31 | % | (a) | 4.30 | % | (a) | Investment Crediting Rate | 3.82 | % | (b) | 4.46 | % | (b) | N/A |
| | N/A |
| | Rate of compensation increase | | (c) | | (c) | | (c) | | (c) | Mortality table | Pri-2012 table with MP- 2019 improvement scale (adjusted) | | RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted) | | Pri-2012 table with MP- 2019 improvement scale (adjusted) | | RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted) | | Health care cost trend on covered charges | N/A | | N/A | | 5.00% with ultimate trend of 5.00% in 2017 | | 5.00% with ultimate trend of 5.00% in 2017 | |
__________
| | (a) | The discount rates above represent the blended rates used to determine the majority of Exelon’s pension and OPEB obligations. Certain benefit plans used individual rates, which range from 3.02% - 3.44% and 3.27% - 3.4% for pension and OPEB plans, respectively, as of December 31, 2019 and 4.13% - 4.36% and 4.27% - 4.38% for pension and OPEB plans, respectively, as of December 31, 2018. |
| | (b) | The investment crediting rate above represents a weighted average rate. |
| | (c) | 3.25% through 2019 and 3.75% thereafter. |
The following assumptions were used to determine the net periodic benefit cost for Exelon for the years ended December 31, 2019, 20182021, 2020 and 2017:2019: | | | | | | | | | | | | | | | | | | | | | Pension Benefits | | OPEB | | | Pension Benefits | | Other Postretirement Benefits | | | 2021 | | 2020 | | 2019 | | 2021 | | 2020 | | 2019 | | Exelon | 2019 | | 2018 | | 2017 | | 2019 | | 2018 | | 2017 | | | Discount rate | 4.31 | % | (a) | 3.62 | % | (a) | 4.04 | % | (a) | 4.30 | % | (a) | 3.61 | % | (a) | 4.04 | % | (a) | Discount rate | 2.58 | % | (a) | 3.34 | % | (a) | 4.31 | % | (a) | 2.51 | % | (a) | 3.31 | % | (a) | 4.30 | % | (a) | Investment Crediting Rate | 4.46 | % | (b) | 4.00 | % | (b) | 4.46 | % | (b) | N/A |
| | N/A |
| | N/A |
| | | Investment crediting rate | | Investment crediting rate | 3.72 | % | (b) | 3.82 | % | (b) | 4.46 | % | (b) | N/A | | N/A | | N/A | | Expected return on plan assets | 7.00 | % | (c) | 7.00 | % | (c) | 7.00 | % | (c) | 6.67 | % | (c) | 6.60 | % | (c) | 6.58 | % | (c) | Expected return on plan assets | 7.00 | % | (c) | 7.00 | % | (c) | 7.00 | % | (c) | 6.46 | % | (c) | 6.69 | % | (c) | 6.67 | % | (c) | Rate of compensation increase | |
| (d) | | (d) | | (e) | |
| (d) | | (d) | | (e) | Rate of compensation increase | 3.75 | % | (d) | 3.75 | % | (d) | 3.25 | % | (d) | 3.75 | % | (d) | 3.75 | % | (d) | 3.25 | % | (d) | Mortality table | RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted) | | RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted) | | RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted) | | RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted) | | RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted) | | RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted) | | Mortality table | Pri-2012 table with MP- 2020 improvement scale (adjusted) | | Pri-2012 table with MP - 2019 improvement scale (adjusted) | | RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted) | | Pri-2012 table with MP- 2020 improvement scale (adjusted) | | Pri-2012 table with MP - 2019 improvement scale (adjusted) | | RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted) | | Health care cost trend on covered charges | N/A | | N/A | | N/A | | 5.00% with ultimate trend of 5.00% in 2017 | | 5.00% with ultimate trend of 5.00% in 2017 | | 5.50% decreasing to ultimate trend of 5.00% in 2017 | | Health care cost trend on covered charges | N/A | | N/A | | N/A | | Initial and ultimate rate of 5.00% | | Initial and ultimate rate of 5.00% | | 5.00% with ultimate trend of 5.00% in 2017 | |
__________ | | (a) | The discount rates above represent the blended rates used to establish the majority of Exelon’s pension and OPEB costs. Certain benefit plans used individual rates, which range from 4.13%-4.36% and 4.27%-4.38% for pension and OPEB plans, respectively, for the year ended December 31, 2019; 3.49%-3.65% and 3.57%-3.68% for pension and OPEB plans; respectively, for the year ended December 31, 2018; and 3.66%-4.11% and 4.00%-4.17% for pension and OPEB plans, respectively, for the year ended December 31, 2017. |
| | (b) | The investment crediting rate above represents a weighted average rate. |
| | (c) | Not applicable to pension and other postretirement benefit plans that do not have plan assets. |
| | (d) | 3.25% through 2019 and 3.75% thereafter. |
| | (e) | The legacy Exelon, CEG and CENG pension and other postretirement plans used a rate of compensation increase of 3.25% through 2019 and 3.75% thereafter, while the legacy PHI pension and OPEB plans used a weighted-average rate of compensation increase of 5% for all periods. |
(a)The discount rates above represent the blended rates used to establish the majority of Exelon’s pension and OPEB costs. Certain benefit plans used individual rates, which range from 2.11%-2.73% and 2.45%-2.63% for pension and OPEB plans, respectively, for the year ended December 31, 2021; 3.02%-3.44% and 3.27%-3.40% for pension and OPEB plans; respectively, for the year ended December 31, 2020; and 4.13%-4.36% and 4.27%-4.38% for pension and OPEB plans, respectively, for the year ended December 31, 2019.
Combined Notes(c)Not applicable to Consolidated Financial Statementspension and OPEB plans that do not have plan assets.
(Dollars in millions, except per share data unless otherwise noted)
Note 14 — Retirement Benefits
(d)3.25% through 2019 and 3.75% thereafter.
Contributions Exelon allocates contributions related to its legacy Exelon pension and OPEB plans to its subsidiaries based on accounting cost. For legacy CEG, CENG, FitzPatrick, and PHI plans, pension and OPEB contributions are allocated to the subsidiaries based on employee participation (both active and retired). The following tables provide contributions to the pension and OPEB plans: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Pension Benefits | | OPEB | | | 2021 | | 2020 | | 2019 | | 2021 | | 2020 | | 2019 | | Exelon | $ | 574 | | | $ | 542 | | | $ | 356 | | | $ | 91 | | | $ | 59 | | | $ | 51 | | | | | | | | | | | | | | | | ComEd | 174 | | | 143 | | | 72 | | | 22 | | | 5 | | | 5 | | | PECO | 17 | | | 18 | | | 27 | | | 1 | | | — | | | 1 | | | BGE | 57 | | | 56 | | | 34 | | | 24 | | | 22 | | | 14 | | | PHI | 39 | | | 30 | | | 10 | | | 9 | | | 9 | | | 15 | | | Pepco | 2 | | | 2 | | | 2 | | | 9 | | | 9 | | | 12 | | | DPL | 1 | | | — | | | 1 | | | — | | | — | | | — | | | ACE | 3 | | | 2 | | | — | | | — | | | — | | | 1 | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | Pension Benefits | | OPEB | | 2019(a) | | 2018(a) | | 2017(a) | | 2019 | | 2018 | | 2017 | Exelon | $ | 356 |
|
| $ | 337 |
|
| $ | 341 |
|
| $ | 51 |
| | $ | 46 |
| | $ | 64 |
| Generation | 160 |
| | 128 |
| | 137 |
| | 15 |
| | 11 |
| | 11 |
| ComEd | 72 |
| | 38 |
| | 36 |
| | 5 |
| | 4 |
| | 5 |
| PECO | 27 |
| | 28 |
| | 24 |
| | 1 |
| | — |
| | — |
| BGE | 34 |
| | 40 |
| | 39 |
| | 14 |
| | 14 |
| | 14 |
| PHI | 10 |
| | 62 |
| | 67 |
| | 15 |
| | 12 |
| | 32 |
| Pepco | 2 |
| | 6 |
| | 62 |
| | 12 |
| | 11 |
| | 10 |
| DPL | 1 |
| | — |
| | — |
| | — |
| | — |
| | 2 |
| ACE | — |
| | 6 |
| | — |
| | 1 |
| | — |
| | 20 |
|
__________
| | (a) | Exelon's and Generation's pension contributions include $21 million related to the legacy CENG plans that was funded by CENG as provided in an Employee Matters Agreement (EMA) between Exelon and CENG for the year ended December 31, 2017. There were 0 pension contributions for the years ended December 31, 2019 and 2018. |
Management 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 pension obligation, and regulatory implications. The Act requires the attainment of certain funding levels to avoid benefit restrictions (such as an inability to pay lump sums or to accrue benefits prospectively), and at-risk status (which triggers higher minimum contribution requirements and participant notification). The projected contributions below reflect a funding strategy to make levelized annual contributions with the objective of achieving 100% funded status on
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 15 — Retirement Benefits an ABO basis over time. This level funding strategy helps minimize volatility of future period required pension contributions. Based on this funding strategy and current market conditions, which are subject to change, Exelon’s estimated annual qualified pension contributions will be approximately $500 million beginning in 2020.2022. Exelon's estimated contributions include contributions related to Generation's qualified pension plans. In connection with the separation, an additional qualified pension contribution of $207 million was completed on February 1, 2022. 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 other postretirementOPEB plans are also not subject to statutory minimum contribution requirements, Exelon does fund certain of its plans. For Exelon's funded OPEB plans, contributions generally equal accounting costs, however, Exelon’s management has historically considered several factors in determining the level of contributions to its OPEB plans, including liabilities management, levels of benefit claims paid, and regulatory implications (amounts deemed prudent to meet regulatory expectations and best assure continued rate recovery). The amounts below include benefit payments related to unfunded plans.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 14 — Retirement Benefits
The following table provides all registrants'Registrants' planned contributions to the qualified pension plans, planned benefit payments to non-qualified pension plans, and planned contributions to other postretirementOPEB plans in 2020:2022: | | | | | | | | | | | | |
| Qualified Pension Plans |
| Non-Qualified Pension Plans |
| OPEB | Exelon | $ | 505 |
|
| $ | 36 |
|
| $ | 42 |
| Generation | 227 |
|
| 14 |
|
| 16 |
| ComEd | 141 |
|
| 2 |
|
| 3 |
| PECO | 17 |
|
| 1 |
|
| — |
| BGE | 56 |
|
| 2 |
|
| 16 |
| PHI | 22 |
|
| 9 |
|
| 7 |
| Pepco | — |
|
| 2 |
|
| 7 |
| DPL | — |
|
| 1 |
|
| — |
| ACE | 2 |
|
| — |
|
| — |
|
| | | | | | | | | | | | | | | | | | | Qualified Pension Plans | | Non-Qualified Pension Plans | | OPEB | Exelon | $ | 505 | | | $ | 32 | | | $ | 50 | | | | | | | | ComEd | 173 | | | 2 | | | 12 | | PECO | 12 | | | 1 | | | 2 | | BGE | 48 | | | 2 | | | 16 | | PHI | 60 | | | 10 | | | 7 | | Pepco | 2 | | | 1 | | | 6 | | DPL | 1 | | | 1 | | | — | | ACE | 7 | | | — | | | — | |
Estimated Future Benefit Payments Estimated future benefit payments to participants in all of the pension plans and postretirement benefit plans atas of December 31, 20192021 were: | | | | | | | | | | Pension Benefits | | OPEB | 2020 | $ | 1,227 |
| | $ | 258 |
| 2021 | 1,252 |
| | 263 |
| 2022 | 1,295 |
| | 267 |
| 2023 | 1,310 |
| | 270 |
| 2024 | 1,324 |
| | 275 |
| 2025 through 2029 | 6,770 |
| | 1,402 |
| Total estimated future benefit payments through 2029 | $ | 13,178 |
|
| $ | 2,735 |
|
| | | | | | | | | | | | | Pension Benefits | | OPEB | 2022 | $ | 1,288 | | | $ | 253 | | 2023 | 1,298 | | | 254 | | 2024 | 1,326 | | | 255 | | 2025 | 1,330 | | | 255 | | 2026 | 1,326 | | | 258 | | 2027 through 2031 | 6,736 | | | 1,284 | | Total estimated future benefits payments through 2031 | $ | 13,304 | | | $ | 2,559 | |
Plan Assets Investment Strategy. On a regular basis, Exelon evaluates its investment strategy to ensure that plan assets will be sufficient to pay plan benefits when due. As part of this ongoing evaluation, Exelon may make changes to its targeted asset allocation and investment strategy. Exelon has developed and implemented a liability hedging investment strategy for its qualified pension plans that has reduced the volatility of its pension assets relative to its pension liabilities. Exelon is likely to continue to gradually increase the liability hedging portfolio as the funded status of its plans improves. The overall objective is to achieve attractive risk-adjusted returns that will balance the liquidity requirements of the plans’ liabilities while striving to minimize the risk of significant losses. Trust assets for Exelon’s other postretirementOPEB plans are managed in a diversified investment strategy that prioritizes maximizing liquidity and returns while minimizing asset volatility.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 15 — Retirement Benefits Actual asset returns have an impact on the costs reported for the Exelon-sponsored pension and OPEB plans. The actual asset returns across Exelon’s pension and OPEB plans for the year ended December 31, 20192021 were 18.80%7.21% and 14.40%9.54%, respectively, compared to an expected long-term return assumption of 7.00% and 6.67%6.46%, respectively. Exelon used an EROA of 7.00% and 6.69%6.44% to estimate its 20202022 pension and OPEB costs, respectively. Exelon’s pension and OPEB plan target asset allocations atas of December 31, 20192021 and 20182020 were as follows:
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 14 — Retirement Benefits
| | | December 31, 2019 | | December 31, 2018 | | December 31, 2021 | | December 31, 2020 | Asset Category | Pension Benefits | | OPEB | | Pension Benefits | | OPEB | Asset Category | Pension Benefits | | OPEB | | Pension Benefits | | OPEB | Equity securities | 33 | % | | 46 | % | | 35 | % | | 47 | % | Equity securities | 35 | % | | 44 | % | | 34 | % | | 45 | % | Fixed income securities | 44 | % | | 32 | % | | 37 | % | | 28 | % | Fixed income securities | 41 | % | | 41 | % | | 43 | % | | 39 | % | Alternative investments(a) | 23 | % | | 22 | % | | 28 | % | | 25 | % | Alternative investments(a) | 24 | % | | 15 | % | | 23 | % | | 16 | % | Total | 100 | % | | 100 | % | | 100 | % | | 100 | % | Total | 100 | % | | 100 | % | | 100 | % | | 100 | % |
__________ | | (a) | Alternative investments include private equity, hedge funds, real estate, and private credit. |
(a)Alternative investments include private equity, hedge funds, real estate, and private credit. Concentrations of Credit Risk. Exelon evaluated its pension and OPEB plans’ asset portfolios for the existence of significant concentrations of credit risk as of December 31, 2019.2021. Types of concentrations that were evaluated include, but are not limited to, investment concentrations in a single entity, type of industry, foreign country, and individual fund. As of December 31, 2019,2021, there were no significant concentrations (defined as greater than 10% of plan assets) of risk in Exelon’s pension and OPEB plan assets.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 15 — Retirement Benefits Fair Value Measurements The following tables present pension and OPEB plan assets measured and recorded at fair value in Exelon's Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy atas of December 31, 20192021 and 2018:2020: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2021 | | 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 | Pension plan assets(a) | | | | | | | | | | | | | | | | | | | | Cash equivalents | $ | 445 | | | $ | 156 | | | $ | — | | | $ | — | | | $ | 601 | | | $ | 408 | | | $ | 121 | | | $ | — | | | $ | — | | | $ | 529 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Equities(b) | 4,621 | | | — | | | 3 | | | 2,180 | | | 6,804 | | | 4,255 | | | — | | | 2 | | | 2,552 | | | 6,809 | | Fixed income: | | | | | | | | | | | | | | | | | | | | U.S. Treasury and agencies | 1,716 | | | 302 | | | — | | | — | | | 2,018 | | | 1,137 | | | 367 | | | — | | | — | | | 1,504 | | State and municipal debt | — | | | 80 | | | — | | | — | | | 80 | | | — | | | 85 | | | — | | | — | | | 85 | | Corporate debt(c) | — | | | 4,319 | | | 557 | | | — | | | 4,876 | | | — | | | 4,873 | | | 573 | | | — | | | 5,446 | | Other(b) | 74 | | | 276 | | | 20 | | | 515 | | | 885 | | | — | | | 239 | | | 21 | | | 537 | | | 797 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Fixed income subtotal | 1,790 | | | 4,977 | | | 577 | | | 515 | | | 7,859 | | | 1,137 | | | 5,564 | | | 594 | | | 537 | | | 7,832 | | Private equity | — | | | — | | | — | | | 1,924 | | | 1,924 | | | — | | | — | | | — | | | 1,632 | | | 1,632 | | Hedge funds | — | | | — | | | — | | | 1,325 | | | 1,325 | | | — | | | — | | | — | | | 1,314 | | | 1,314 | | | | | | | | | | | | | | | | | | | | | | Real estate | — | | | — | | | — | | | 1,301 | | | 1,301 | | | — | | | — | | | — | | | 1,080 | | | 1,080 | | Private credit | — | | | — | | | 223 | | | 1,033 | | | 1,256 | | | — | | | — | | | 234 | | | 1,046 | | | 1,280 | | Pension plan assets subtotal | 6,856 | | | 5,133 | | | 803 | | | 8,278 | | | 21,070 | | | 5,800 | | | 5,685 | | | 830 | | | 8,161 | | | 20,476 | | | | | | | | | | | | | | | | | | | | | | OPEB plan assets(a) | | | | | | | | | | | | | | | | | | | | Cash equivalents | 84 | | | 64 | | | — | | | — | | | 148 | | | 50 | | | 52 | | | — | | | — | | | 102 | | Equities | 605 | | | 3 | | | — | | | 506 | | | 1,114 | | | 618 | | | 2 | | | — | | | 569 | | | 1,189 | | Fixed income: | | | | | | | | | | | | | | | | | | | | U.S. Treasury and agencies | 22 | | | 68 | | | — | | | — | | | 90 | | | 16 | | | 66 | | | — | | | — | | | 82 | | State and municipal debt | — | | | 11 | | | — | | | — | | | 11 | | | — | | | 89 | | | — | | | — | | | 89 | | Corporate debt(c) | — | | | 116 | | | — | | | — | | | 116 | | | — | | | 89 | | | — | | | — | | | 89 | | Other | 348 | | | 7 | | | — | | | 212 | | | 567 | | | 285 | | | 3 | | | — | | | 179 | | | 467 | | Fixed income subtotal | 370 | | | 202 | | | — | | | 212 | | | 784 | | | 301 | | | 247 | | | — | | | 179 | | | 727 | | | | | | | | | | | | | | | | | | | | | | Hedge funds | — | | | — | | | — | | | 273 | | | 273 | | | — | | | — | | | — | | | 308 | | | 308 | | Real estate | — | | | — | | | — | | | 134 | | | 134 | | | — | | | — | | | — | | | 111 | | | 111 | | Private credit | — | | | — | | | — | | | 131 | | | 131 | | | — | | | — | | | — | | | 117 | | | 117 | | OPEB plan assets subtotal | 1,059 | | | 269 | | | — | | | 1,256 | | | 2,584 | | | 969 | | | 301 | | | — | | | 1,284 | | | 2,554 | | Total pension and OPEB plan assets(d) | $ | 7,915 | | | $ | 5,402 | | | $ | 803 | | | $ | 9,534 | | | $ | 23,654 | | | $ | 6,769 | | | $ | 5,986 | | | $ | 830 | | | $ | 9,445 | | | $ | 23,030 | |
__________ (a)See Note 18—Fair Value of Financial Assets and Liabilities for a description of levels within the fair value hierarchy. (b)Includes derivative instruments of $(3) million and $2 million for the years ended December 31, 2021 and 2020, respectively, which have total notional amounts of $5,959 million and $6,879 million as of December 31, 2021 and 2020, respectively. The notional principal amounts for these instruments provide one measure of the transaction volume 274 | | | | | | | | | | | | | | | | | | | | | December 31, 2019(a) | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total | Pension plan assets | | | | | | | | | | Cash equivalents | $ | 258 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 258 |
| Equities(b) | 3,616 |
| | — |
| | 5 |
| | 2,589 |
| | 6,210 |
| Fixed income: |
|
|
|
|
| | | |
| U.S. Treasury and agencies | 1,294 |
| | 280 |
| | — |
| | — |
| | 1,574 |
| State and municipal debt | — |
| | 56 |
| | — |
| | — |
| | 56 |
| Corporate debt | — |
| | 4,342 |
| | 245 |
| | — |
| | 4,587 |
| Other(b) | — |
| | 461 |
| | — |
| | 851 |
| | 1,312 |
| Fixed income subtotal | 1,294 |
|
| 5,139 |
|
| 245 |
| | 851 |
| | 7,529 |
| Private equity | — |
| | — |
| | — |
| | 1,391 |
| | 1,391 |
| Hedge funds | — |
| | — |
| | — |
| | 1,126 |
| | 1,126 |
| Real estate | — |
| | — |
| | — |
| | 1,030 |
| | 1,030 |
| Private credit | — |
| | — |
| | 237 |
| | 929 |
| | 1,166 |
| Pension plan assets subtotal | $ | 5,168 |
|
| $ | 5,139 |
|
| $ | 487 |
| | $ | 7,916 |
| | $ | 18,710 |
|
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 1415 — Retirement Benefits
outstanding as of the fiscal years ended and do not represent the amount of the company’s exposure to credit or market loss.
(c)Includes investments in equities sold short held in investment vehicles primarily to hedge the equity option component of its convertible debt. Pension equities sold short totaled $(75) million and $(96) million as of December 31, 2021 and 2020, respectively. OPEB equities sold short totaled $(28) million and $(42) million as of December 31, 2021 and 2020, respectively. | | | | | | | | | | | | | | | | | | | | | December 31, 2019(a) | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total | OPEB plan assets | | | | | | | | | | Cash equivalents | $ | 39 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 39 |
| Equities | 473 |
| | 3 |
| | — |
| | 719 |
| | 1,195 |
| Fixed income: |
|
|
|
|
| | | |
| U.S. Treasury and agencies | 17 |
| | 64 |
| | — |
| | — |
| | 81 |
| State and municipal debt | — |
| | 107 |
| | — |
| | — |
| | 107 |
| Corporate debt | — |
| | 49 |
| | — |
| | — |
| | 49 |
| Other | 258 |
| | 78 |
| | — |
| | 201 |
| | 537 |
| Fixed income subtotal | 275 |
|
| 298 |
|
| — |
|
| 201 |
| | 774 |
| Hedge funds | — |
| | — |
| | — |
| | 293 |
| | 293 |
| Real estate | — |
| | — |
| | — |
| | 109 |
| | 109 |
| Private credit | — |
| | — |
| | — |
| | 131 |
| | 131 |
| OPEB plan assets subtotal | $ | 787 |
|
| $ | 301 |
|
| $ | — |
| | $ | 1,453 |
|
| $ | 2,541 |
| Total pension and OPEB plan assets(c) | $ | 5,955 |
| | $ | 5,440 |
| | $ | 487 |
| | $ | 9,369 |
| | $ | 21,251 |
|
(d)Excludes net liabilities of $226 million and $132 million as of December 31, 2021 and 2020, respectively, which include certain derivative assets that have notional amounts of $214 million and $239 million as of December 31, 2021 and 2020, respectively. These items are required to reconcile to the fair value of net plan assets and consist primarily of receivables or payables related to pending securities sales and purchases, interest and dividends receivable, and repurchase agreement obligations. The repurchase agreements generally have maturities ranging from 3-6 months. | | | | | | | | | | | | | | | | | | | | | December 31, 2018(a) | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total | Pension plan assets | | | | | | | | | | Cash equivalents | $ | 350 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 350 |
| Equities(b) | 3,364 |
| | — |
| | 2 |
| | 1,980 |
| | 5,346 |
| Fixed income: |
|
| |
|
| |
|
| | | |
|
| U.S. Treasury and agencies | 996 |
| | 173 |
| | — |
| | — |
| | 1,169 |
| State and municipal debt | — |
| | 59 |
| | — |
| | — |
| | 59 |
| Corporate debt | — |
| | 3,716 |
| | 216 |
| | — |
| | 3,932 |
| Other(b) | — |
| | 329 |
| | — |
| | 613 |
| | 942 |
| Fixed income subtotal | 996 |
|
| 4,277 |
|
| 216 |
| | 613 |
| | 6,102 |
| Private equity | — |
| | — |
| | — |
| | 1,219 |
| | 1,219 |
| Hedge funds | — |
| | — |
| | — |
| | 1,608 |
| | 1,608 |
| Real estate | — |
| | — |
| | — |
| | 1,029 |
| | 1,029 |
| Private credit | — |
| | — |
| | 268 |
| | 798 |
| | 1,066 |
| Pension plan assets subtotal | $ | 4,710 |
|
| $ | 4,277 |
|
| $ | 486 |
| | $ | 7,247 |
|
| $ | 16,720 |
|
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 14 — Retirement Benefits
| | | | | | | | | | | | | | | | | | | | | December 31, 2018(a) | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total | OPEB plan assets | | | | | | | | | | Cash equivalents | $ | 22 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 22 |
| Equities | 537 |
| | 2 |
| | — |
| | 508 |
| | 1,047 |
| Fixed income: |
|
|
|
|
| | | |
| U.S. Treasury and agencies | 11 |
| | 56 |
| | — |
| | — |
| | 67 |
| State and municipal debt | — |
| | 126 |
| | — |
| | — |
| | 126 |
| Corporate debt | — |
| | 48 |
| | — |
| | — |
| | 48 |
| Other | 183 |
| | 72 |
| | — |
| | 170 |
| | 425 |
| Fixed income subtotal | 194 |
|
| 302 |
|
| — |
| | 170 |
| | 666 |
| Hedge funds | — |
| | — |
| | — |
| | 411 |
| | 411 |
| Real estate | — |
| | — |
| | — |
| | 132 |
| | 132 |
| Private credit | — |
| | — |
| | — |
| | 132 |
| | 132 |
| OPEB plan assets subtotal | $ | 753 |
|
| $ | 304 |
|
| $ | — |
| | $ | 1,353 |
| | $ | 2,410 |
| Total pension and OPEB plan assets(c) | $ | 5,463 |
| | $ | 4,581 |
| | $ | 486 |
| | $ | 8,600 |
| | $ | 19,130 |
|
__________
| | (a) | See Note 17—Fair Value of Financial Assets and Liabilities for a description of levels within the fair value hierarchy. |
| | (b) | Includes derivative instruments of $2 million and less than $1 million, which have a total notional amount of $6,668 million and $5,991 million at December 31, 2019 and 2018, respectively. The notional principal amounts for these instruments provide one measure of the transaction volume outstanding as of the fiscal years ended and do not represent the amount of the company’s exposure to credit or market loss. |
| | (c) | Excludes net liabilities of $120 million and $44 million at December 31, 2019 and 2018, respectively, which are required to reconcile to the fair value of net plan assets. These items consist primarily of receivables or payables related to pending securities sales and purchases, interest and dividends receivable. |
The following table presents the reconciliation of Level 3 assets and liabilities for Exelon measured at fair value for pension and OPEB plans for the years ended December 31, 20192021 and 2018:2020: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Fixed Income | | Equities | | Private Credit | | Total | Pension Assets | | | | | | | | | | | | | | Balance as of January 1, 2021 | | | | | | | $ | 594 | | | $ | 2 | | | $ | 234 | | | $ | 830 | | Actual return on plan assets: | | | | | | | | | | | | | | Relating to assets still held as of the reporting date | | | | | | | (21) | | | — | | | 31 | | | 10 | | | | | | | | | | | | | | | | Purchases, sales and settlements: | | | | | | | | | | | | | | Purchases | | | | | | | 17 | | | — | | | 9 | | | 26 | | | | | | | | | | | | | | | | Settlements(a) | | | | | | | (20) | | | — | | | (51) | | | (71) | | Transfers into Level 3 | | | | | | | 7 | | | 1 | | | — | | | 8 | | Balance as of December 31, 2021 | | | | | | | $ | 577 | | | $ | 3 | | | $ | 223 | | | $ | 803 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | Fixed Income | | Equities | | Private Credit | | Total | Pension Assets | | | | | | | | Balance as of January 1, 2019 | $ | 216 |
|
| $ | 2 |
| | $ | 268 |
| | $ | 486 |
| Actual return on plan assets: |
|
|
| | | |
|
| Relating to assets still held at the reporting date | 28 |
|
| 3 |
| | 28 |
| | 59 |
| Relating to assets sold during the period | (7 | ) |
| — |
| | — |
| | (7 | ) | Purchases, sales and settlements: |
|
|
| | | |
|
| Purchases | 26 |
|
| — |
| | 41 |
| | 67 |
| Sales | (4 | ) |
| — |
| | — |
| | (4 | ) | Settlements(a) | (2 | ) |
| — |
| | (100 | ) | | (102 | ) | Transfers out of Level 3 | (12 | ) |
| — |
| | — |
| | (12 | ) | Balance as of December 31, 2019 | $ | 245 |
|
| $ | 5 |
| | $ | 237 |
| | $ | 487 |
|
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 14 — Retirement Benefits
| | | | | Fixed Income | | Equities | | Private Credit | | Total | Pension Assets | | Pension Assets | | | | | | | | | Balance as of January 1, 2020 | | Balance as of January 1, 2020 | | $ | 245 | | | $ | 5 | | | $ | 237 | | | $ | 487 | | Actual return on plan assets: | | Actual return on plan assets: | | | Relating to assets still held as of the reporting date | | Relating to assets still held as of the reporting date | | 19 | | | (3) | | | 15 | | | 31 | | | Purchases, sales and settlements: | | Purchases, sales and settlements: | | | Purchases | | Purchases | | 34 | | | — | | | 24 | | | 58 | | | Settlements(a) | | Settlements(a) | | (3) | | | — | | | (42) | | | (45) | | Transfers into Level 3(b) | | Transfers into Level 3(b) | | 299 | | | — | | | — | | | 299 | | Balance as of December 31, 2020 | | Balance as of December 31, 2020 | | $ | 594 | | | $ | 2 | | | $ | 234 | | | $ | 830 | | | | | Fixed income | | Equities | | Private Credit | | Total | | Pension Assets | | | | | | | | | Balance as of January 1, 2018 | $ | 232 |
|
| $ | 2 |
| | $ | 224 |
| | $ | 458 |
| | Actual return on plan assets: |
|
|
| | | |
|
| | Relating to assets still held at the reporting date | (14 | ) |
| — |
| | 9 |
| | (5 | ) | | Relating to assets sold during the period | (1 | ) |
| — |
| | — |
| | (1 | ) | | Purchases, sales and settlements: |
|
|
| | | |
|
| | Purchases | 19 |
|
| — |
| | 35 |
| | 54 |
| | Sales | (8 | ) |
| — |
| | — |
| | (8 | ) | | Settlements(a) | (12 | ) |
| — |
| | — |
| | (12 | ) | | Balance as of December 31, 2018 | $ | 216 |
|
| $ | 2 |
|
| $ | 268 |
| | $ | 486 |
| | |
__________ | | (a) | Represents cash settlements only. |
There were 0 significant transfers between(a)Represents cash settlements only.
(b)In 2020, a contract was terminated for a certain fixed income commingled fund resulting in the ownership of certain fixed income securities which led to a transfer into Level 1 and Level 2 during the year ended December 31, 2019 for the pension and OPEB plan assets.3 from not subject to leveling of $299 million. Valuation Techniques Used to Determine Fair Value The techniques used to fair value the pension and OPEB assets invested in cash equivalents, equities, fixed income, derivatives, private equity, real estate, and private credit investments are the same as the valuation techniques for these types of investments in NDTFs.NDT funds. See Cash Equivalents and NDT Fund Investments in Note 1718 - Fair Value of Financial Assets and Liabilities for further information. Pension and OPEB assets also include investments in hedge funds. Hedge fund investments include those seeking to maximize absolute returns usingthat employ a broad range of strategies to enhance returns and provide additional diversification. The fair value of hedge funds is determined using NAV or its equivalent as a practical expedient, and therefore, hedge funds are not classified within the fair value hierarchy. Exelon has the ability to redeem these investments at NAV or its equivalent subject to certain restrictions which may include a lock-up period or a gate.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 15 — Retirement Benefits Defined Contribution Savings Plan (All Registrants) The Registrants participate in various 401(k) defined contribution savings plans that are sponsored by Exelon. The plans are 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 matching contributions to the savings plan for the years ended December 31, 2019, 20182021, 2020, and 2017:2019: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | Exelon | | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | 2021 | $ | 143 | | | | | $ | 35 | | | $ | 12 | | | $ | 12 | | | 14 | | | $ | 4 | | | $ | 3 | | | $ | 2 | | 2020 | 158 | | | | | 36 | | | 12 | | | 13 | | | 14 | | | 4 | | | 3 | | | 3 | | 2019 | 161 | | | | | 35 | | | 11 | | | 12 | | | 13 | | | 3 | | | 3 | | | 2 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | For the Year Ended December 31, | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | 2019 | $ | 161 |
| | $ | 73 |
|
| $ | 35 |
|
| $ | 11 |
|
| $ | 12 |
|
| 13 |
| | $ | 3 |
| | $ | 3 |
| | $ | 2 |
| 2018 | 179 |
| | 86 |
|
| 37 |
|
| 9 |
|
| 12 |
|
| 13 |
| | 3 |
| | 2 |
| | 2 |
| 2017 | 128 |
| | 55 |
|
| 31 |
|
| 10 |
|
| 10 |
|
| 13 |
| | 3 |
| | 2 |
| | 2 |
|
15.16. 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
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 15 — Derivative Financial Instruments
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. AllGeneration's and ComEd's derivative economic hedges related to commodities, referred to as economic hedges, are recorded at fair value through earnings at GenerationExelon for Generation's economic hedges and for ComEd's economic hedges 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 derivative settlesderivatives settle and revenue or expense is recognized in earnings as the underlying physical commodity is sold or consumed. 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 referencingreferenced 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, thatwhich 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 are 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 the 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 areis 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
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 16 — Derivative Financial Instruments 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.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 15 — Derivative Financial Instruments
Utility Registrants. 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 gas price volatility and have no direct earnings impact as the costs are fully recovered from customers through regulatory-approved recovery 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 instrumentInstrument | 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(b) | GasElectricity | NPNS | Fixed price contracts for default supply requirements through full requirements contracts. | | Gas | NPNS | Fixed price contracts to cover about 20%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 priceand index priced contracts through full requirements contracts. | Changes in fair value of economic hedge recorded to an offsetting regulatory asset or liability(c)(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 for additional information.
| | (a) | See Note 3 - Regulatory Matters for additional information. |
| | (b) | As part of its hedging program, PECO enters into electric supply procurement contracts that do not meet the definition of a derivative instrument. |
| | (c) | The fair value of the DPL economic hedge is not material as of December 31, 2019 and 2018 and is not presented in the fair value tables below. |
(b)The fair value of the DPL economic hedge is not material as of December 31, 2021 and 2020 and is not presented in the fair value tables below.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 1516 — Derivative Financial Instruments
The following table providestables provide a summary of the derivative fair value balances recorded by Exelon Generation and ComEd as of December 31, 20192021 and 2018:2020: | | | | | | | | | | | | | | | | | | | Exelon | | ComEd | | | Exelon | | Generation | | ComEd | | December 31, 2019 | Total Derivatives | | Economic Hedges | | Proprietary Trading | | Collateral
(a)(b) | | Netting(a) | | Subtotal | | Economic Hedges | | December 31, 2021 | | December 31, 2021 | | Economic Hedges | | Proprietary Trading | | Collateral (a)(b) | | Netting(a) | | Total | | Economic Hedges | | Mark-to-market derivative assets (current assets) | $ | 675 |
| | $ | 3,506 |
| | $ | 72 |
| | $ | 287 |
| | $ | (3,190 | ) | | $ | 675 |
| | $ | — |
| Mark-to-market derivative assets (current assets) | | $ | 10,915 | | | $ | 25 | | | $ | 152 | | | $ | (8,923) | | | $ | 2,169 | | | $ | — | | | Mark-to-market derivative assets (noncurrent assets) | 508 |
| | 1,238 |
| | 25 |
| | 122 |
| | (877 | ) | | 508 |
| | — |
| Mark-to-market derivative assets (noncurrent assets) | | 3,224 | | | 2 | | | 15 | | | (2,298) | | | 943 | | | — | | | Total mark-to-market derivative assets | 1,183 |
| | 4,744 |
|
| 97 |
|
| 409 |
| | (4,067 | ) | | 1,183 |
| | — |
| Total mark-to-market derivative assets | | 14,139 | | | 27 | | | 167 | | | (11,221) | | | 3,112 | | | — | | | Mark-to-market derivative liabilities (current liabilities) | (236 | ) | | (3,713 | ) | | (38 | ) | | 357 |
| | 3,190 |
| | (204 | ) | | (32 | ) | Mark-to-market derivative liabilities (current liabilities) | | (10,161) | | | (19) | | | 262 | | | 8,923 | | | (995) | | | (18) | | | Mark-to-market derivative liabilities (noncurrent liabilities) | (380 | ) | | (1,140 | ) | | (11 | ) | | 163 |
| | 877 |
| | (111 | ) | | (269 | ) | Mark-to-market derivative liabilities (noncurrent liabilities) | | (3,094) | | | (1) | | | 83 | | | 2,298 | | | (714) | | | (201) | | | Total mark-to-market derivative liabilities | (616 | ) | | (4,853 | ) |
| (49 | ) |
| 520 |
| | 4,067 |
| | (315 | ) | | (301 | ) | Total mark-to-market derivative liabilities | | (13,255) | | | (20) | | | 345 | | | 11,221 | | | (1,709) | | | (219) | | | Total mark-to-market derivative net assets (liabilities) | $ | 567 |
| | $ | (109 | ) |
| $ | 48 |
|
| $ | 929 |
| | $ | — |
| | $ | 868 |
| | $ | (301 | ) | Total mark-to-market derivative net assets (liabilities) | | $ | 884 | | | $ | 7 | | | $ | 512 | | | $ | — | | | $ | 1,403 | | | $ | (219) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2018 | | | | | | | | | | | | | | | December 31, 2020 | | December 31, 2020 | | | | Mark-to-market derivative assets (current assets) | $ | 801 |
| | $ | 3,505 |
| | $ | 105 |
| | $ | 121 |
| | $ | (2,930 | ) | | $ | 801 |
| | $ | — |
| Mark-to-market derivative assets (current assets) | | $ | 2,757 | | | $ | 40 | | | $ | 103 | | | $ | (2,261) | | | $ | 639 | | | $ | — | | | Mark-to-market derivative assets (noncurrent assets) | 445 |
| | 1,266 |
| | 41 |
| | 51 |
| | (913 | ) | | 445 |
| | — |
| Mark-to-market derivative assets (noncurrent assets) | | 1,501 | | | 4 | | | 64 | | | (1,015) | | | 554 | | | — | | | Total mark-to-market derivative assets | 1,246 |
| | 4,771 |
| | 146 |
| | 172 |
| | (3,843 | ) | | 1,246 |
| | — |
| Total mark-to-market derivative assets | | 4,258 | | | 44 | | | 167 | | | (3,276) | | | 1,193 | | | — | | | Mark-to-market derivative liabilities (current liabilities) | (473 | ) | | (3,429 | ) | | (74 | ) | | 125 |
| | 2,931 |
| | (447 | ) | | (26 | ) | Mark-to-market derivative liabilities (current liabilities) | | (2,662) | | | (23) | | | 131 | | | 2,261 | | | (293) | | | (33) | | | Mark-to-market derivative liabilities (noncurrent liabilities) | (474 | ) | | (1,203 | ) | | (20 | ) | | 60 |
| | 912 |
| | (251 | ) | | (223 | ) | Mark-to-market derivative liabilities (noncurrent liabilities) | | (1,603) | | | (2) | | | 118 | | | 1,015 | | | (472) | | | (268) | | | Total mark-to-market derivative liabilities | (947 | ) | | (4,632 | ) | | (94 | ) | | 185 |
| | 3,843 |
| | (698 | ) | | (249 | ) | Total mark-to-market derivative liabilities | | (4,265) | | | (25) | | | 249 | | | 3,276 | | | (765) | | | (301) | | | Total mark-to-market derivative net assets (liabilities) | $ | 299 |
| | $ | 139 |
| | $ | 52 |
| | $ | 357 |
| | $ | — |
| | $ | 548 |
| | $ | (249 | ) | Total mark-to-market derivative net assets (liabilities) | | $ | (7) | | | $ | 19 | | | $ | 416 | | | $ | — | | | $ | 428 | | | $ | (301) | | |
_________ | | (a) | Exelon and Generation net all available amounts allowed under the derivative authoritative guidance in the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases Exelon 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. These amounts are immaterial and not reflected in the table above. |
| | (b) | Of the collateral posted/(received), $511 million and $(94) million represents variation margin on the exchanges at December 31, 2019 and 2018, respectively. |
(a)Exelon nets all available amounts allowed under the derivative authoritative guidance in the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases, Exelon 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. These amounts are not material as of December 31, 2021 and 2020 and not reflected in the table above.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 15 — Derivative Financial Instruments
Economic Hedges (Commodity Price Risk) Generation. For the years ended December 31, 2021, 2020, and 2019, 2018 and 2017, 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. | | | | | | | | | | | | | | | | | | | | | | | Gain (Loss) | Income Statement Location | | 2021 | | 2020 | | 2019 | | | | Operating revenues | | $ | (635) | | | $ | 112 | | | $ | — | | Purchased power and fuel | | 1,206 | | | 168 | | | (204) | | Total | | $ | 571 | | | $ | 280 | | | $ | (204) | |
| | | | | | | | | | | | | |
| | 2019 | | 2018 | | 2017 | Income Statement Location | | Gain (Loss) | Operating revenues | | $ | — |
| | $ | (270 | ) | | $ | (126 | ) | Purchased power and fuel | | (204 | ) | | (47 | ) | | (43 | ) | Total Exelon and Generation | | $ | (204 | ) | | $ | (317 | ) | | $ | (169 | ) |
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 16 — Derivative Financial Instruments 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 riskFor merchant revenues not already hedged via comprehensive state programs, such as the CMC in Illinois, we utilize a three-year ratable sales plan to align our hedging strategy with our financial objectives. The prompt three-year merchant revenues are hedged on aan approximate rolling 90%/60%/30% basis. We may also enter into transactions that are outside of this ratable basis over three-year periods. As of December 31, 2019, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York and ERCOT reportable segments is 91%-94% and 61%-64% for 2020 and 2021, respectively.hedging program. 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 years ended December 31, 2019, 20182021, 2020, and 2017,2019, net pre-tax commodity mark-to-market gains (losses)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)(Exelon) Exelon and Generation utilizeutilizes interest rate swaps which are treated as economic hedges, to manage theirits interest rate exposure. On July 1, 2018, Exelon de-designated its fair value hedges related to interest rate riskexposure and Generation de-designated its cash flow hedges related to interest rate risk. The notional amounts were $1,269 million and $1,420 million at December 31, 2019 and 2018, respectively, for Exelon and $569 million and $620 million at December 31, 2019 and 2018, respectively, for Generation.
Generation utilizes 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 $231$486 million and $268$665 million atfor Exelon as of December 31, 20192021 and 2018,2020, respectively.
The mark-to-market derivative assets and liabilities as of December 31, 20192021 and 20182020 and the mark-to-market gains (losses)and losses for the years ended December 31, 2019, 20182021, 2020, and 20172019 were not material for Exelon and Generation.Exelon. 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
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 15 — Derivative Financial Instruments
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. 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 December 31, 2019.2021. 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 figuresamounts 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.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 16 — Derivative Financial Instruments | | Rating as of December 31, 2019 | 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 | | Rating as of December 31, 2021 | | Rating as of December 31, 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 | $ | 877 |
|
| $ | 20 |
| | $ | 857 |
| | — |
| | $ | — |
| Investment grade | $ | 715 | | | $ | 176 | | | $ | 539 | | | 1 | | | $ | 106 | | Non-investment grade | 79 |
|
| 63 |
| | 16 |
| | | | | Non-investment grade | 13 | | | — | | | 13 | | | — | | | — | | No external ratings |
|
|
| |
| | | | | No external ratings | | Internally rated — investment grade | 218 |
|
| — |
| | 218 |
| | | | | Internally rated — investment grade | 111 | | | — | | | 111 | | | — | | | — | | Internally rated — non-investment grade | 139 |
|
| 23 |
| | 116 |
| | | | | Internally rated — non-investment grade | 226 | | | 47 | | | 179 | | | — | | | — | | Total | $ | 1,313 |
|
| $ | 106 |
| | $ | 1,207 |
| | — |
| | $ | — |
| Total | $ | 1,065 | | | $ | 223 | | | $ | 842 | | | 1 | | | $ | 106 | |
| | | | | Net Credit Exposure by Type of Counterparty | As of December 31, 2019 | Financial institutions | $ | 9 |
| Investor-owned utilities, marketers, power producers | 930 |
| Energy cooperatives and municipalities | 235 |
| Other | 33 |
| Total | $ | 1,207 |
|
__________
| | | | | | (a)Net Credit Exposure by Type of Counterparty | As of December 31, 2019, credit collateral held from counterparties where Generation had credit exposure included $25 million of cash2021 | Financial institutions | $ | 32 | | Investor-owned utilities, marketers, power producers | 711 | | Energy cooperatives and $81 million of letters of credit. The credit collateral does not include non-liquid collateral.municipalities | 62 | | Other | 37 | | Total | $ | 842 | |
__________ (a)As of December 31, 2021, credit collateral held from counterparties where Generation had credit exposure included $163 million of cash and $60 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 December 31, 2019,2021, the amount of cash collateral held with external counterparties by ComEd and DPL was $41 million and $43 million, respectively, which is recorded in Other current liabilities in ComEd’s and DPL’s Consolidated Balance Sheets. The amounts for PECO, BGE, Pepco, and ACE as of December 31, 2021 and for the Utility Registrants’ counterparty credit risk with suppliers was immaterial.Registrants as of December 31, 2020 are not material. 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, where the contractual right of offset exists under applicable master netting agreements. In the absence of expressly agreed-to provisions that specify
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 15 — Derivative Financial Instruments
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:
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 16 — Derivative Financial Instruments | | | | As of December 31, | | As of December 31, | Credit-Risk Related Contingent Features | | 2019 | | 2018 | Credit-Risk Related Contingent Features | | 2021 | | 2020 | Gross fair value of derivative contracts containing this feature(a) | | $ | (956 | ) | | $ | (1,723 | ) | Gross fair value of derivative contracts containing this feature(a) | | $ | (3,872) | | | $ | (834) | | Offsetting fair value of in-the-money contracts under master netting arrangements(b) | | 649 |
| | 1,105 |
| Offsetting fair value of in-the-money contracts under master netting arrangements(b) | | 2,424 | | | 537 | | Net fair value of derivative contracts containing this feature(c) | | $ | (307 | ) | | $ | (618 | ) | Net fair value of derivative contracts containing this feature(c) | | $ | (1,448) | | | $ | (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 a Registrant 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. |
(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. As of December 31, 20192021 and 2018, Exelon and2020, Generation posted or held the following amounts 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. | | | | | | | | | | | | As of December 31, | | | 2019 | | 2018 | Cash collateral posted | | $ | 982 |
| | $ | 418 |
| Letters of credit posted | | 264 |
| | 367 |
| Cash collateral held | | 103 |
| | 47 |
| Letters of credit held | | 112 |
| | 44 |
| Additional collateral required in the event of a credit downgrade below investment grade | | 1,509 |
| | 2,104 |
|
| | | | | | | | | | | | | | | | | As of December 31, | | | 2021 | | 2020 | Cash collateral posted | | $ | 713 | | | $ | 511 | | Letters of credit posted | | 755 | | | 226 | | Cash collateral held | | 182 | | | 110 | | Letters of credit held | | 124 | | | 40 | | Additional collateral required in the event of a credit downgrade below investment grade | | 2,113 | | | 1,432 | |
Generation entered into supply forward contracts with certain utilities, including PECO and BGE,the Utility Registrants, 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 Registrants 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,BGE's, and DPL’s credit rating. As of December 31, 2019,2021, 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 December 31, 2019,2021, they could have been required to post incremental collateral to itstheir counterparties of $44$37 million, $50$78 million, and $11$14 million, respectively.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 16 — Debt and Credit Agreements
16.17. 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 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. PHIPHI 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
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 17 — Debt and Credit Agreements 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 supported by the revolving credit agreements and bilateral credit agreements atas of December 31, 20192021 and 2018:2020: | | | Maximum Program Size at December 31, | | Outstanding Commercial Paper at December 31, | | Average Interest Rate on Commercial Paper Borrowings for the Year Ended December 31, | | Maximum Program Size at December 31, | | Outstanding Commercial Paper at December 31, | | Average Interest Rate on Commercial Paper Borrowings at December 31, | Commercial Paper Issuer | 2019(a)(b)(c) | | 2018(a)(b)(c) | | 2019 | | 2018 | | 2019 | | 2018 | Commercial Paper Issuer | 2021(a)(b)(c) | | 2020(a)(b)(c) | | 2021 | | 2020 | | 2021 | | 2020 | Exelon(d) | $ | 9,000 |
| | $ | 9,000 |
| | $ | 870 |
| | $ | 89 |
| | 2.25 | % | | 2.15 | % | Exelon(d) | $ | 9,000 | | | $ | 9,000 | | | $ | 1,301 | | | $ | 1,031 | | | 0.52 | % | | 0.25 | % | Generation | 5,300 |
| | 5,300 |
| | 320 |
| | — |
| | 1.84 | % | | 1.96 | % | | | ComEd | 1,000 |
| | 1,000 |
| | 130 |
| | — |
| | 2.38 | % | | 2.14 | % | ComEd | 1,000 | | | 1,000 | | | — | | | 323 | | | — | % | | 0.23 | % | PECO | 600 |
| | 600 |
| | — |
| | — |
| | 2.39 | % | | 2.24 | % | PECO | 600 | | | 600 | | | — | | | — | | | — | % | | — | % | BGE | 600 |
| | 600 |
| | 76 |
| | 35 |
| | 2.46 | % | | 2.18 | % | BGE | 600 | | | 600 | | | 130 | | | — | | | 0.37 | % | | — | % | PHI | 900 |
| | 900 |
| | 208 |
| | 54 |
| | N/A |
| | N/A |
| | PHI(e) | | PHI(e) | 900 | | | 900 | | | 469 | | | 368 | | | 0.35 | % | | 0.24 | % | Pepco | 300 |
| | 300 |
| | 82 |
| | 40 |
| | 2.56 | % | | 2.24 | % | Pepco | 300 | | | 300 | | | 175 | | | 35 | | | 0.33 | % | | 0.22 | % | DPL | 300 |
| | 300 |
| | 56 |
| | — |
| | 2.02 | % | | 2.07 | % | DPL | 300 | | | 300 | | | 149 | | | 146 | | | 0.36 | % | | 0.24 | % | ACE | 300 |
| | 300 |
| | 70 |
| | 14 |
| | 2.43 | % | | 2.21 | % | ACE | 300 | | | 300 | | | 145 | | | 187 | | | 0.35 | % | | 0.25 | % |
__________ | | (a) | Excludes $1,400(a)Excludes $1,200 million and $1,500 million in bilateral credit facilities as of December 31, 2021 and 2020, respectively, and $131 million and $144 million in credit facilities for project finance as of December 31, 2021 and 2020, respectively. These credit facilities do not back the commercial paper program relating to Generation. (b)As of December 31, 2021, excludes $142 million of credit facility agreements arranged at minority and community banks, including $33 million, $33 million, $8 million, $8 million, $8 million, and $8 million, at ComEd, PECO, BGE, Pepco, DPL, and ACE, respectively. These facilities expire on October 7, 2022. These facilities are solely utilized to issue letters of credit. As of December 31, 2020, excludes $135 million of credit facility agreements arranged primarily at minority and community banks, including $32 million, $33 million, $8 million, $8 million, $8 million, and $8 million, at ComEd, PECO, BGE, Pepco, DPL, and ACE, respectively. (c)Pepco, DPL, and ACE's revolving credit facility has the ability to flex to $500 million, and $545 million in bilateral credit facilities at December 31, 2019 and 2018, respectively, and $159 million in credit facilities for project finance at December 31, 2019 and 2018, respectively. These credit facilities do not back Generation's commercial paper program. |
| | (b) | At December 31, 2019, excludes $142 million of credit facility agreements arranged at minority and community banks at Generation, ComEd, PECO, BGE, Pepco, DPL and ACE with aggregate commitments of $44 million, $33 million, $33 million, $8 million, $8 million, $8 million and $8 million, respectively. These facilities expire on October 9, 2020. These facilities are solely utilized to issue letters of credit. At December 31, 2018, excludes $135 million of credit facility agreements arranged at minority and community banks at Generation, ComEd, PECO, BGE, Pepco, DPL and ACE with aggregate commitments of $49 million, $33 million, $34 million, $5 million, $5 million, $5 million, and $5 million, respectively. |
| | (c) | Pepco, DPL and ACE's revolving credit facility has the ability to flex to $500 million, $500 million, and $350 million, respectively. The borrowing capacity may be increased or decreased during the term of the facility, except that (i) the sum of the borrowing capacity must equal the total amount of the facility, and (ii) the aggregate amount of credit used at any given time by each of Pepco, DPL, or ACE may not exceed $900 million or the maximum amount of short-term debt the company is permitted to have outstanding by its regulatory authorities. The total number of the borrowing reallocations may not exceed eight per year during the term of the facility.
(d)Includes revolving credit agreement at Exelon Corporate with a maximum program size of $600 million as of December 31, 2021 and 2020. Exelon Corporate had no outstanding commercial paper as of December 31, 2021 and 2020. (e)Represents the consolidated amounts of Pepco, DPL, and ACE. |
| | (d) | Includes revolving credit agreement at Exelon Corporate with a maximum program size of $600 million at both December 31, 2019 and 2018, respectively. Exelon Corporate had $136 million of outstanding commercial paper at December 31, 2019 and no outstanding commercial paper at the end of 2018. |
In order to maintain their respective commercial paper programs in the amounts indicated above, each Registrant must have credit facilities in place, at least equal to the amount of its commercial paper program. A registrant does not issue commercial paper in an aggregate amount exceeding the then available capacity under its credit facility.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 1617 — Debt and Credit Agreements
AtAs of December 31, 2019,2021, the Registrants had the following aggregate bank commitments, credit facility borrowings, and available capacity under their respective credit facilities:
| | | | Available Capacity as of December 31, 2021 | Borrower(a) | | Borrower(a) | Facility Type | | Aggregate Bank Commitment(b) | | Facility Draws | | Outstanding Letters of Credit | | Actual | | To Support Additional Commercial Paper(c) | Exelon(c) | | Exelon(c) | Syndicated Revolver / Bilaterals / Project Finance | | $ | 10,331 | | | $ | — | | | $ | 2,383 | | | $ | 7,948 | | | $ | 6,461 | | | | | | | | | | | | Available Capacity at December 31, 2019 | | Borrower | Facility Type | | Aggregate Bank Commitment(a) | | Facility Draws | | Outstanding Letters of Credit | | Actual | | To Support Additional Commercial Paper(b) | | Exelon(b) | Syndicated Revolver / Bilaterals / Project Finance | | $ | 10,559 |
| | $ | — |
| | $ | 1,443 |
| | $ | 9,116 |
| | $ | 7,353 |
| | Generation | Syndicated Revolver | | 5,300 |
| | — |
| | 769 |
| | 4,531 |
| | 4,211 |
| | Generation | Bilaterals | | 1,400 |
| | — |
| | 545 |
| | 855 |
| | — |
| | Generation | Project Finance | | 159 |
| | — |
| | 120 |
| | 39 |
| | — |
| | ComEd | Syndicated Revolver | | 1,000 |
| | — |
| | 2 |
| | 998 |
| | 868 |
| ComEd | Syndicated Revolver | | 1,000 | | | — | | | 2 | | | 998 | | | 998 | | PECO | Syndicated Revolver | | 600 |
| | — |
| | — |
| | 600 |
| | 600 |
| PECO | Syndicated Revolver | | 600 | | | — | | | — | | | 600 | | | 600 | | BGE | Syndicated Revolver | | 600 |
| | — |
| | — |
| | 600 |
| | 524 |
| BGE | Syndicated Revolver | | 600 | | | — | | | — | | | 600 | | | 470 | | PHI | Syndicated Revolver | | 900 |
| | — |
| | — |
| | 900 |
| | 692 |
| PHI | Syndicated Revolver | | 900 | | | — | | | — | | | 900 | | | 431 | | Pepco | Syndicated Revolver | | 300 |
| | — |
| | — |
| | 300 |
| | 218 |
| Pepco | Syndicated Revolver | | 300 | | | — | | | — | | | 300 | | | 125 | | DPL | Syndicated Revolver | | 300 |
| | — |
| | — |
| | 300 |
| | 244 |
| DPL | Syndicated Revolver | | 300 | | | — | | | — | | | 300 | | | 151 | | ACE | Syndicated Revolver | | 300 |
| | — |
| | — |
| | 300 |
| | 230 |
| ACE | Syndicated Revolver | | 300 | | | — | | | — | | | 300 | | | 155 | |
__________ (a)On February 1, 2022, Exelon Corporate and the Utility Registrants' respective syndicated revolving credit facilities were replaced with a new 5-year revolving credit facility. (b)As of December 31, 2021, excludes $142 million of credit facility agreements arranged at minority and community banks, including $33 million, $33 million, $8 million, $8 million, $8 million, and $8 million, at ComEd, PECO, BGE, Pepco, DPL, and ACE, respectively. These facilities expire on October 7, 2022. These facilities are solely utilized to issue letters of credit. As of December 31, 2021, letters of credit issued under these facilities totaled $5 million, $1 million, and $2 million for ComEd, PECO, and BGE, respectively. (c)Includes $600 million aggregate bank commitment related to Exelon Corporate. Exelon Corporate had $6 million outstanding letters of credit as of December 31, 2021. Exelon Corporate had $594 million in available capacity to support additional commercial paper as of December 31, 2021. 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: | | | | | | | | | | | | | | | (a)Borrower | Excludes $142 million of credit facility agreements arranged at minority and community banks at Generation, ComEd, PECO, BGE, Pepco, DPL and ACE with aggregate commitments of $44 million, $33 million, $33 million, $8 million, $8 million, $8 million and $8 million, respectively. These facilities expire on October 9, 2020. These facilities are solely utilized to issue letters of credit. As of December 31, 2019, letters of credit issued under these facilities totaled $5 million, $5 million, $2 million for Generation, ComEd, and BGE, respectively. | Aggregate Bank Commitment | | Interest Rate |
Exelon Corporate | | $ | 900 | | | SOFR plus 1.275 | % | (b)ComEd | Includes $600 million aggregate bank commitment related to Exelon Corporate. Exelon Corporate had $6 million and $9 million outstanding letters of credit at December 31, 2019 and 2018, respectively. Exelon Corporate had $458 million in available capacity to support additional commercial paper at December 31, 2019. | 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 | % |
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 1617 — Debt and Credit Agreements
The following tables present the short-term borrowings activity for Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE during 2019 and 2018.
| | | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2019 | Exelon(a) | Generation | ComEd | PECO | BGE | PHI | Pepco | DPL | ACE | Average borrowings | $ | 472 |
| $ | 13 |
| $ | 236 |
| $ | — |
| $ | 103 |
| N/A | $ | 45 |
| $ | 21 |
| $ | 51 |
| Maximum borrowings outstanding | 890 |
| 357 |
| 465 |
| 21 |
| 298 |
| N/A | 144 |
| 125 |
| 180 |
| Average interest rates, computed on a daily basis | 2.25 | % | 1.84 | % | 2.38 | % | 2.39 | % | 2.46 | % | N/A | 2.56 | % | 2.02 | % | 2.43 | % | Average interest rates, at December 31 | 2.25 | % | 1.84 | % | 2.38 | % | 2.39 | % | 2.46 | % | N/A | 2.56 | % | 2.02 | % | 2.43 | % | | | | | | | | | | | December 31, 2018 | Exelon(a) | Generation | ComEd | PECO | BGE | PHI | Pepco | DPL | ACE | Average borrowings | $ | 531 |
| $ | 37 |
| $ | 154 |
| $ | 68 |
| $ | 65 |
| N/A | $ | 22 |
| $ | 87 |
| $ | 95 |
| Maximum borrowings outstanding | 1,237 |
| 583 |
| 520 |
| 350 |
| 239 |
| N/A | 90 |
| 245 |
| 210 |
| Average interest rates, computed on a daily basis | 2.21 | % | 1.96 | % | 2.14 | % | 2.24 | % | 2.18 | % | N/A | 2.24 | % | 2.07 | % | 2.21 | % | Average interest rates, at December 31 | 2.15 | % | 1.96 | % | 2.14 | % | 2.24 | % | 2.18 | % | N/A | 2.24 | % | 2.07 | % | 2.21 | % |
__________
| | (a) | Includes $3 million and $4 million average borrowings related to Exelon Corporate at December 31, 2019 and 2018, respectively. Exelon Corporate had $144 million and $95 million maximum borrowings outstanding at December 31, 2019 and 2018, with 1.92% and 1.93% average interest rates computed on a daily basis for 2019 and 2018, and 1.92% and 1.93% average interest rates at December 31, 2019 and 2018, respectively.
|
Short-Term Loan Agreements
On March 23, 2017, Exelon Corporate entered into a term loan agreement for $500 million, which was renewed on March 22, 2018 with an expiration of March 21, 2019. The loan agreement was renewed on March 20, 2019 and will expire on March 19, 2020. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.95% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Exelon's Consolidated Balance Sheet within Short-Term borrowings.
Revolving Credit Agreements
On May 26, 2016, Exelon Corporate, Generation, ComEd, PECO and BGE entered into amendments to each of their respective syndicated revolving credit facilities, which extended the maturity of each of the facilities to May 26, 2021. Exelon Corporate also increased the size of its facility from $500 million to $600 million. On May 26, 2016, PHI, Pepco, DPL and ACE entered into an amendment to their Second Amended and Restated Credit Agreement dated as of August 1, 2011, which (i) extended the maturity date of the facility to May 26, 2021, (ii) removed PHI as a borrower under the facility, (iii) decreased the size of the facility from $1.5 billion to $900 million and (iv) aligned its financial covenant from debt to capitalization leverage ratio to interest coverage ratio. On May 26, 2018, each of the Registrants' respective syndicated revolving credit facilities had their maturity dates extended to May 26, 2023.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 16 — Debt and Credit Agreements
Bilateral Credit Agreements The following table reflects the bilateral credit agreements atas of December 31, 2019:2021: | | | | | | | | | | | Registrant | Date Initiated | | Latest Amendment Date | | Maturity Date(a) | | Amount | Generation(b) | October 26, 2012 | | October 24, 2019 | | October 24, 2020 | | $ | 200 |
| Generation(c) | January 11, 2013 | | January 4, 2019 | | March 1, 2021 | | 100 | Generation(c) | January 5, 2016 | | January 4, 2019 | | April 5, 2021 | | 150 | Generation(c) | February 21, 2019 | | N/A | | March 31, 2021 | | 100 | Generation(c) | October 25, 2019 | | N/A | | N/A | | 200 | Generation(c) | October 25, 2019 | | N/A | | N/A | | 100 | Generation(c) | November 20, 2019 | | N/A | | N/A | | 300 | Generation(c) | November 21, 2019 | | N/A | | November 21, 2020 | | 150 | Generation(c) | November 21, 2019 | | N/A | | November 21, 2021 | | 100 |
__________ | | | | | | | | | | | | | | | | | | | | | | | | | | | (a)Subsidiary | Credit facilities that do not contain a maturity date are specific to the agreements set within each contract. In some instances, credit facilities are automatically renewed based on the contingency standards set within the specific agreement. | Date Initiated | | Latest Amendment Date | | Maturity Date(a) | | Amount |
Generation(b)(c) | | January 11, 2013 | | March 1, 2021 | | March 1, 2023 | | $ | 100 | | Generation(b) | | January 5, 2016 | | April 2, 2021 | | April 5, 2023 | | 150 | Generation(b)(c) | | February 21, 2019 | | March 31, 2021 | | March 31, 2022 | | 100 | Generation(b) | | October 25, 2019 | | N/A | | N/A | | 200 | | | | | | | | | | Generation(b) | Bilateral credit facility relates to CENG, which is incorporated within Generation, and supports the issuance of letters of credit and funding for working capital and does not back Generation's commercial paper program. |
| November 20, 2019 | | N/A | | N/A | | 300 | (c)Generation(b) | Bilateral credit agreements solely support the issuance of letters of credit and do not back Generation's commercial paper program. | November 21, 2019 | | N/A | | N/A | | 150 | Generation(b) | | November 21, 2019 | | November 21, 2021 | | November 21, 2022 | | 100 | Generation(b)(d) | | May 15, 2020 | | N/A | | N/A | | 100 |
__________ (a)Credit facilities that do not contain a maturity date are specific to the agreements set within each contract. In some instances, credit facilities are automatically renewed based on the contingency standards set within the specific agreement. (b)Bilateral credit agreements solely support the issuance of letters of credit and do not back the commercial paper program relating to Generation. (c)The bilateral credit agreement was terminated on January 31, 2022. (d)On February 9, 2022, the bilateral credit agreement increased to $200 million. Borrowings under Exelon Corporate’s, Generation’s,Exelon’s, ComEd’s, PECO’s, BGE's, Pepco's, DPL's, and ACE's revolving credit agreements bear interest at a rate based upon either the prime rate or a LIBOR-based rate, plus an adder based upon the particular Registrant’s credit rating. The adders for the prime based borrowings and LIBOR-based borrowings are presented in the following table: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exelon(a) | | | | ComEd | | PECO | | BGE | | | | Pepco | | DPL | | ACE | Prime based borrowings | 0 - 27.5 | | | | — | | | — | | | — | | | | | 7.5 | | | — | | | 7.5 | | LIBOR-based borrowings | 90.0 - 127.5 | | | | 100.0 | | | 90.0 | | | 90.0 | | | | | 107.5 | | | 100.0 | | | 107.5 | |
| | | | | | | | | | | | | | | | | | Exelon | | Generation | | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE | Prime based borrowings | 27.5 | | 27.5 | | 7.5 | | — | | — | | 7.5 | | 7.5 | | 7.5 | LIBOR-based borrowings | 127.5 | | 127.5 | | 107.5 | | 90.0 | | 100.0 | | 107.5 | | 107.5 | | 107.5 |
__________
(a)Includes interest rate adders at Exelon Corporate of 27.5 basis points and 127.5 basis points for prime and LIBOR-based borrowings, respectively.
If any registrant loses its investment grade rating, the maximum adders for prime rate borrowings and LIBOR-based rate borrowings would be 65 basis points and 165 basis points.points, respectively. The credit agreements also require the borrower to pay a facility fee based upon the aggregate commitments. The fee varies depending upon the respective credit ratings of the borrower. 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, 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 0.65% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Short-term borrowings in Exelon's Consolidated Balance Sheet. On March 24, 2021, Exelon Corporate entered into a 9-month term loan agreement for $200 million. 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. Exelon Corporate repaid the term loan on December 22, 2021. On March 31, 2021, Exelon Corporate entered into a 9-month and 364-day term loan agreement for $150 million each with variable interest rates of LIBOR plus 0.65% and expiration dates of December 31, 2021 and March 30, 2022, respectively. The 364-day loan agreement is reflected in Short-term borrowings in Exelon's Consolidated Balance Sheet. Exelon Corporate repaid the 9-month term loan on December 29, 2021. In connection with the separation, on January 24, 2022, Exelon Corporate entered into a 364-day term loan agreement for $1.15 billion. The loan agreement will expire on January 23, 2023. Pursuant to the loan
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 17 — Debt and Credit Agreements agreement, loans made thereunder bear interest at a variable rate equal to SOFR plus 0.75% and all indebtedness thereunder is unsecured. 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 Short-term borrowings in Exelon's Consolidated Balance Sheet. In connection with the separation, Generation repaid the term loan on January 26, 2022. 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 Short-term borrowings in Exelon's Consolidated Balance Sheet. On August 6, 2021, Generation entered into a 364-day term loan agreement for $880 million to fund the purchase of EDF's equity interest in CENG. Pursuant to the loan agreement, loans made thereunder bear interest at a variable 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 is reflected in Short-term borrowings in Exelon's Consolidated Balance Sheet. The loan agreement was amended on January 24, 2022 to change the maturity date to June 30, 2022 from August 5, 2022. See Note 2 — Mergers, Acquisitions, and Dispositions for additional information. On January 25, 2021, ComEd entered into two 90-day term loan agreements of $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. Variable Rate Demand Bonds DPL has outstanding obligations in respect of Variable Rate Demand Bonds (VRDB). VRDBs are subject to repayment on the demand of the holders and, for this reason, are accounted for as short-term debt in accordance with GAAP. However, these bonds may be converted to a fixed-rate, fixed-term option to establish a maturity which corresponds to the date of final maturity of the bonds. On this basis, PHI views VRDBs as a source of long-term financing. As of both December 31, 20192021 and December 31, 2018,2020, $79 million in variable rate demand bonds issued by DPL were outstanding and are included in the Long-term debt due within one year in Exelon's, PHI's, and DPL's Consolidated Balance Sheet.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 1617 — Debt and Credit Agreements
Long-Term Debt The following tables present the outstanding long-term debt at the Registrants as of December 31, 20192021 and 2018:2020: Exelon | | | | | | | Maturity Date | | December 31, | | Maturity Date | | December 31, | | Rates | | 2019 | | 2018 | | Rates | | 2021 | | 2020 | Long-term debt | | | | | | | | | | Long-term debt | | | | | | | | | First mortgage bonds(a)(c) | 1.70 | % | - | 7.90 | % | | 2020 - 2049 | | $ | 17,486 |
| | $ | 16,496 |
| 0.14 | % | - | 7.90 | % | | 2022 - 2051 | | $ | 20,751 | | | $ | 18,915 | | Senior unsecured notes | 2.45 | % | - | 7.60 | % | | 2020 - 2046 | | 10,685 |
| | 11,285 |
| Senior unsecured notes | 3.25 | % | - | 7.60 | % | | 2022 - 2050 | | 10,285 | | | 10,585 | | Unsecured notes | 2.40 | % | - | 6.35 | % | | 2021 - 2049 | | 3,300 |
| | 2,900 |
| Unsecured notes | 2.25 | % | - | 6.35 | % | | 2022 - 2050 | | 4,000 | | | 3,700 | | Pollution control notes | 2.50 | % | - | 2.70 | % | | 2025 - 2036 | | 412 |
| | 435 |
| | Nuclear fuel procurement contracts | | | 3.15 | % | | 2020 | | 3 |
| | 39 |
| | | Notes payable and other | 2.53 | % | - | 7.99 | % | | 2020 - 2053 | | 154 |
| | 188 |
| Notes payable and other | 1.64 | % | - | 7.49 | % | | 2022 - 2053 | | 189 | | | 170 | | Junior subordinated notes |
| | 3.50 | % | | 2022 | | 1,150 |
| | 1,150 |
| Junior subordinated notes | | 3.50 | % | | 2022 | | 1,150 | | | 1,150 | | | Long-term software licensing agreement | | | 3.95 | % | | 2024 | | 55 |
| | 73 |
| Long-term software licensing agreement | 3.62 | % | - | 3.95 | % | | 2024 - 2025 | | 9 | | | 30 | | Unsecured Tax-Exempt Bonds(b) | 1.63 | % | - | 5.40 | % | | 2022 - 2031 | | 222 |
| | 112 |
| | Medium-Terms Notes (unsecured) | 7.61 | % | - | 7.72 | % | | 2027 | | 10 |
| | 22 |
| | Unsecured tax-exempt bonds | | Unsecured tax-exempt bonds | 0.12 | % | - | 1.70 | % | | 2022 - 2024 | | 143 | | | 143 | | Medium-terms notes (unsecured) | | Medium-terms notes (unsecured) | 0 | | 7.72 | % | | 2027 | | 10 | | | 10 | | Transition bonds | | | 5.55 | % | | 2023 | | 40 |
| | 59 |
| Transition bonds | | 5.55 | % | | 2021 | | — | | | 21 | | Loan Agreement | | | 2.00 | % | | 2023 | | 50 |
| | 50 |
| | Loan agreement(d) | | Loan agreement(d) | | 2.00 | % | | 2023 | | 50 | | | 50 | | Nonrecourse debt: | | | | | | | | Nonrecourse debt: | | Fixed rates | 2.29 | % | - | 6.00 | % | | 2031 - 2037 | | 1,182 |
| | 1,253 |
| Fixed rates | 2.29 | % | - | 6.00 | % | | 2031 - 2037 | | 909 | | | 977 | | Variable rates | 3.18 | % | - | 4.91 | % | | 2020 - 2024 | | 811 |
| | 849 |
| Variable rates | 2.98 | % | - | 3.50 | % | | 2026 - 2027 | | 870 | | | 765 | | Total long-term debt | | | | | 35,560 |
| | 34,911 |
| Total long-term debt | | 38,366 | | | 36,516 | | Unamortized debt discount and premium, net | | | | | (72 | ) | | (66 | ) | Unamortized debt discount and premium, net | | (77) | | | (77) | | Unamortized debt issuance costs | | | | | (214 | ) | | (216 | ) | Unamortized debt issuance costs | | (262) | | | (248) | | Fair value adjustment | | | | | 765 |
| | 795 |
| Fair value adjustment | | 670 | | | 721 | | | Long-term debt due within one year | | | | | (4,710 | ) | | (1,349 | ) | Long-term debt due within one year | | (3,373) | | | (1,819) | | Long-term debt | | | | | $ | 31,329 |
| | $ | 34,075 |
| Long-term debt | | $ | 35,324 | | | $ | 35,093 | | Long-term debt to financing trusts(c) | | | | | | | | | Long-term debt to financing trusts(e) | | Long-term debt to financing trusts(e) | | | | | Subordinated debentures to ComEd Financing III | | | 6.35 | % | | 2033 | | $ | 206 |
| | $ | 206 |
| Subordinated debentures to ComEd Financing III | | 6.35 | % | | 2033 | | $ | 206 | | | $ | 206 | | Subordinated debentures to PECO Trust III | 6.75 | % | - | 7.38 | % | | 2028 | | 81 |
| | 81 |
| Subordinated debentures to PECO Trust III | 5.25 | % | - | 7.38 | % | | 2028 | | 81 | | | 81 | | Subordinated debentures to PECO Trust IV | | | 5.75 | % | | 2033 | | 103 |
| | 103 |
| Subordinated debentures to PECO Trust IV | | 5.75 | % | | 2033 | | 103 | | | 103 | | | Total long-term debt to financing trusts | | | | | 390 |
| | 390 |
| Total long-term debt to financing trusts | | $ | 390 | | | $ | 390 | | Unamortized debt issuance costs | | | | | — |
| | — |
| | Long-term debt to financing trusts | | | | | $ | 390 |
| | $ | 390 |
| | |
__________ | | (a) | Substantially all of ComEd’s assets other than expressly excepted property and substantially all of PECO’s, Pepco's, DPL's and ACE's assets are subject to the liens of their respective mortgage indentures. |
| | (b) | Bond amount totaling $110 million was previously disclosed within the first mortgage bonds line item, as it was classified as a secured tax-exempt bond. In 2019, the callable bond was reissued as an unsecured tax-exempt bond, and is presented as such within this section. |
| | (c) | Amounts owed to these financing trusts are recorded as Long-term debt to financing trusts within Exelon’s Consolidated Balance Sheets. |
(a)Substantially all of ComEd’s assets other than expressly excepted property and substantially all of PECO’s, Pepco's, DPL's, and ACE's assets are subject to the liens of their respective mortgage indentures.
(b)On November 16, 2021, DPL entered into a purchase agreement of First Mortgage Bonds of $125 million at 3.06% due on February 15, 2052. The closing date of the issuance occurred on February 15, 2022.
(c)On November 16, 2021, ACE entered into a purchase agreement of First Mortgage Bonds of $25 million and $150 million at 2.27% and 3.06% due on February 15, 2032 and February 15, 2052, respectively. The closing date of the issuance occurred on February 15, 2022.
(d)In connection with the separation, Exelon Corporate entered into three 18-month term loan agreements. On January 21, 2022, two of the loan agreements were issued for $300 million each with an expiration date of July 21, 2023. On January 24, 2022, the third loan agreement was issued for $250 million with an expiration date of July 24, 2023. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to SOFR plus 0.65%.
(e)Amounts owed to these financing trusts are recorded as Long-term debt to financing trusts within Exelon’s Consolidated Balance Sheet.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 1617 — Debt and Credit Agreements
ComEd
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Maturity Date | | December 31, | | Rates | | 2021 | | 2020 | Long-term debt | | | | | | | | | | First mortgage bonds(a) | 2.20 | % | - | 6.45 | % | | 2024 - 2051 | | $ | 9,879 | | | $ | 9,079 | | Other | | | 7.49 | % | | 2053 | | 8 | | | 8 | | Total long-term debt | | | | | | | 9,887 | | | 9,087 | | Unamortized debt discount and premium, net | | | | | | | (27) | | | (28) | | Unamortized debt issuance costs | | | | | | | (87) | | | (76) | | Long-term debt due within one year | | | | | | | — | | | (350) | | Long-term debt | | | | | | | $ | 9,773 | | | $ | 8,633 | | Long-term debt to financing trust(b) | | | | | | | | | | Subordinated debentures to ComEd Financing III | | | 6.35 | % | | 2033 | | $ | 206 | | | $ | 206 | | Total long-term debt to financing trusts | | | | | | | 206 | | | 206 | | Unamortized debt issuance costs | | | | | | | (1) | | | (1) | | Long-term debt to financing trusts | | | | | | | $ | 205 | | | $ | 205 | |
Generation__________
(a)Substantially all of ComEd’s assets, other than expressly excepted property, are subject to the lien of its mortgage indenture. | | | | | | | | | | | | | | | | | | | | | | Maturity Date | | December 31, | | Rates | | 2019 | | 2018 | Long-term debt | | | | | | | | | | Senior unsecured notes | 2.95 | % | - | 7.60 | % | | 2020 - 2042 | | $ | 5,420 |
| | $ | 6,019 |
| Pollution control notes | 2.50 | % | - | 2.70 | % | | 2025 - 2036 | | 412 |
| | 435 |
| Nuclear fuel procurement contracts | |
| 3.15 | % | | 2020 | | 3 |
| | 39 |
| Notes payable and other | 2.53 | % | - | 4.26 | % | | 2020 - 2028 | | 115 |
| | 164 |
| Nonrecourse debt: | | | | | | | | | | Fixed rates | 2.29 | % | - | 6.00 | % | | 2031 - 2037 | | 1,182 |
| | 1,253 |
| Variable rates | 3.18 | % | - | 4.91 | % | | 2020 - 2024 | | 811 |
| | 849 |
| Total long-term debt | | | | | | | 7,943 |
| | 8,759 |
| Unamortized debt discount and premium, net | | | | | | | (5 | ) | | (6 | ) | Unamortized debt issuance costs | | | | | | | (42 | ) | | (51 | ) | Fair value adjustment | | | | | | | 78 |
| | 91 |
| Long-term debt due within one year | | | | | | | (3,182 | ) | | (906 | ) | Long-term debt | | | | | | | $ | 4,792 |
| | $ | 7,887 |
|
(b)Amount owed to this financing trust is recorded as Long-term debt to financing trust within ComEd’s Consolidated Balance Sheet.
PECO
ComEd
| | | | | | | Maturity Date | | December 31, | | Maturity Date | | December 31, | | Rates | | 2019 | | 2018 | | Rates | | 2021 | | 2020 | Long-term debt | | | | | | | | Long-term debt | | | | | | | | First mortgage bonds(a) | 2.55 | % | - | 6.45 | % | | 2020 - 2049 | | $ | 8,578 |
| | $ | 8,179 |
| First mortgage bonds(a) | 2.38 | % | - | 5.95 | % | | 2022 - 2051 | | $ | 4,200 | | | $ | 3,750 | | Notes payable and other |
|
| | 7.49 | % | | 2053 | | 8 |
| | 8 |
| | Loan agreement | | Loan agreement | | 2.00 | % | | 2023 | | 50 | | | 50 | | Total long-term debt | | | | | 8,586 |
| | 8,187 |
| Total long-term debt | | 4,250 | | | 3,800 | | Unamortized debt discount and premium, net | | | | | (27 | ) | | (23 | ) | Unamortized debt discount and premium, net | | (20) | | | (20) | | Unamortized debt issuance costs | | | | | (68 | ) | | (63 | ) | Unamortized debt issuance costs | | (33) | | | (27) | | Long-term debt due within one year | | | | | (500 | ) | | (300 | ) | Long-term debt due within one year | | (350) | | | (300) | | Long-term debt | | | | | $ | 7,991 |
| | $ | 7,801 |
| Long-term debt | | $ | 3,847 | | | $ | 3,453 | | Long-term debt to financing trust(b) | | | | | | | | | Subordinated debentures to ComEd Financing III | | | 6.35 | % | | 2033 | | $ | 206 |
| | $ | 206 |
| | Total long-term debt to financing trusts | | | | | 206 |
| | 206 |
| | Unamortized debt issuance costs | | | | | (1 | ) | | (1 | ) | | Long-term debt to financing trusts(b) | | Long-term debt to financing trusts(b) | | | | | Subordinated debentures to PECO Trust III | | Subordinated debentures to PECO Trust III | 5.25 | % | - | 7.38 | % | | 2028 | | $ | 81 | | | $ | 81 | | Subordinated debentures to PECO Trust IV | | Subordinated debentures to PECO Trust IV | | 5.75 | % | | 2033 | | 103 | | | 103 | | | Long-term debt to financing trusts | | | | | $ | 205 |
| | $ | 205 |
| Long-term debt to financing trusts | | $ | 184 | | | $ | 184 | |
__________ | | (a) | Substantially all of ComEd’s assets, other than expressly excepted property, are subject to the lien of its mortgage indenture. |
| | (b) | Amount owed to this financing trust is recorded as Long-term debt to financing trust within ComEd’s Consolidated Balance Sheets. |
(a)Substantially all of PECO’s assets are subject to the lien of its mortgage indenture.
(b)Amounts owed to this financing trust are recorded as Long-term debt to financing trusts within PECO’s Consolidated Balance Sheet.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 1617 — Debt and Credit Agreements
PECO
| | | | | | | | | | | | | | | | | | | | | | Maturity Date | | December 31, | | Rates | | 2019 | | 2018 | Long-term debt | | | | | | | | | | First mortgage bonds(a) | 1.70 | % | - | 5.95 | % | | 2021 - 2049 | | $ | 3,400 |
| | $ | 3,075 |
| Loan Agreement | | | 2.00 | % | | 2023 | | 50 |
| | 50 |
| Total long-term debt | | | | | | | 3,450 |
| | 3,125 |
| Unamortized debt discount and premium, net | | | | | | | (21 | ) | | (18 | ) | Unamortized debt issuance costs | | | | | | | (24 | ) | | (23 | ) | Long-term debt | | | | | | | $ | 3,405 |
| | $ | 3,084 |
| Long-term debt to financing trusts(b) | | | | | | | | | | Subordinated debentures to PECO Trust III | 6.75 | % | - | 7.38 | % | | 2028 | | $ | 81 |
| | $ | 81 |
| Subordinated debentures to PECO Trust IV | | | 5.75 | % | | 2033 | | 103 |
| | 103 |
| Long-term debt to financing trusts | | | | | | | $ | 184 |
| | $ | 184 |
|
__________
| | (a) | Substantially all of PECO’s assets are subject to the lien of its mortgage indenture. |
| | (b) | Amounts owed to this financing trust are recorded as Long-term debt to financing trusts within PECO’s Consolidated Balance Sheets. |
BGE | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Maturity Date | | December 31, | | Rates | | 2021 | | 2020 | Long-term debt | | | | | | | | | | | | | | | | | | | | Unsecured notes | 2.25 | % | - | 6.35 | % | | 2022 - 2050 | | $ | 4,000 | | | $ | 3,700 | | Total long-term debt | | | | | | | 4,000 | | | 3,700 | | Unamortized debt discount and premium, net | | | | | | | (12) | | | (12) | | Unamortized debt issuance costs | | | | | | | (27) | | | (24) | | Long-term debt due within one year | | | | | | | (250) | | | (300) | | Long-term debt | | | | | | | $ | 3,711 | | | $ | 3,364 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | Maturity Date | | December 31, | | Rates | | 2019 | | 2018 | Long-term debt | | | | | | | | | | Unsecured notes | 2.40 | % | - | 6.35 | % | | 2021 - 2049 | | $ | 3,300 |
| | $ | 2,900 |
| Total long-term debt | | | | | | | 3,300 |
| | 2,900 |
| Unamortized debt discount and premium, net | | | | | | | (9 | ) | | (6 | ) | Unamortized debt issuance costs | | | | | | | (21 | ) | | (18 | ) | Long-term debt | | | | | | | $ | 3,270 |
| | $ | 2,876 |
|
PHI | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Maturity Date | | December 31, | | Rates | | 2021 | | 2020 | Long-term debt | | | | | | | | | | First mortgage bonds(a) | 0.14 | % | - | 7.90 | % | | 2022 - 2051 | | $ | 6,672 | | | $ | 6,086 | | Senior unsecured notes | | | 7.45 | % | | 2032 | | 185 | | | 185 | | Unsecured tax-exempt bonds | 0.12 | % | - | 1.70 | % | | 2022 - 2024 | | 143 | | | 143 | | Medium-terms notes (unsecured) | | | 7.72 | % | | 2027 | | 10 | | | 10 | | Transition bonds | | | 5.55 | % | | 2021 | | — | | | 21 | | Finance leases | | | 3.54 | % | | 2022 - 2029 | | 74 | | | 50 | | Other(b) | 7.28 | % | - | 7.49 | % | | 2022 | | — | | | 1 | | Total long-term debt | | | | | | | 7,084 | | | 6,496 | | Unamortized debt discount and premium, net | | | | | | | 4 | | | 4 | | Unamortized debt issuance costs | | | | | | | (36) | | | (28) | | Fair value adjustment | | | | | | | 495 | | | 534 | | Long-term debt due within one year | | | | | | | (399) | | | (347) | | Long-term debt | | | | | | | $ | 7,148 | | | $ | 6,659 | |
_________ (a)Substantially all of Pepco's, DPL's, and ACE's assets are subject to the liens of their respective mortgage indentures. (b)The amount in the Other category was less than 1 million as of December 31, 2021.
Pepco
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Maturity Date | | December 31, | | Rates | | 2021 | | 2020 | Long-term debt | | | | | | | | | | First mortgage bonds(a) | 2.32 | % | - | 7.90 | % | | 2022 - 2051 | | $ | 3,350 | | | $ | 3,075 | | Unsecured tax-exempt bonds | | | 1.70 | % | | 2022 | | 110 | | | 110 | | Finance leases | | | 3.54 | % | | 2025 - 2029 | | 26 | | | 17 | | Other(b) | 7.28 | % | - | 7.49 | % | | 2022 | | — | | | 1 | | Total long-term debt | | | | | | | 3,486 | | | 3,203 | | Unamortized debt discount and premium, net | | | | | | | 2 | | | 2 | | Unamortized debt issuance costs | | | | | | | (43) | | | (40) | | Long-term debt due within one year | | | | | | | (313) | | | (3) | | Long-term debt | | | | | | | $ | 3,132 | | | $ | 3,162 | | ________(a)Substantially all of Pepco's assets are subject to the lien of its mortgage indenture. (b)The amount in the Other category was less than 1 million as of December 31, 2021.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 1617 — Debt and Credit Agreements
DPL
PHI
| | | | | | | | | | | | | | | | | | | | | | Maturity Date | | December 31, | | Rates | | 2019 | | 2018 | Long-term debt | | | | | | | | | | First mortgage bonds(a) | 1.76 | % | - | 7.90 | % | | 2021 - 2049 | | $ | 5,508 |
| | $ | 5,242 |
| Senior unsecured notes | |
| 7.45 | % | | 2032 | | 185 |
| | 185 |
| Unsecured Tax-Exempt Bonds(b) | 1.63 | % | - | 5.40 | % | | 2022 - 2031 | | 222 |
| | 112 |
| Medium-terms notes (unsecured) | 7.61 | % | - | 7.72 | % | | 2027 | | 10 |
| | 22 |
| Transition bonds(c) |
|
|
| 5.55 | % | | 2023 | | 40 |
| | 59 |
| Notes payable and other | 3.54 | % | - | 7.99 | % | | 2021 - 2027 | | 30 |
| | 16 |
| Total long-term debt | | | | | | | 5,995 |
|
| 5,636 |
| Unamortized debt discount and premium, net | | | | | | | 4 |
| | 4 |
| Unamortized debt issuance costs | | | | | | | (19 | ) | | (14 | ) | Fair value adjustment | | | | | | | 583 |
| | 633 |
| Long-term debt due within one year | | | | | | | (103 | ) | | (125 | ) | Long-term debt | | | | | | | $ | 6,460 |
|
| $ | 6,134 |
|
_________ | | (a) | Substantially all of Pepco's, DPL's, and ACE's assets are subject to the lien of its respective mortgage indenture. |
| | (b) | Bond amount totaling $110 million was previously disclosed within the first mortgage bonds line item, as it was classified as a secured tax-exempt bond. In 2019, the callable bond was reissued as an unsecured tax-exempt bond, and is presented as such within this section. |
| | (c) | Transition bonds are recorded as part of Long-term debt within ACE's Consolidated Balance Sheets. |
Pepco
| | | | | | | Maturity Date | | December 31, | | Maturity Date | | December 31, | | Rates | | 2019 | | 2018 | | Rates | | 2021 | | 2020 | Long-term debt | | | | | | | | Long-term debt | | | | | | | | First mortgage bonds(a) | 3.05 | % | - | 7.90 | % | | 2022 - 2048 | | $ | 2,775 |
| | $ | 2,735 |
| | Unsecured Tax-Exempt Bonds(b) | | | 1.70 | % | | 2022 | | 110 |
| | — |
| | Notes payable and other | 3.54 | % | - | 7.99 | % | | 2021 - 2027 | | 12 |
| | 16 |
| | First mortgage bonds(a)(b) | | First mortgage bonds(a)(b) | 0.14 | % | - | 4.27 | % | | 2023 - 2051 | | $ | 1,749 | | | $ | 1,624 | | Unsecured tax-exempt bonds | | Unsecured tax-exempt bonds | 0.12 | % | - | 0.13 | % | | 2024 | | 33 | | | 33 | | Medium-terms notes (unsecured) | | Medium-terms notes (unsecured) | | 7.72 | % | | 2027 | | 10 | | | 10 | | Finance leases | | Finance leases | | 3.54 | % | | 2025 - 2029 | | 29 | | | 20 | | Total long-term debt | | | | | 2,897 |
|
| 2,751 |
| Total long-term debt | | 1,821 | | | 1,687 | | Unamortized debt discount and premium, net | | | | | 2 |
| | 2 |
| Unamortized debt discount and premium, net | | — | | | 1 | | Unamortized debt issuance costs | | | | | (35 | ) | | (34 | ) | Unamortized debt issuance costs | | (11) | | | (11) | | Long-term debt due within one year | | | | | (2 | ) | | (15 | ) | Long-term debt due within one year | | (83) | | | (82) | | Long-term debt | | | | | $ | 2,862 |
|
| $ | 2,704 |
| Long-term debt | | $ | 1,727 | | | $ | 1,595 | |
__________ | | (a) | Substantially all of Pepco's assets are subject to the lien of its respective mortgage indenture. |
| | (b) | Bond amount totaling $110 million was previously disclosed within the first mortgage bonds line item, as it was classified as a secured tax-exempt bond. In 2019, the callable bond was reissued as an unsecured tax-exempt bond, and is presented as such within this section. |
(a)Substantially all of DPL's assets are subject to the lien of its mortgage indenture.
(b)On November 16, 2021, DPL entered into a purchase agreement of First Mortgage Bonds of $125 million at 3.06% due on February 15, 2052. The closing date of the issuance occurred on February 15, 2022.
ACE
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Maturity Date | | December 31, | | Rates | | 2021 | | 2020 | Long-term debt | | | | | | | | | | First mortgage bonds(a)(b) | 2.25 | % | - | 5.80 | % | | 2024 - 2050 | | $ | 1,573 | | | $ | 1,387 | | Transition bonds | | | 5.55 | % | | 2021 | | — | | | 21 | | Finance leases | | | 3.54 | % | | 2022 - 2029 | | 19 | | | 13 | | Total long-term debt | | | | | | | 1,592 | | | 1,421 | | Unamortized debt discount and premium, net | | | | | | | (1) | | | (1) | | Unamortized debt issuance costs | | | | | | | (9) | | | (7) | | Long-term debt due within one year | | | | | | | (3) | | | (261) | | Long-term debt | | | | | | | $ | 1,579 | | | $ | 1,152 | |
__________ (a)Substantially all of ACE's assets are subject to the lien of its mortgage indenture. (b)On November 16, 2021, ACE entered into a purchase agreement of First Mortgage Bonds of $25 million and $150 million at 2.27% and 3.06% due on February 15, 2032 and February 15, 2052, respectively. The closing date of the issuance occurred on February 15, 2022.
Long-term debt maturities at the Registrants in the periods 2022 through 2026 and thereafter are as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Year | Exelon | | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | 2022 | $ | 3,373 | | | | | $ | — | | | $ | 350 | | | $ | 250 | | | $ | 399 | | | $ | 313 | | | $ | 83 | | | $ | 3 | | 2023 | 865 | | | | | — | | | 50 | | | 300 | | | 512 | | | 4 | | | 505 | | | 3 | | 2024 | 818 | | | | | 250 | | | — | | | — | | | 562 | | | 404 | | | 5 | | | 153 | | 2025 | 2,223 | | | | | — | | | 350 | | | — | | | 162 | | | 4 | | | 5 | | | 153 | | 2026 | 1,725 | | | | | 500 | | | — | | | 350 | | | 11 | | | 4 | | | 4 | | | 3 | | Thereafter | 29,752 | | (a) | | | 9,342 | | (b) | 3,684 | | (c) | 3,100 | | | 5,438 | | | 2,757 | | | 1,219 | | | 1,277 | | Total | $ | 38,756 | | | | | $ | 10,092 | | | $ | 4,434 | | | $ | 4,000 | | | $ | 7,084 | | | $ | 3,486 | | | $ | 1,821 | | | $ | 1,592 | |
__________ (a)Includes $390 million due to ComEd and PECO financing trusts. (b)Includes $206 million due to ComEd financing trust. (c)Includes $184 million due to PECO financing trusts.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 1617 — Debt and Credit Agreements
Long-Term Debt to Affiliates
DPL
| | | | | | | | | | | | | | | | | | | | | | Maturity Date | | December 31, | | Rates | | 2019 | | 2018 | Long-term debt | | | | | | | | | | First mortgage bonds(a) | 1.76 | % | - | 4.27 | % | | 2023 - 2049 | | $ | 1,446 |
| | $ | 1,370 |
| Unsecured Tax-Exempt Bonds | 1.63 | % | - | 5.40 | % | | 2024 - 2031 | | 112 |
| | 112 |
| Medium-terms notes (unsecured) | 7.61 | % | - | 7.72 | % | | 2027 | | 10 |
| | 22 |
| Other | | | 3.54 | % | | 2027 | | 10 |
| | — |
| Total long-term debt | | | | | | | 1,578 |
|
| 1,504 |
| Unamortized debt discount and premium, net | | | | | | | 1 |
| | 2 |
| Unamortized debt issuance costs | | | | | | | (12 | ) | | (12 | ) | Long-term debt due within one year | | | | | | | (80 | ) | | (91 | ) | Long-term debt | | | | | | | $ | 1,487 |
|
| $ | 1,403 |
|
__________
| | (a) | Substantially all of DPL's assets are subject to the lien of its respective mortgage indenture. |
ACE
| | | | | | | | | | | | | | | | | | | | | | Maturity Date | | December 31, | | Rates | | 2019 | | 2018 | Long-term debt | | | | | | | | | | First mortgage bonds(a) | 3.38 | % | - | 6.80 | % | | 2021 - 2049 | | $ | 1,287 |
| | $ | 1,137 |
| Transition bonds(b) |
| | 5.55 | % | | 2023 | | 40 |
| | 59 |
| Other | | | 3.54 | % | | 2027 | | 8 |
| | — |
| Total long-term debt | | | | | | | $ | 1,335 |
|
| $ | 1,196 |
| Unamortized debt discount and premium, net | | | | | | | (1 | ) | | (1 | ) | Unamortized debt issuance costs | | | | | | | (7 | ) | | (7 | ) | Long-term debt due within one year | | | | | | | (20 | ) | | (18 | ) | Long-term debt | | | | | | | $ | 1,307 |
|
| $ | 1,170 |
|
__________
| | (a) | Substantially all of ACE's assets are subject to the lien of its respective mortgage indenture. |
| | (b) | Maturities of ACE's Transition Bonds outstanding at December 31, 2019 are $19 million in 2020 and $21 million in 2021. |
Combined Notes to Consolidated Financial Statements
(Dollarsthe Constellation merger, Exelon and subsidiaries of Generation (former Constellation subsidiaries) entered into intercompany loan agreements that mirror the terms and amounts of the third-party debt obligations of Exelon, resulting in millions, except per share data unless otherwise noted)
Note 16 — Debt and Credit Agreements
Long-term debt maturitiesintercompany notes receivable at Exelon Corporate from Generation. As of December 31, 2021 and 2020, Exelon Corporate had $319 million and $324 million, respectively, recorded to intercompany notes receivable from Generation. In connection with the separation, on January 31, 2022, Exelon Corporate received cash from Generation ComEd, PECO, BGE, PHI, Pepco, DPL and ACE inof $258 million to settle the periods 2020 through 2024 and thereafter are as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Year | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | 2020 | $ | 4,710 |
| | $ | 3,182 |
| | $ | 500 |
| | $ | — |
| | $ | — |
| | $ | 103 |
| | $ | 2 |
| | $ | 80 |
| | $ | 20 |
| 2021 | 1,517 |
| | 2 |
| | 350 |
| | 300 |
| | 300 |
| | 265 |
| | 2 |
| | 2 |
| | 261 |
| 2022 | 3,088 |
| | 1,024 |
| | — |
| | 350 |
| | 250 |
| | 314 |
| | 311 |
| | 2 |
| | 1 |
| 2023 | 855 |
| | 1 |
| | — |
| | 50 |
| | 300 |
| | 504 |
| | 1 |
| | 502 |
| | 1 |
| 2024 | 1,596 |
| | 792 |
| | 250 |
| | — |
| | — |
| | 553 |
| | 401 |
| | 1 |
| | 151 |
| Thereafter | 24,184 |
| (a) | 2,942 |
| | 7,691 |
| (b) | 2,934 |
| (c) | 2,450 |
| | 4,256 |
| | 2,180 |
| | 991 |
| | 901 |
| Total | $ | 35,950 |
| | $ | 7,943 |
| | $ | 8,791 |
| | $ | 3,634 |
|
| $ | 3,300 |
|
| $ | 5,995 |
|
| $ | 2,897 |
|
| $ | 1,578 |
|
| $ | 1,335 |
|
__________
| | (a) | Includes $390 million due to ComEd and PECO financing trusts. |
| | (b) | Includes $206 million due to ComEd financing trust. |
| | (c) | Includes $184 million due to PECO financing trusts. |
intercompany loan.
Debt Covenants As of December 31, 2019,2021, the Registrants are in compliance with debt covenants, except for Antelope Valley's nonrecourse debt event of default as discussed below.covenants. Nonrecourse Debt Exelon, andthrough Generation, havehas issued nonrecourse debt financing, in which approximately $2.8$2 billion of generating assets have been pledged as collateral atas of December 31, 2019.2021. 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 nonrecourse debt financing covenants, there could be a requirement to accelerate repayment of the associated debt or other borrowings earlier than the stated maturity dates. In these instances, if such repayment was not satisfied, 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. Antelope Valley Solar Ranch One. In December 2011, the DOE Loan Programs Office issued a guarantee for up to $646$646 million for a nonrecourse loan from the Federal Financing Bank to support the financing of the construction of the Antelope Valley facility. The project became fully operational in 2014. The loan will mature on January 5, 2037. Interest rates on the loan were fixed upon each advance at a spread of 37.5 basis points above U.S. Treasuries of comparable maturity. The advances were completed as of December 31, 2015 and the outstanding loan balance will bear interest at an average blended interest rate of 2.82%. As of December 31, 2019,2021 and December 31, 2020, approximately $485$435 million was outstanding. and $460 million were outstanding, respectively. In addition, Generation has issued letters of credit were issued to support itsGeneration's equity investment in the project. Asproject with $37 million outstanding as of December 31, 2019, Generation had $38 million in letters of credit outstanding related to the project.2021. In December 2017, Generation’sExelon’s interests in Antelope Valley were also contributed to and are pledged as collateral for the EGR IVCR financing structurestructures referenced below. Antelope Valley sells all of its output to PG&E through a PPA. On January 29, 2019, PG&E filed for protection under Chapter 11 of the U.S. Bankruptcy Code, which created an event of default for Antelope Valley’s nonrecourse debt that provides the lender with a right to accelerate amounts outstanding under the loan such that they would become immediately due and payable. As a result of the ongoing event of default and the absence of a waiver from the lender foregoing their acceleration rights, the debt was reclassified as current in Exelon’s and Generation’s Consolidated Balance Sheets in the first quarter of 2019 and continues to be classified as current as of December 31, 2019. Further, distributions from Antelope Valley to EGR IV are currently suspended.
Continental Wind.Wind, LLC. In September 2013, Continental Wind, LLC (Continental Wind), an indirect subsidiary of Exelon, and Generation, completed the issuance and sale of $613 million senior secured notes. Continental Wind owns
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 16 — Debt and Credit Agreements
and operates a portfolio of wind farms in Idaho, Kansas, Michigan, Oregon, New Mexico, and Texas with a total net capacity of 667MW.667 MW. The net proceeds were distributed to Generation for its general business purposes. The notes are scheduled to mature on February 28, 2033. The notes bear interest at a fixed rate of 6.00% with interest payable semi-annually. As of December 31, 2019, $4472021 and December 31, 2020, approximately $380 million was outstanding.and $415 million were outstanding, respectively. In addition, Continental Wind entered intohas a $131$122 million letter of credit facility and $10$4 million working capital revolver facility. Continental Wind has issued letters of credit to satisfy certain of its credit support and security obligations. As of December 31, 2019,2021, the Continental Wind letter of credit facility had $115 million in letters of credit outstanding related to the project. In 2017, Generation’sExelon’s interests in Continental Wind were contributed to EGRP.CRP. Refer to Note 2223 - Variable Interest Entities for additional information on EGRP.CRP. Renewable Power Generation. In March 2016, RPG, an indirect subsidiary of Exelon, and Generation, issued $150 million aggregate principal amount of a nonrecourse senior secured notes. The net proceeds were distributed to Generation for paydown of long term debt obligations at Sacramento PV Energy and Constellation Solar Horizons and for general business purposes. The loan is scheduled to mature on March 31, 2035. The term loan
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 17 — Debt and Credit Agreements bears interest at a fixed rate of 4.11% payable semi-annually. As of December 31, 2019, $1062021 and December 31, 2020, approximately $90 million was outstanding.and $95 million were outstanding, respectively. In 2017, Generation’sExelon’s interests in Renewable Power GenerationRPG were contributed to EGRP.CRP. Refer to Note 2223 - Variable Interest Entities for additional information on EGRP.CRP. SolGen.SolGen, LLC. In September 2016, SolGen, LLC (SolGen), an indirect subsidiary of Exelon, and Generation, issued $150 million aggregate principal amount of a nonrecourse senior secured notes. The net proceeds were distributed to Generation for general business purposes. The loan is scheduled to mature on September 30, 2036. The term loan bears interest at a fixed rateOn December 8, 2020, Generation entered into an agreement with an affiliate of 3.93% payable semi-annually. As of December 31, 2019, $131 million was outstanding. In 2017, Generation’s interests in SolGen were also contributed to and are pledged as collateralBrookfield Renewable, for the EGR IV financing structure referenced below.sale of a significant portion of Generation's solar business. The sale was completed on March 31, 2021 in which the buyer assumed the $125 million outstanding debt. See Note 2 — Mergers, Acquisitions, and Dispositions for additional information on the sale agreement.
ExGen Renewables IV.Constellation Renewables. In November 2017, EGR IV,CR, an indirect subsidiary of Exelon, and Generation, entered into an $850$850 million nonrecourse senior secured term loan credit facility agreement. Generation’s interests in EGRP, Antelope Valley, SolGen, and Albany Green Energy were all contributed to and are pledged as collateral for this financing. The net proceedsagreement with a maturity date of $785 million, after the initial funding of $50 million for debt service and liquidity reserves as well as deductions for original discount and estimated costs, fees and expenses incurred in connection with the execution and delivery of the credit facility agreement, were distributed to Generation for general corporate purposes. The $50 million of debt service and liquidity reserves was treated as restricted cash in Exelon’s and Generation’s Consolidated Balance Sheets and Consolidated Statements of Cash Flows. The loan is scheduled to mature on November 28, 2024. The term loan bears interest at a variable rate equal to LIBOR + 3%, subject to a 1% LIBOR floor with interest payable quarterly. As of December 31, 2019, $796 million was outstanding. In addition to the financing, EGR IVCR entered into interest rate swaps with an initial notional amount of $636 million at an interest rate of 2.32% to manage a portion of the interest rate exposure in connection with the financing.
Although Antelope Valley’s debt isIn December 2020, CR entered into a financing agreement for a $750 million nonrecourse senior secured term loan credit facility, scheduled to mature on December 15, 2027. The term loan bears interest at a variable rate equal to LIBOR plus 2.50%, subject to a 1% LIBOR floor with interest payable quarterly. In addition to the financing, CR entered into interest rate swaps with an initial notional amount of $516 million at an interest rate of 1.05% to manage a portion of the interest rate exposure in default, it isconnection with the financing.
The proceeds were used to repay the November 2017 nonrecourse senior secured term loan credit facility of $850 million, of which $709 million was outstanding as of the retirement date in December of 2020, and to EGR IV. However, ifsettle the November 2017 interest rate swap. Exelon’s interests in the futureCRP and Antelope Valley wereremained contributed to fileand are pledged as collateral for bankruptcy protection as a resultthis financing. As of events culminating from PG&E’s bankruptcy proceedings this would represent an event of default for EGR IV’s debt that would provide the lender with an opportunity to accelerate EGR IV’s debt.December 31, 2021 and December 31, 2020, $735 million and $750 million was outstanding, respectively. See Note 22 -23 — Variable Interest Entities for additional information on EGRP.CRP and Note 16 — Derivative Financial Instruments for additional information on interest rate swaps.
West Medway II, LLC. On May 13, 2021, West Medway II, LLC (West Medway II), an indirect subsidiary of Exelon, 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 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. Exelon’s interests in West Medway II, were pledged as collateral for this financing. As of December 31, 2021, approximately $135 million was outstanding. See Note 16 — Derivative Financial Instruments for additional information on interest rate swaps.
17.18. Fair Value of Financial Assets and Liabilities (All Registrants)
Exelon measuremeasures and recordsclassifies 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.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 17 — Fair Value of Financial Assets and Liabilities
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 18 — Fair Value of Financial Assets and Liabilities Fair Value of Financial Liabilities Recorded at the Carrying AmountAmortized 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 December 31, 20192021 and 2018.2020. The Registrants have no financial liabilities classified as Level 1. The carrying amounts of the Registrants’ short-term liabilities as presented onin their Consolidated Balance Sheets are representative of their fair value (Level 2) because of the short-term nature of these instruments.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2021 | | December 31, 2020 | | | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value | | | | Level 2 | | Level 3 | | Total | | | Level 2 | | Level 3 | | Total | Long-Term Debt, including amounts due within one year(a) | Exelon | | $ | 38,697 | | | $ | 40,282 | | | $ | 3,310 | | | $ | 43,592 | | | $ | 36,912 | | | $ | 40,688 | | | $ | 3,064 | | | $ | 43,752 | | | | | | | | | | | | | | | | | | | ComEd | | 9,773 | | | 11,305 | | | — | | | 11,305 | | | 8,983 | | | 11,117 | | | — | | | 11,117 | | PECO | | 4,197 | | | 4,740 | | | 50 | | | 4,790 | | | 3,753 | | | 4,553 | | | 50 | | | 4,603 | | BGE | | 3,961 | | | 4,406 | | | — | | | 4,406 | | | 3,664 | | | 4,366 | | | — | | | 4,366 | | PHI | | 7,547 | | | 5,970 | | | 2,167 | | | 8,137 | | | 7,006 | | | 6,099 | | | 1,806 | | | 7,905 | | Pepco | | 3,445 | | | 3,201 | | | 975 | | | 4,176 | | | 3,165 | | | 3,336 | | | 748 | | | 4,084 | | DPL | | 1,810 | | | 1,426 | | | 552 | | | 1,978 | | | 1,677 | | | 1,484 | | | 455 | | | 1,939 | | ACE | | 1,582 | | | 1,091 | | | 641 | | | 1,732 | | | 1,413 | | | 1,018 | | | 602 | | | 1,620 | | Long-Term Debt to Financing Trusts | Exelon | | $ | 390 | | | $ | — | | | $ | 470 | | | $ | 470 | | | $ | 390 | | | $ | — | | | $ | 467 | | | $ | 467 | | ComEd | | 205 | | | — | | | 248 | | | 248 | | | 205 | | | — | | | 246 | | | 246 | | PECO | | 184 | | | — | | | 222 | | | 222 | | | 184 | | | — | | | 221 | | | 221 | | SNF Obligation | Exelon | | $ | 1,210 | | | $ | 1,060 | | | $ | — | | | $ | 1,060 | | | $ | 1,208 | | | $ | 909 | | | $ | — | | | $ | 909 | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2019 | | December 31, 2018 | | | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value | | | | Level 2 | | Level 3 | | Total | | | Level 2 | | Level 3 | | Total | Long-Term Debt, including amounts due within one year(a)
| Exelon | | $ | 36,039 |
| | $ | 37,453 |
| | $ | 2,580 |
| | $ | 40,033 |
| | $ | 35,424 |
| | $ | 33,711 |
| | $ | 2,158 |
| | $ | 35,869 |
| Generation | | 7,974 |
| | 7,304 |
| | 1,366 |
| | 8,670 |
| | 8,793 |
| | 7,467 |
| | 1,443 |
| | 8,910 |
| ComEd | | 8,491 |
| | 9,848 |
| | — |
| | 9,848 |
| | 8,101 |
| | 8,390 |
| | — |
| | 8,390 |
| PECO | | 3,405 |
| | 3,868 |
| | 50 |
| | 3,918 |
| | 3,084 |
| | 3,157 |
| | 50 |
| | 3,207 |
| BGE | | 3,270 |
| | 3,649 |
| | — |
| | 3,649 |
| | 2,876 |
| | 2,950 |
| | — |
| | 2,950 |
| PHI | | 6,563 |
| | 5,902 |
| | 1,164 |
| | 7,066 |
| | 6,259 |
| | 5,436 |
| | 665 |
| | 6,101 |
| Pepco | | 2,864 |
| | 3,198 |
| | 388 |
| | 3,586 |
| | 2,719 |
| | 2,901 |
| | 196 |
| | 3,097 |
| DPL | | 1,567 |
| | 1,408 |
| | 311 |
| | 1,719 |
| | 1,494 |
| | 1,303 |
| | 193 |
| | 1,496 |
| ACE | | 1,327 |
| | 1,026 |
| | 464 |
| | 1,490 |
| | 1,188 |
| | 987 |
| | 275 |
| | 1,262 |
| Long-Term Debt to Financing Trusts(a)
| Exelon | | $ | 390 |
| | $ | — |
| | $ | 428 |
| | $ | 428 |
| | $ | 390 |
| | $ | — |
| | $ | 400 |
| | $ | 400 |
| ComEd | | 205 |
| | — |
| | 227 |
| | 227 |
| | 205 |
| | — |
| | 209 |
| | 209 |
| PECO | | 184 |
| | — |
| | 201 |
| | 201 |
| | 184 |
| | — |
| | 191 |
| | 191 |
| SNF Obligation | Exelon | | $ | 1,199 |
| | $ | 1,055 |
| | $ | — |
| | $ | 1,055 |
| | $ | 1,171 |
| | $ | 949 |
| | $ | — |
| | $ | 949 |
| Generation | | 1,199 |
| | 1,055 |
| | — |
| | 1,055 |
| | 1,171 |
| | 949 |
| | — |
| | 949 |
|
__________________
(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 1617 — Debt and Credit Agreements for each Registrants’ unamortized debt issuance costs, unamortized debt discount and premium, net, and purchase accounting fair value adjustments and Note 11 — Leases for finance lease liabilities.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 18 — Fair Value of Financial Assets and Liabilities Exelon uses the following methods and assumptions to estimate fair value of financial liabilities recorded at carrying cost:
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 17 — Fair Value of Financial Assets and Liabilities
| | | | | | | | | | | | Type | Level | Registrants | Valuation | Long-term debt,Long-Term Debt, including amounts due within one year | Taxable Debt Securities | 2 | All | The fair value is determined by a valuation model that is based on a conventional discounted cash flow methodology and utilizes assumptions of current market pricing curves. Exelon obtains credit spreads based on trades of existing Exelon debt securities as well as other issuers in the utility sector with similar credit ratings. The yields are then converted into discount rates of various tenors that are used for discounting the respective cash flows of the same tenor for each bond or note. | Variable Rate Financing Debt | 2 | Exelon, Generation, DPL | Debt rates are reset on a regular basis and the carrying value approximates fair value. | Taxable Private Placement Debt Securities | 3 | Exelon, Pepco, DPL, ACE | Rates are obtained similar to the process for taxable debt securities. Due to low trading volume and qualitative factors such as market conditions, low volume of investors, and investor demand, these debt securities are Level 3. | Government Backed Fixed Rate Project Financing Debt | 3 | Exelon Generation | The fair value is similar to the process for taxable debt securities. Due to the lack of market trading data on similar debt, the discount rates are derived based on the original loan interest rate spread to the applicable U.S. Treasury rate as well as a current market curve derived from government-backed securities. | Non-Government Backed Fixed Rate Nonrecourse Debt | 3 | Exelon, Generation, Pepco | Fair value is based on market and quoted prices for its own and other nonrecourse debt with similar risk profiles. Given the low trading volume in the nonrecourse debt market, the price quotes used to determine fair value will reflect certain qualitative factors, such as market conditions, investor demand, new developments that might significantly impact the project cash flows or off-taker credit, and other circumstances related to the projectproject. | Long-Term Debt to Financing Trusts | Long Term Debt to Financing Trusts | 3 | Exelon, ComEd, PECO | Fair value is based on publicly traded securities issued by the financing trusts. Due to low trading volume of these securities and qualitative factors, such as market conditions, investor demand, and circumstances related to each issue, this debt is classified as Level 3. | SNF Obligation | SNF Obligation | 2 | Exelon Generation | The carrying amount is derived from a contract with the DOE to provide for disposal of SNF from Generation’scertain of Exelon’s nuclear generating stations. See Note 19 — Commitments and Contingencies for further details. When determining the fair value of the obligation, the future carrying amount of the SNF obligation is calculated by compounding the current book value of the SNF obligation at the 13-week U.S. Treasury rate. The compounded obligation amount is discounted back to present value using Generation’sExelon’s discount rate, which is calculated using the same methodology as described above for the taxable debt securities, and an estimated maturity date of 2030.2035. |
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 17 — 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 December 31, 20192021 and 2018:2020: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exelon | | Generation | As of December 31, 2019 | 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) | $ | 639 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 639 |
| | $ | 214 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 214 |
| NDT fund investments | | | | | | | | |
|
| | | | | | | | | |
|
| Cash equivalents(b) | 365 |
| | 87 |
| | — |
| | — |
| | 452 |
| | 365 |
| | 87 |
| | — |
| | — |
| | 452 |
| Equities | 3,353 |
| | 1,753 |
| | — |
| | 1,388 |
| | 6,494 |
| | 3,353 |
| | 1,753 |
| | — |
| | 1,388 |
| | 6,494 |
| Fixed income |
| |
| |
| | | |
|
| |
| |
| |
| | | |
|
| Corporate debt | — |
| | 1,469 |
| | 257 |
| | — |
| | 1,726 |
| | — |
| | 1,469 |
| | 257 |
| | — |
| | 1,726 |
| U.S. Treasury and agencies | 1,808 |
| | 131 |
| | — |
| | — |
| | 1,939 |
| | 1,808 |
| | 131 |
| | — |
| | — |
| | 1,939 |
| Foreign governments | — |
| | 42 |
| | — |
| | — |
| | 42 |
| | — |
| | 42 |
| | — |
| | — |
| | 42 |
| State and municipal debt | — |
| | 90 |
| | — |
| | — |
| | 90 |
| | — |
| | 90 |
| | — |
| | — |
| | 90 |
| Other(c) | — |
| | 33 |
| | — |
| | 953 |
| | 986 |
| | — |
| | 33 |
| | — |
| | 953 |
|
| 986 |
| Fixed income subtotal | 1,808 |
| | 1,765 |
| | 257 |
|
| 953 |
| | 4,783 |
| | 1,808 |
| | 1,765 |
| | 257 |
| | 953 |
| | 4,783 |
| Private credit | — |
| | — |
| | 254 |
| | 508 |
| | 762 |
| | — |
| | — |
| | 254 |
| | 508 |
| | 762 |
| Private equity | — |
| | — |
| | — |
| | 402 |
| | 402 |
| | — |
| | — |
| | — |
| | 402 |
| | 402 |
| Real estate | — |
| | — |
| | — |
| | 607 |
| | 607 |
| | — |
| | — |
| | — |
| | 607 |
| | 607 |
| NDT fund investments subtotal(d) | 5,526 |
| | 3,605 |
| | 511 |
| | 3,858 |
|
| 13,500 |
|
| 5,526 |
| | 3,605 |
| | 511 |
|
| 3,858 |
|
| 13,500 |
| Rabbi trust investments |
| |
| |
| | | |
| |
| |
| |
| | | |
| Cash equivalents | 50 |
| | — |
| | — |
| | — |
| | 50 |
| | 4 |
| | — |
| | — |
| | — |
| | 4 |
| Mutual funds | 81 |
| | — |
| | — |
| | — |
| | 81 |
| | 25 |
| | — |
| | — |
| | — |
| | 25 |
| Fixed income | — |
| | 12 |
| | — |
| | — |
| | 12 |
| | — |
| | — |
| | — |
| | — |
| | — |
| Life insurance contracts | — |
| | 78 |
| | 41 |
| | — |
| | 119 |
| | — |
| | 25 |
| | — |
| | — |
| | 25 |
| Rabbi trust investments subtotal | 131 |
| | 90 |
| | 41 |
| | — |
|
| 262 |
|
| 29 |
| | 25 |
| | — |
| | — |
|
| 54 |
| Commodity derivative assets |
| |
| |
| | | |
|
| |
| |
| |
| | | |
|
| Economic hedges | 768 |
| | 2,491 |
| | 1,485 |
| | — |
| | 4,744 |
| | 768 |
| | 2,491 |
| | 1,485 |
| | — |
| | 4,744 |
| Proprietary trading | — |
| | 37 |
| | 60 |
| | — |
| | 97 |
| | — |
| | 37 |
| | 60 |
| | — |
| | 97 |
| Effect of netting and allocation of collateral(e)(f) | (908 | ) | | (2,162 | ) | | (588 | ) | | — |
| | (3,658 | ) | | (908 | ) | | (2,162 | ) | | (588 | ) | | — |
| | (3,658 | ) | Commodity derivative assets subtotal | (140 | ) | | 366 |
| | 957 |
|
| — |
|
| 1,183 |
|
| (140 | ) | | 366 |
| | 957 |
|
| — |
|
| 1,183 |
| Total assets | 6,156 |
| | 4,061 |
| | 1,509 |
|
| 3,858 |
|
| 15,584 |
|
| 5,629 |
| | 3,996 |
| | 1,468 |
|
| 3,858 |
|
| 14,951 |
|
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 1718 — Fair Value of Financial Assets and Liabilities
Exelon
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | As of December 31, 2021 | | | 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) | $ | 643 | | | $ | — | | | $ | — | | | $ | — | | | $ | 643 | | | | | | | | | | | | $ | 686 | | | $ | — | | | $ | — | | | $ | — | | | $ | 686 | | NDT fund investments | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Cash equivalents(b) | 465 | | | 116 | | | — | | | — | | | 581 | | | | | | | | | | | | 210 | | | 95 | | | — | | | — | | | 305 | | Equities | 4,564 | | | 1,805 | | | — | | | 1,645 | | | 8,014 | | | | | | | | | | | | 3,886 | | | 2,077 | | | — | | | 1,562 | | | 7,525 | | Fixed income | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Corporate debt(c) | — | | | 1,145 | | | 286 | | | — | | | 1,431 | | | | | | | | | | | | — | | | 1,485 | | | 285 | | | — | | | 1,770 | | U.S. Treasury and agencies | 2,193 | | | 30 | | | — | | | — | | | 2,223 | | | | | | | | | | | | 1,871 | | | 126 | | | — | | | — | | | 1,997 | | Foreign governments | — | | | 60 | | | — | | | — | | | 60 | | | | | | | | | | | | — | | | 56 | | | — | | | — | | | 56 | | State and municipal debt | — | | | 26 | | | — | | | — | | | 26 | | | | | | | | | | | | — | | | 101 | | | — | | | — | | | 101 | | Other | 29 | | | 23 | | | — | | | 1,449 | | | 1,501 | | | | | | | | | | | | — | | | 41 | | | — | | | 961 | | | 1,002 | | Fixed income subtotal | 2,222 | | | 1,284 | | | 286 | | | 1,449 | | | 5,241 | | | | | | | | | | | | 1,871 | | | 1,809 | | | 285 | | | 961 | | | 4,926 | | Private credit | — | | | — | | | 178 | | | 624 | | | 802 | | | | | | | | | | | | — | | | — | | | 212 | | | 629 | | | 841 | | Private equity | — | | | — | | | — | | | 673 | | | 673 | | | | | | | | | | | | — | | | — | | | — | | | 504 | | | 504 | | Real estate | — | | | — | | | — | | | 864 | | | 864 | | | | | | | | | | | | — | | | — | | | — | | | 679 | | | 679 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | NDT fund investments subtotal(d)(e) | 7,251 | | | 3,205 | | | 464 | | | 5,255 | | | 16,175 | | | | | | | | | | | | 5,967 | | | 3,981 | | | 497 | | | 4,335 | | | 14,780 | | Rabbi trust investments | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Cash equivalents | 63 | | | — | | | — | | | — | | | 63 | | | | | | | | | | | | 60 | | | — | | | — | | | — | | | 60 | | Mutual funds | 105 | | | — | | | — | | | — | | | 105 | | | | | | | | | | | | 91 | | | — | | | — | | | — | | | 91 | | Fixed income | — | | | 10 | | | — | | | — | | | 10 | | | | | | | | | | | | — | | | 11 | | | — | | | — | | | 11 | | Life insurance contracts | — | | | 99 | | | 38 | | | — | | | 137 | | | | | | | | | | | | — | | | 87 | | | 34 | | | — | | | 121 | | Rabbi trust investments subtotal | 168 | | | 109 | | | 38 | | | — | | | 315 | | | | | | | | | | | | 151 | | | 98 | | | 34 | | | — | | | 283 | | Investments in equities(f) | 43 | | | — | | | — | | | — | | | 43 | | | | | | | | | | | | 195 | | | — | | | — | | | — | | | 195 | | Commodity derivative assets | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Economic hedges | 3,017 | | | 7,223 | | | 3,899 | | | — | | | 14,139 | | | | | | | | | | | | 745 | | | 1,914 | | | 1,599 | | | — | | | 4,258 | | Proprietary trading | — | | | 19 | | | 8 | | | — | | | 27 | | | | | | | | | | | | — | | | 17 | | | 27 | | | — | | | 44 | | Effect of netting and allocation of collateral(g)(h) | (2,108) | | | (6,177) | | | (2,769) | | | — | | | (11,054) | | | | | | | | | | | | (607) | | | (1,597) | | | (905) | | | — | | | (3,109) | | Commodity derivative assets subtotal | 909 | | | 1,065 | | | 1,138 | | | — | | | 3,112 | | | | | | | | | | | | 138 | | | 334 | | | 721 | | | — | | | 1,193 | | DPP consideration | — | | | 365 | | | — | | | — | | | 365 | | | | | | | | | | | | — | | | 639 | | | — | | | — | | | 639 | | Total assets | 9,014 | | | 4,744 | | | 1,640 | | | 5,255 | | | 20,653 | | | | | | | | | | | | 7,137 | | | 5,052 | | | 1,252 | | | 4,335 | | | 17,776 | | Liabilities | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Commodity derivative liabilities | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Economic hedges | (2,201) | | | (6,870) | | | (4,184) | | | — | | | (13,255) | | | | | | | | | | | | (682) | | | (1,928) | | | (1,655) | | | — | | | (4,265) | | Proprietary trading | — | | | (18) | | | (2) | | | — | | | (20) | | | | | | | | | | | | — | | | (21) | | | (4) | | | — | | | (25) | | Effect of netting and allocation of collateral(g)(h) | 2,189 | | | 6,642 | | | 2,735 | | | — | | | 11,566 | | | | | | | | | | | | 540 | | | 1,918 | | | 1,067 | | | — | | | 3,525 | | Commodity derivative liabilities subtotal | (12) | | | (246) | | | (1,451) | | | — | | | (1,709) | | | | | | | | | | | | (142) | | | (31) | | | (592) | | | — | | | (765) | | Deferred compensation obligation | — | | | (154) | | | — | | | — | | | (154) | | | | | | | | | | | | — | | | (145) | | | — | | | — | | | (145) | | Total liabilities | (12) | | | (400) | | | (1,451) | | | — | | | (1,863) | | | | | | | | | | | | (142) | | | (176) | | | (592) | | | — | | | (910) | | Total net assets | $ | 9,002 | | | $ | 4,344 | | | $ | 189 | | | $ | 5,255 | | | $ | 18,790 | | | | | | | | | | | | $ | 6,995 | | | $ | 4,876 | | | $ | 660 | | | $ | 4,335 | | | $ | 16,866 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exelon | | Generation | As of December 31, 2019 | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total | | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total | Liabilities |
| |
| |
| | | |
| |
| |
| |
| | | |
|
| Commodity derivative liabilities |
| |
| |
| | | |
| |
| |
| |
| | | |
| Economic hedges | (1,071 | ) | | (2,855 | ) | | (1,228 | ) | | — |
| | (5,154 | ) | | (1,071 | ) | | (2,855 | ) | | (927 | ) | | — |
| | (4,853 | ) | Proprietary trading | — |
| | (34 | ) | | (15 | ) | | — |
| | (49 | ) | | — |
| | (34 | ) | | (15 | ) | | — |
| | (49 | ) | Effect of netting and allocation of collateral(e)(f) | 1,071 |
| | 2,714 |
| | 802 |
| | — |
| | 4,587 |
| | 1,071 |
| | 2,714 |
| | 802 |
| | — |
| | 4,587 |
| Commodity derivative liabilities subtotal | — |
| | (175 | ) | | (441 | ) |
| — |
|
| (616 | ) |
| — |
| | (175 | ) | | (140 | ) |
| — |
|
| (315 | ) | Deferred compensation obligation | — |
| | (147 | ) | | — |
| | — |
| | (147 | ) | | — |
| | (41 | ) | | — |
| | — |
| | (41 | ) | Total liabilities | — |
| | (322 | ) | | (441 | ) |
| — |
|
| (763 | ) |
| — |
| | (216 | ) | | (140 | ) |
| — |
|
| (356 | ) | Total net assets | $ | 6,156 |
| | $ | 3,739 |
| | $ | 1,068 |
|
| $ | 3,858 |
|
| $ | 14,821 |
|
| $ | 5,629 |
| | $ | 3,780 |
| | $ | 1,328 |
|
| $ | 3,858 |
|
| $ | 14,595 |
|
294 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exelon | | Generation | As of December 31, 2018 | 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) | $ | 1,243 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 1,243 |
| | $ | 581 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 581 |
| NDT fund investments | | | | | | | | |
| | | | | | | | | |
| Cash equivalents(b) | 252 |
| | 86 |
| | — |
| | — |
| | 338 |
| | 252 |
| | 86 |
| | — |
| | — |
| | 338 |
| Equities | 2,918 |
| | 1,591 |
| | — |
| | 1,381 |
| | 5,890 |
| | 2,918 |
| | 1,591 |
| | — |
| | 1,381 |
| | 5,890 |
| Fixed income |
|
|
|
|
| | | |
| |
|
|
|
|
| | | |
| Corporate debt | — |
| | 1,593 |
| | 230 |
| | — |
| | 1,823 |
| | — |
| | 1,593 |
| | 230 |
| | — |
| | 1,823 |
| U.S. Treasury and agencies | 2,081 |
| | 99 |
| | — |
| | — |
| | 2,180 |
| | 2,081 |
| | 99 |
| | — |
| | — |
| | 2,180 |
| Foreign governments | — |
| | 50 |
| | — |
| | — |
| | 50 |
| | — |
| | 50 |
| | — |
| | — |
| | 50 |
| State and municipal debt | — |
| | 149 |
| | — |
| | — |
| | 149 |
| | — |
| | 149 |
| | — |
| | — |
| | 149 |
| Other(c) | — |
| | 30 |
| | — |
| | 846 |
| | 876 |
| | — |
| | 30 |
| | — |
| | 846 |
| | 876 |
| Fixed income subtotal | 2,081 |
|
| 1,921 |
|
| 230 |
|
| 846 |
|
| 5,078 |
|
| 2,081 |
|
| 1,921 |
|
| 230 |
|
| 846 |
|
| 5,078 |
| Private credit | — |
| | — |
| | 313 |
| | 367 |
| | 680 |
| | — |
| | — |
| | 313 |
| | 367 |
| | 680 |
| Private equity | — |
| | — |
| | — |
| | 329 |
| | 329 |
| | — |
| | — |
| | — |
| | 329 |
| | 329 |
| Real estate | — |
| | — |
| | — |
| | 510 |
| | 510 |
| | — |
| | — |
| | — |
| | 510 |
| | 510 |
| NDT fund investments subtotal(d) | 5,251 |
|
| 3,598 |
|
| 543 |
|
| 3,433 |
|
| 12,825 |
|
| 5,251 |
|
| 3,598 |
|
| 543 |
|
| 3,433 |
|
| 12,825 |
|
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 1718 — Fair Value of Financial Assets and Liabilities __________ (a)Excludes cash of $881 million and $409 million as of December 31, 2021 and 2020, respectively, and restricted cash of $95 million and $59 million as of December 31, 2021 and 2020, respectively, and includes long-term restricted cash of $44 million and $53 million as of December 31, 2021 and 2020, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. (b)Includes $116 million of cash received from outstanding repurchase agreements as of both December 31, 2021 and 2020, 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 $(55) million and $(62) million as of December 31, 2021 and 2020, respectively, held in an investment vehicle primarily to hedge the equity option component of its convertible debt. (d)Includes net derivative liabilities of $1 million and net derivative assets of $2 million, which have total notional amounts of $687 million and $1,043 million as of December 31, 2021 and 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's exposure to credit or market loss. (e)Excludes net liabilities of $111 million and $181 million as of December 31, 2021 and 2020, respectively, which include certain derivative assets that have notional amounts of $182 million and $104 million as of December 31, 2021 and 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 which were previously designated as equity investments without readily determinable fair values but are now publicly traded and therefore have readily determinable fair values. The first investment became publicly traded in the fourth quarter of 2020. The fair value of these investments is recorded in Other current assets in Exelon's Consolidated Balance Sheets based on the quoted market prices of the stocks as of the respective balance sheet date. Unrealized (losses)/gains of $(160) million and $186 million were recorded in Other, net in Exelon's Consolidated Statement of Operations and Comprehensive Income for the years ended December 31, 2021 and 2020, respectively. (g)Collateral posted/(received) from counterparties, net of collateral paid to counterparties, totaled $81 million, $465 million, and $(34) million allocated to Level 1, Level 2, and Level 3 mark-to-market derivatives, respectively, as of December 31, 2021. Collateral posted/(received) 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 $897 million held and $209 million posted of variation margin with the exchanges as of December 31, 2021 and 2020, respectively.
As of December 31, 2021, Exelon has outstanding commitments to invest in private credit, private equity, and real estate investments of approximately $306 million, $171 million, and $459 million, respectively. These commitments will be funded by the existing NDT funds. Exelon held investments without readily determinable fair values with carrying amounts of $44 million and $73 million as of December 31, 2021 and 2020, respectively. Changes in fair value, cumulative adjustments, and impairments were not material for the years ended December 31, 2021 and 2020. ComEd, PECO, and BGE 295 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exelon | | Generation | As of December 31, 2018 | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total | | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total | Rabbi trust investments |
|
|
|
|
| | | |
| |
|
|
|
|
| | | |
| Cash equivalents | 48 |
| | — |
| | — |
| | — |
| | 48 |
| | 5 |
| | — |
| | — |
| | — |
| | 5 |
| Mutual funds | 72 |
| | — |
| | — |
| | — |
| | 72 |
| | 24 |
| | — |
| | — |
| | — |
| | 24 |
| Fixed income | — |
| | 15 |
| | — |
| | — |
| | 15 |
| | — |
| | — |
| | — |
| | — |
| | — |
| Life insurance contracts | — |
| | 70 |
| | 38 |
| | — |
| | 108 |
| | — |
| | 22 |
| | — |
| | — |
| | 22 |
| Rabbi trust investments subtotal | 120 |
|
| 85 |
|
| 38 |
|
| — |
|
| 243 |
|
| 29 |
|
| 22 |
|
| — |
|
| — |
|
| 51 |
| Commodity derivative assets | | | | | | | | | | | | | | | | | | | | Economic hedges | 541 |
| | 2,760 |
| | 1,470 |
| | — |
| | 4,771 |
| | 541 |
| | 2,760 |
| | 1,470 |
| | — |
| | 4,771 |
| Proprietary trading | — |
| | 69 |
| | 77 |
| | — |
| | 146 |
| | — |
| | 69 |
| | 77 |
| | — |
| | 146 |
| Effect of netting and allocation of collateral(e)(f) | (582 | ) | | (2,357 | ) | | (732 | ) | | — |
| | (3,671 | ) | | (582 | ) | | (2,357 | ) | | (732 | ) | | — |
| | (3,671 | ) | Commodity derivative assets subtotal | (41 | ) |
| 472 |
|
| 815 |
|
| — |
|
| 1,246 |
|
| (41 | ) |
| 472 |
|
| 815 |
|
| — |
|
| 1,246 |
| Total assets | 6,573 |
|
| 4,155 |
|
| 1,396 |
|
| 3,433 |
|
| 15,557 |
|
| 5,820 |
|
| 4,092 |
|
| 1,358 |
|
| 3,433 |
|
| 14,703 |
| Liabilities |
|
|
|
|
| | | |
| |
|
|
|
|
| | | |
|
| Commodity derivative liabilities |
|
|
|
|
| | | |
| |
|
|
|
|
| | | |
| Economic hedges | (642 | ) | | (2,963 | ) | | (1,276 | ) | | — |
| | (4,881 | ) | | (642 | ) | | (2,963 | ) | | (1,027 | ) | | — |
| | (4,632 | ) | Proprietary trading | — |
| | (73 | ) | | (21 | ) | | — |
| | (94 | ) | | — |
| | (73 | ) | | (21 | ) | | — |
| | (94 | ) | Effect of netting and allocation of collateral(e)(f) | 639 |
| | 2,581 |
| | 808 |
| | — |
| | 4,028 |
| | 639 |
| | 2,581 |
| | 808 |
| | — |
| | 4,028 |
| Commodity derivative liabilities subtotal | (3 | ) |
| (455 | ) |
| (489 | ) |
| — |
|
| (947 | ) |
| (3 | ) |
| (455 | ) |
| (240 | ) |
| — |
|
| (698 | ) | Deferred compensation obligation | — |
|
| (137 | ) |
| — |
| | — |
| | (137 | ) | | — |
|
| (35 | ) |
| — |
| | — |
| | (35 | ) | Total liabilities | (3 | ) |
| (592 | ) |
| (489 | ) |
| — |
|
| (1,084 | ) |
| (3 | ) |
| (490 | ) |
| (240 | ) |
| — |
|
| (733 | ) | Total net assets | $ | 6,570 |
|
| $ | 3,563 |
|
| $ | 907 |
|
| $ | 3,433 |
|
| $ | 14,473 |
|
| $ | 5,817 |
|
| $ | 3,602 |
|
| $ | 1,118 |
|
| $ | 3,433 |
|
| $ | 13,970 |
|
__________
| | (a) | Exelon excludes cash of $373 million and $458 million at December 31, 2019 and 2018, respectively, and restricted cash of $110 million and $80 million at December 31, 2019 and 2018, respectively, and includes long-term restricted cash of $177 million and $185 million at December 31, 2019 and 2018, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. Generation excludes cash of $177 million and $283 million at December 31, 2019 and 2018, respectively and restricted cash of $58 million and $39 million at December 31, 2019 and 2018, respectively. |
| | (b) | Includes $90 million and $50 million of cash received from outstanding repurchase agreements at December 31, 2019 and 2018, respectively, and is offset by an obligation to repay upon settlement of the agreement as discussed in (d) below. |
| | (c) | Includes derivative instruments of $2 million and $44 million, which have a total notional amount of $724 million and $1,432 million at December 31, 2019 and 2018, respectively. The notional principal amounts for these instruments provide one measure of the transaction volume outstanding as of the fiscal years ended and do not represent the amount of the company's exposure to credit or market loss. |
| | (d) | Excludes net liabilities of $147 million and $130 million at December 31, 2019 and 2018, 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. |
| | (e) | Collateral posted/(received) from counterparties totaled $163 million, $551 million and $214 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2019. Collateral posted/(received) from |
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 1718 — Fair Value of Financial Assets and Liabilities
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ComEd | | PECO | | BGE | 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 | | | | | | | | | | | | | | | | | | | | | | | | Cash equivalents(a) | $ | 237 | | | $ | — | | | $ | — | | | $ | 237 | | | $ | 9 | | | $ | — | | | $ | — | | | $ | 9 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | Rabbi trust investments | | | | | | | | | | | | | | | | | | | | | | | | Mutual funds | — | | | — | | | — | | | — | | | 11 | | | — | | | — | | | 11 | | | 14 | | | — | | | — | | | 14 | | Life insurance contracts | — | | | — | | | — | | | — | | | — | | | 16 | | | — | | | 16 | | | — | | | — | | | — | | | — | | Rabbi trust investments subtotal | — | | | — | | | — | | | — | | | 11 | | | 16 | | | — | | | 27 | | | 14 | | | — | | | — | | | 14 | | Total assets | 237 | | | — | | | — | | | 237 | | | 20 | | | 16 | | | — | | | 36 | | | 14 | | | — | | | — | | | 14 | | Liabilities | | | | | | | | | | | | | | | | | | | | | | | | Mark-to-market derivative liabilities(b) | — | | | — | | | (219) | | | (219) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Deferred compensation obligation | — | | | (10) | | | — | | | (10) | | | — | | | (9) | | | — | | | (9) | | | — | | | (7) | | | — | | | (7) | | Total liabilities | — | | | (10) | | | (219) | | | (229) | | | — | | | (9) | | | — | | | (9) | | | — | | | (7) | | | — | | | (7) | | Total net assets (liabilities) | $ | 237 | | | $ | (10) | | | $ | (219) | | | $ | 8 | | | $ | 20 | | | $ | 7 | | | $ | — | | | $ | 27 | | | $ | 14 | | | $ | (7) | | | $ | — | | | $ | 7 | |
counterparties totaled $57 million, $224 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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 | Assets | | | | | | | | | | | | | | | | | | | | | | | | Cash equivalents(a) | $ | 285 | | | $ | — | | | $ | — | | | $ | 285 | | | $ | 8 | | | $ | — | | | $ | — | | | $ | 8 | | | $ | 120 | | | $ | — | | | $ | — | | | $ | 120 | | Rabbi trust investments | | | | | | | | | | | | | | | | | | | | | | | | Mutual funds | — | | | — | | | — | | | — | | | 9 | | | — | | | — | | | 9 | | | 10 | | | — | | | — | | | 10 | | Life insurance contracts | — | | | — | | | — | | | — | | | — | | | 13 | | | — | | | 13 | | | — | | | — | | | — | | | — | | Rabbi trust investments subtotal | — | | | — | | | — | | | — | | | 9 | | | 13 | | | — | | | 22 | | | 10 | | | — | | | — | | | 10 | | Total assets | 285 | | | — | | | — | | | 285 | | | 17 | | | 13 | | | — | | | 30 | | | 130 | | | — | | | — | | | 130 | | Liabilities | | | | | | | | | | | | | | | | | | | | | | | | Mark-to-market derivative liabilities(b) | — | | | — | | | (301) | | | (301) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Deferred compensation obligation | — | | | (8) | | | — | | | (8) | | | — | | | (9) | | | — | | | (9) | | | — | | | (5) | | | — | | | (5) | | Total liabilities | — | | | (8) | | | (301) | | | (309) | | | — | | | (9) | | | — | | | (9) | | | — | | | (5) | | | — | | | (5) | | Total net assets (liabilities) | $ | 285 | | | $ | (8) | | | $ | (301) | | | $ | (24) | | | $ | 17 | | | $ | 4 | | | $ | — | | | $ | 21 | | | $ | 130 | | | $ | (5) | | | $ | — | | | $ | 125 | |
__________ (a)ComEd excludes cash of $105 million and $76$83 million allocated to Level 1, Level 2as of December 31, 2021 and 2020, respectively, and restricted cash of $42 million and $37 million as of December 31, 2021 and 2020, respectively, and includes long-term restricted cash of $43 million as of both December 31, 2021 and 2020, which is reported in Other deferred debits in the Consolidated Balance Sheets. PECO excludes cash of $35 million and $18 million as of December 31, 2021 and 2020, respectively. BGE excludes cash of $51 million and $24 million as of December 31, 2021 and 2020, respectively, and restricted cash of $4 million and $1 million as of December 31, 2021 and 2020, respectively. (b)The Level 3 mark-to-market derivatives,balance consists of the current and noncurrent liability of $18 million and $201 million, respectively, as of December 31, 2018. | | (f) | Of the collateral posted/(received), $511 million and $(94) million represents variation margin on the exchanges as of December 31, 2019 and 2018, respectively. |
As of December 31, 2019, Generation has outstanding commitments to invest in fixed income, private credit, private equity2021 and real estate investments of approximately $85 million, $166 million, $375$33 million and $427$268 million, respectively. These commitments will be funded by Generation’s existing NDT funds.
Exelon and Generation hold investments without readily determinable fair values with carrying amounts of $69 millionrespectively, as of December 31, 2019. Changes were immaterial in fair value, cumulative adjustments2020 related to floating-to-fixed energy swap contracts with unaffiliated suppliers.
PHI, Pepco, DPL, and impairments for the year ended December 31, 2019.ACE 296
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ComEd | | PECO | | BGE | As of December 31, 2019 | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total | Assets | | | | | | | | | | | | | | | | | | | | | | | | Cash equivalents(a) | $ | 280 |
|
| $ | — |
|
| $ | — |
| | $ | 280 |
| | $ | 15 |
|
| $ | — |
|
| $ | — |
| | $ | 15 |
| | $ | — |
|
| $ | — |
|
| $ | — |
| | $ | — |
| Rabbi trust investments | | | | | | | | | | | | | | | | | | | | | | | | Mutual funds | — |
|
| — |
|
| — |
| | — |
| | 8 |
|
| — |
|
| — |
| | 8 |
| | 8 |
|
| — |
|
| — |
| | 8 |
| Life insurance contracts | — |
| | — |
| | — |
| | — |
| | — |
| | 11 |
| | — |
| | 11 |
| | — |
| | — |
| | — |
| | — |
| Rabbi trust investments subtotal | — |
| | — |
| | — |
| | — |
| | 8 |
| | 11 |
| | — |
| | 19 |
| | 8 |
| | — |
| | — |
| | 8 |
| Total assets | 280 |
|
| — |
|
| — |
|
| 280 |
|
| 23 |
|
| 11 |
|
| — |
|
| 34 |
|
| 8 |
|
| — |
|
| — |
|
| 8 |
| Liabilities |
|
|
|
|
| |
| |
|
|
|
|
| |
| |
|
|
|
|
| |
| Deferred compensation obligation | — |
|
| (8 | ) |
| — |
| | (8 | ) | | — |
|
| (9 | ) |
| — |
| | (9 | ) | | — |
|
| (5 | ) |
| — |
| | (5 | ) | Mark-to-market derivative liabilities(b) | — |
|
| — |
|
| (301 | ) | | (301 | ) | | — |
|
| — |
|
| — |
| | — |
| | — |
|
| — |
|
| — |
| | — |
| Total liabilities | — |
|
| (8 | ) |
| (301 | ) |
| (309 | ) |
| — |
|
| (9 | ) |
| — |
|
| (9 | ) |
| — |
|
| (5 | ) |
| — |
|
| (5 | ) | Total net assets (liabilities) | $ | 280 |
|
| $ | (8 | ) |
| $ | (301 | ) |
| $ | (29 | ) |
| $ | 23 |
|
| $ | 2 |
|
| $ | — |
|
| $ | 25 |
|
| $ | 8 |
|
| $ | (5 | ) |
| $ | — |
|
| $ | 3 |
|
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 1718 — Fair Value of Financial Assets and Liabilities
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | As of December 31, 2021 | | As of December 31, 2020 | PHI | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total | Assets | | | | | | | | | | | | | | | | Cash equivalents(a) | $ | 110 | | | $ | — | | | $ | — | | | $ | 110 | | | $ | 86 | | | $ | — | | | $ | — | | | $ | 86 | | | | | | | | | | | | | | | | | | Rabbi trust investments | | | | | | | | | | | | | | | | Cash equivalents | 59 | | | — | | | — | | | 59 | | | 55 | | | — | | | — | | | 55 | | Mutual funds | 14 | | | — | | | — | | | 14 | | | 14 | | | — | | | — | | | 14 | | Fixed income | — | | | 10 | | | — | | | 10 | | | — | | | 11 | | | — | | | 11 | | Life insurance contracts | — | | | 27 | | | 35 | | | 62 | | | — | | | 26 | | | 34 | | | 60 | | Rabbi trust investments subtotal | 73 | | | 37 | | | 35 | | | 145 | | | 69 | | | 37 | | | 34 | | | 140 | | Total assets | 183 | | | 37 | | | 35 | | | 255 | | | 155 | | | 37 | | | 34 | | | 226 | | Liabilities | | | | | | | | | | | | | | | | Deferred compensation obligation | — | | | (18) | | | — | | | (18) | | | — | | | (17) | | | — | | | (17) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total liabilities | — | | | (18) | | | — | | | (18) | | | — | | | (17) | | | — | | | (17) | | Total net assets | $ | 183 | | | $ | 19 | | | $ | 35 | | | $ | 237 | | | $ | 155 | | | $ | 20 | | | $ | 34 | | | $ | 209 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Pepco | | DPL | | ACE | 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 | | | | | | | | | | | | | | | | | | | | | | | | Cash equivalents(a) | $ | 31 | | | $ | — | | | $ | — | | | $ | 31 | | | $ | 43 | | | $ | — | | | $ | — | | | $ | 43 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | Rabbi trust investments | | | | | | | | | | | | | | | | | | | | | | | | Cash equivalents | 58 | | | — | | | — | | | 58 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Life insurance contracts | — | | | 27 | | | 35 | | | 62 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Rabbi trust investments subtotal | 58 | | | 27 | | | 35 | | | 120 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Total assets | 89 | | | 27 | | | 35 | | | 151 | | | 43 | | | — | | | — | | | 43 | | | — | | | — | | | — | | | — | | Liabilities | | | | | | | | | | | | | | | | | | | | | | | | Deferred compensation obligation | — | | | (2) | | | — | | | (2) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total liabilities | — | | | (2) | | | — | | | (2) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Total net assets | $ | 89 | | | $ | 25 | | | $ | 35 | | | $ | 149 | | | $ | 43 | | | $ | — | | | $ | — | | | $ | 43 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
297 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ComEd | | PECO | | BGE | As of December 31, 2018 | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total | Assets | | | | | | | | | | | | | | | | | | | | | | | | Cash equivalents(a) | $ | 209 |
|
| $ | — |
|
| $ | — |
| | $ | 209 |
| | $ | 111 |
|
| $ | — |
|
| $ | — |
| | $ | 111 |
| | $ | 4 |
|
| $ | — |
|
| $ | — |
| | $ | 4 |
| Rabbi trust investments | | | | | | | | | | | | | | | | | | | | | | | | Mutual funds | — |
|
| — |
|
| — |
| | — |
| | 7 |
|
| — |
|
| — |
| | 7 |
| | 6 |
|
| — |
|
| — |
| | 6 |
| Life insurance contracts | — |
| | — |
| | — |
| | — |
| | — |
| | 10 |
| | — |
| | 10 |
| | — |
| | — |
| | — |
| | — |
| Rabbi trust investments subtotal | — |
| | — |
| | — |
| | — |
| | 7 |
| | 10 |
| | — |
| | 17 |
| | 6 |
| | — |
| | — |
| | 6 |
| Total assets | 209 |
|
| — |
|
| — |
|
| 209 |
|
| 118 |
|
| 10 |
|
| — |
|
| 128 |
|
| 10 |
|
| — |
|
| — |
|
| 10 |
| Liabilities |
|
|
|
|
| |
| |
|
|
|
|
| |
| |
|
|
|
|
| |
| Deferred compensation obligation | — |
|
| (6 | ) |
| — |
| | (6 | ) | | — |
|
| (10 | ) |
| — |
| | (10 | ) | | — |
|
| (5 | ) |
| — |
| | (5 | ) | Mark-to-market derivative liabilities(b) | — |
|
| — |
|
| (249 | ) | | (249 | ) | | — |
|
| — |
|
| — |
| | — |
| | — |
|
| — |
|
| — |
| | — |
| Total liabilities | — |
|
| (6 | ) |
| (249 | ) |
| (255 | ) |
| — |
|
| (10 | ) |
| — |
|
| (10 | ) |
| — |
|
| (5 | ) |
| — |
|
| (5 | ) | Total net assets (liabilities) | $ | 209 |
|
| $ | (6 | ) |
| $ | (249 | ) |
| $ | (46 | ) |
| $ | 118 |
|
| $ | — |
|
| $ | — |
|
| $ | 118 |
|
| $ | 10 |
|
| $ | (5 | ) |
| $ | — |
|
| $ | 5 |
|
__________
| | (a) | ComEd excludes cash of $90 million and $93 million at December 31, 2019 and 2018 and restricted cash of $33 million and $28 million at December 31, 2019 and 2018, respectively, and includes long-term restricted cash of $163 million and $166 million at December 31, 2019 and 2018, respectively which is reported in Other deferred debits in the Consolidated Balance Sheets. PECO excludes cash of $12 million and $24 million at December 31, 2019 and 2018, respectively. BGE excludes cash of $24 million and $7 million at December 31, 2019 and 2018, respectively, and restricted cash of $1 million and $2 million at December 31, 2019 and 2018, respectively.
|
| | (b) | The Level 3 balance consists of the current and noncurrent liability of $32 million and $269 million, respectively, at December 31, 2019, and $26 million and $223 million, respectively, at December 31, 2018, related to floating-to-fixed energy swap contracts with unaffiliated suppliers. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | As of December 31, 2019 | | As of December 31, 2018 | PHI | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total | Assets | | | | | | | | | | | | | | | | Cash equivalents(a) | $ | 124 |
| | $ | — |
| | $ | — |
| | $ | 124 |
| | $ | 147 |
| | $ | — |
| | $ | — |
| | $ | 147 |
| Rabbi trust investments | | | | | | |
| | | | | | | |
|
| Cash equivalents | 44 |
| | — |
| | — |
| | 44 |
| | 42 |
| | — |
| | — |
| | 42 |
| Mutual Funds | 14 |
| | — |
| | — |
| | 14 |
| | 13 |
| | — |
| | — |
| | 13 |
| Fixed income | — |
| | 12 |
| | — |
| | 12 |
| | — |
| | 15 |
| | — |
| | 15 |
| Life insurance contracts | — |
| | 24 |
| | 41 |
| | 65 |
| | — |
| | 22 |
| | 38 |
| | 60 |
| Rabbi trust investments subtotal(b) | 58 |
|
| 36 |
|
| 41 |
|
| 135 |
|
| 55 |
|
| 37 |
|
| 38 |
|
| 130 |
| Total assets | 182 |
|
| 36 |
|
| 41 |
|
| 259 |
|
| 202 |
|
| 37 |
|
| 38 |
|
| 277 |
| Liabilities | | | | | | | | | | | | | | |
|
| Deferred compensation obligation | — |
| | (19 | ) | | — |
| | (19 | ) | | — |
| | (21 | ) | | — |
| | (21 | ) | Total liabilities | — |
|
| (19 | ) |
| — |
|
| (19 | ) |
| — |
|
| (21 | ) |
| — |
|
| (21 | ) | Total net assets | $ | 182 |
|
| $ | 17 |
|
| $ | 41 |
|
| $ | 240 |
|
| $ | 202 |
|
| $ | 16 |
|
| $ | 38 |
|
| $ | 256 |
|
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 1718 — Fair Value of Financial Assets and Liabilities
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Pepco | | DPL | | ACE | As of December 31, 2019 | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total | Assets | | | | | | | | | | | | | | | | | | | | | | | | Cash equivalents(a) | $ | 34 |
| | $ | — |
| | $ | — |
| | $ | 34 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 16 |
| | $ | — |
| | $ | — |
| | $ | 16 |
| Rabbi trust investments | | | | | | |
|
| | | | | | | |
|
| | | | | | | |
|
| Cash equivalents | 43 |
| | — |
| | — |
| | 43 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Fixed income | — |
| | 2 |
| | — |
| | 2 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Life insurance contracts | — |
| | 24 |
| | 41 |
| | 65 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Rabbi trust investments subtotal | 43 |
|
| 26 |
|
| 41 |
|
| 110 |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
| Total assets | 77 |
|
| 26 |
|
| 41 |
|
| 144 |
|
| — |
|
| — |
|
| — |
|
| — |
|
| 16 |
|
| — |
|
| — |
|
| 16 |
| Liabilities | | | | | | | | | | | | | | | | | | | | | | | | Deferred compensation obligation | — |
| | (2 | ) | | — |
| | (2 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Total liabilities | — |
|
| (2 | ) |
| — |
|
| (2 | ) |
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
| Total net assets | $ | 77 |
|
| $ | 24 |
|
| $ | 41 |
|
| $ | 142 |
|
| $ | — |
|
| $ | — |
|
| $ | — |
|
| $ | — |
|
| $ | 16 |
|
| $ | — |
|
| $ | — |
|
| $ | 16 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | Pepco | | DPL | | ACE | | Pepco | | DPL | | ACE | | As of December 31, 2018 | 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, 2020 | | 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 | Assets | | | | | | | | | | | | | | | | | | | | | | | | Assets | | | | | | | | | | | | | | | | | | | | | | | | Cash equivalents(a) | $ | 38 |
| | $ | — |
| | $ | — |
| | $ | 38 |
| | $ | 16 |
| | $ | — |
| | $ | — |
| | $ | 16 |
| | $ | 23 |
| | $ | — |
| | $ | — |
| | $ | 23 |
| Cash equivalents(a) | $ | 35 | | | $ | — | | | $ | — | | | $ | 35 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 13 | | | $ | — | | | $ | — | | | $ | 13 | | | Rabbi trust investments | | | | | | |
|
| | | | | | | |
|
| | | | | | | |
|
| Rabbi trust investments | | Cash equivalents | 41 |
| | — |
| | — |
| | 41 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Cash equivalents | 53 | | | — | | | — | | | 53 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Fixed income | — |
| | 5 |
| | — |
| | 5 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Fixed income | — | | | 2 | | | — | | | 2 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Life insurance contracts | — |
| | 22 |
| | 37 |
| | 59 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Life insurance contracts | — | | | 26 | | | 34 | | | 60 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Rabbi trust investments subtotal | 41 |
|
| 27 |
|
| 37 |
|
| 105 |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
| Rabbi trust investments subtotal | 53 | | | 28 | | | 34 | | | 115 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Total assets | 79 |
|
| 27 |
|
| 37 |
|
| 143 |
|
| 16 |
|
| — |
|
| — |
|
| 16 |
|
| 23 |
|
| — |
|
| — |
|
| 23 |
| Total assets | 88 | | | 28 | | | 34 | | | 150 | | | — | | | — | | | — | | | — | | | 13 | | | — | | | — | | | 13 | | Liabilities | | | | | | | | | | | | | | | | | | | | | | | | Liabilities | | | | | | | | | | | | | | | | | | | | | | | | Deferred compensation obligation | — |
| | (3 | ) | | — |
| | (3 | ) | | — |
| | (1 | ) | | — |
| | (1 | ) | | — |
| | — |
| | — |
| | — |
| Deferred compensation obligation | — | | | (2) | | | — | | | (2) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | Total liabilities | — |
|
| (3 | ) |
| — |
|
| (3 | ) |
| — |
|
| (1 | ) |
| — |
|
| (1 | ) |
| — |
|
| — |
|
| — |
|
| — |
| Total liabilities | — | | | (2) | | | — | | | (2) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Total net assets | $ | 79 |
|
| $ | 24 |
|
| $ | 37 |
|
| $ | 140 |
|
| $ | 16 |
|
| $ | (1 | ) |
| $ | — |
|
| $ | 15 |
|
| $ | 23 |
|
| $ | — |
|
| $ | — |
|
| $ | 23 |
| Total net assets | $ | 88 | | | $ | 26 | | | $ | 34 | | | $ | 148 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 13 | | | $ | — | | | $ | — | | | $ | 13 | |
__________ | | (a) | PHI excludes cash of $57 million and $39 million at December 31, 2019 and 2018, respectively, and includes long term restricted cash of $14 million and $19 million at December 31, 2019 and 2018, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. Pepco excludes cash of $29 million and $15 million at December 31, 2019 and 2018, respectively. DPL excludes cash of $13 million and $8 million at December 31, 2019 and 2018, respectively. ACE excludes cash of $12 million and $7 million at December 31, 2019 and 2018, respectively, and includes long-term restricted cash of $14 million and $19 million at December 31, 2019 and 2018,(a)PHI excludes cash of $100 million and $74 million as of December 31, 2021 and 2020, respectively, and restricted cash of $3 million and none as of December 31, 2021 and 2020, respectively, and includes long-term restricted cash of none and $10 million as of December 31, 2021 and 2020, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. Pepco excludes cash of $34 million and $30 million as of December 31, 2021 and 2020, respectively, and restricted cash of $3 million and none as of December 31, 2021 and 2020, respectively. DPL excludes cash of $28 million and $15 million as of December 31, 2021 and 2020, respectively. ACE excludes cash of $29 million and $17 million as of December 31, 2021 and 2020, respectively, and includes long-term restricted cash of none and $10 million as of December 31, 2021 and 2020, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. |
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 17 — Fair Value of FinancialLevel 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 years ended December 31, 20192021 and 2018:2020: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exelon | | | ComEd | | PHI and Pepco | | | | | For the year ended December 31, 2021 | | NDT Fund Investments | | Mark-to-Market Derivatives | | Life Insurance Contracts | | Total | | | | | | | Mark-to-Market Derivatives | | Life Insurance Contracts | | | | | Balance as of January 1, 2021 | | $ | 497 | | | $ | 129 | | | $ | 34 | | | $ | 660 | | | | | | | | $ | (301) | | | $ | 34 | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total realized / unrealized gains (losses) | | | | | | | | | | | | | | | | | | | | | | Included in net income | | 5 | | | (812) | | (a) | 3 | | | (804) | | | | | | | | — | | | 3 | | | | | | | | | | | | | | | | | | | | | | | | | | | | Included in regulatory assets/liabilities | | 19 | | | 82 | | | — | | | 101 | | | | | | | | 82 | | (b) | — | | | | | | Change in collateral | | — | | | (196) | | | — | | | (196) | | | | | | | | — | | | — | | | | | | Purchases, sales, and settlements | | | | | | | | | | | | | | | | | | | | | | Purchases | | 4 | | | 162 | | | — | | | 166 | | | | | | | | — | | | — | | | | | | Sales | | — | | | (10) | | | — | | | (10) | | | | | | | | — | | | — | | | | | | | | | | | | | | | | | | | | | | | | | | | | Settlements | | (61) | | | — | |
| (2) | | | (63) | | | | | | | | — | | | (2) | | | | | | Transfers into Level 3 | | — | | | 19 | | (c) | 3 | | | 22 | | | | | | | | — | | | — | | | | | | Transfers out of Level 3 | | — | | | 313 | | (c) | — | | | 313 | | | | | | | | — | | | — | | | | | | Balance as of December 31, 2021 | | $ | 464 | | | $ | (313) | | | $ | 38 | | | $ | 189 | | | | | | | | $ | (219) | | | $ | 35 | | | | | | The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of December 31, 2021 | | $ | 5 | | | $ | (1,222) | | | $ | 3 | | | (1,214) | | | | | | | | $ | — | | | $ | 3 | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exelon | | Generation | | ComEd | | PHI and Pepco | | | For the year ended December 31, 2019 | Total | | NDT Fund Investments | | Mark-to-Market Derivatives | | Total Generation | | Mark-to-Market Derivatives | | Life Insurance Contracts | | Eliminated in Consolidation | Balance as of January 1, 2019 | $ | 907 |
| | $ | 543 |
| | $ | 575 |
|
| $ | 1,118 |
| | $ | (249 | ) | | $ | 38 |
| | $ | — |
| Total realized / unrealized gains (losses) | | |
| |
|
|
|
| | | | | | | Included in net income | (23 | ) | | 5 |
| | (31 | ) | (a) | (26 | ) | | — |
| | 3 |
| | — |
| Included in noncurrent payables to affiliates | — |
| | 34 |
| | — |
|
| 34 |
| | — |
| | — |
| | (34 | ) | Included in regulatory assets/liabilities | (18 | ) | | — |
| | — |
| | — |
| | (52 | ) | (b) | — |
| | 34 |
| Change in collateral | 138 |
| | — |
| | 138 |
|
| 138 |
| | — |
| | — |
| | — |
| Purchases, sales, issuances and settlements |
| | | | |
|
| | | | | | | Purchases | 176 |
| | 44 |
| | 132 |
| | 176 |
| | — |
| | — |
| | — |
| Sales | (23 | ) | | (21 | ) | | (2 | ) |
| (23 | ) | | — |
| | — |
| | — |
| Settlements | (89 | ) | | (94 | ) | | 5 |
|
| (89 | ) | | — |
| | — |
| | — |
| Transfers into Level 3 | 5 |
| | — |
| | 5 |
| (c) | 5 |
| | — |
| | — |
| | — |
| Transfers out of Level 3 | (5 | ) | | — |
| | (5 | ) | (c) | (5 | ) | | — |
| | — |
| | — |
| Balance as of December 31, 2019 | $ | 1,068 |
| | $ | 511 |
| | $ | 817 |
|
| $ | 1,328 |
| | $ | (301 | ) |
| $ | 41 |
|
| $ | — |
| The amount of total gains (losses) included in income attributed to the change in unrealized (losses) gains related to assets and liabilities held as of December 31, 2019 | $ | 359 |
| | $ | 5 |
| | $ | 351 |
| | $ | 356 |
| | $ | — |
| | $ | 3 |
| | $ | — |
|
298
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 1718 — Fair Value of Financial Assets and Liabilities
| | | | | | | | | | | | | | | | | | | | | | | Exelon | | | ComEd | | PHI and Pepco | | For the year ended December 31, 2020 | | For the year ended December 31, 2020 | | NDT Fund Investments | | Mark-to-Market Derivatives | | Life Insurance Contracts | | Total | | | Mark-to-Market Derivatives | | Life Insurance Contracts | | Balance as of January 1, 2020 | | Balance as of January 1, 2020 | | $ | 511 | | | $ | 516 | | | $ | 41 | | | $ | 1,068 | | | | $ | (301) | | | $ | 41 | | | | Exelon | | Generation | | ComEd | | PHI and Pepco | | | | For the year ended December 31, 2018 | Total | | NDT Fund Investments | | Mark-to-Market Derivatives | | Total Generation | | Mark-to-Market Derivatives | | Life Insurance Contracts | | Eliminated in Consolidation | | Balance as of January 1, 2018 | $ | 966 |
| | $ | 648 |
|
| $ | 552 |
|
| $ | 1,200 |
| | $ | (256 | ) | | $ | 22 |
| | $ | — |
| | Total realized / unrealized gains (losses) |
|
| |
|
|
|
|
|
| | | | | | | Total realized / unrealized gains (losses) | | | | | | Included in net income | (101 | ) | | — |
|
| (105 | ) | (a) | (105 | ) | | — |
| | 4 |
| | — |
| Included in net income | | 2 | | | (414) | | (a) | 3 | | | (409) | | | | — | | | 3 | | | Included in noncurrent payables to affiliates | — |
| | (1 | ) |
| — |
| | (1 | ) | | — |
| | — |
| | 1 |
| | | Included in regulatory assets/liabilities | 6 |
| | — |
| | — |
| | — |
| | 7 |
| (b) | — |
| | (1 | ) | Included in regulatory assets/liabilities | | 21 | | | — | | | — | | | 21 | | | | — | | (b) | — | | | Change in collateral | (5 | ) | | — |
|
| (5 | ) | | (5 | ) | | — |
| | — |
| | — |
| Change in collateral | | — | | | (53) | | | — | | | (53) | | | | — | | | — | | | Purchases, sales, issuances and settlements |
|
| |
|
|
| |
|
| | | | | | | | Purchases, sales, and settlements | | Purchases, sales, and settlements | | | | | | Purchases | 226 |
| | 36 |
|
| 190 |
| | 226 |
| | — |
| | — |
| | — |
| Purchases | | 8 | | | 143 | | | — | | | 151 | | | | — | | | — | | | Sales | (4 | ) | | — |
|
| (4 | ) |
| (4 | ) | | — |
| | — |
| | — |
| Sales | | — | | | (27) | | | — | | | (27) | | | | — | | | — | | | | Settlements | (123 | ) | | (140 | ) |
| 5 |
|
| (135 | ) | | — |
| | 12 |
| | — |
| Settlements | | (45) | | | — | |
| (10) | | | (55) | | | | — | | | (10) | | | Transfers into Level 3 | (22 | ) | | — |
|
| (22 | ) | (c) | (22 | ) | | — |
| | — |
| | — |
| Transfers into Level 3 | | — | | | (12) | | (c) | — | | | (12) | | | | — | | | — | | | Transfers out of Level 3 | (36 | ) | | — |
|
| (36 | ) | (c) | (36 | ) | | — |
| | — |
| | — |
| Transfers out of Level 3 | | — | | | (24) | | (c) | — | | | (24) | | | | — | | | — | | | Balance as of December 31, 2018 | $ | 907 |
| | $ | 543 |
|
| $ | 575 |
|
| $ | 1,118 |
| | $ | (249 | ) | | $ | 38 |
| | $ | — |
| | The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held as of December 31, 2018 | $ | 160 |
| | $ | (5 | ) |
| $ | 165 |
|
| $ | 160 |
| | $ | — |
| | $ | — |
| | $ | — |
| | Balance as of December 31, 2020 | | Balance as of December 31, 2020 | | $ | 497 | | | $ | 129 | | | $ | 34 | | | $ | 660 | | | | $ | (301) | | | $ | 34 | | | The amount of total gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of December 31, 2020 | | The amount of total gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of December 31, 2020 | | $ | 2 | | | $ | 6 | | | $ | 3 | | | $ | 11 | | | | $ | — | | | $ | 3 | | |
__________ | | (a) | Includes a reduction for the reclassification of $377 million and $265 million of realized gains due to the settlement of derivative contracts for the years ended December 31, 2019 and 2018, respectively. |
| | (b) | Includes $78 million of decreases in fair value and an increase for realized losses due to settlements of $26 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the year ended December 31, 2019. Includes $24 million of decreases in fair value and an increase for realized losses due to settlements of $17 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the year ended December 31, 2018. |
| | (c) | Transfers into and out 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. |
(a)Includes an addition of $410 million for realized losses and a reduction of $420 million for realized gains due to the settlement of derivative contracts for the years ended December 31, 2021 and 2020, respectively. (b)Includes $62 million of increases in fair value and an increase for realized losses due to settlements of $20 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the year ended December 31, 2021. Includes $33 million of decreases in fair value and an increase for realized losses due to settlements of $33 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the year ended December 31, 2020. (c)Transfers into and out 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 of the total realized and unrealized gains (losses) included in income for Level 3 assets and liabilities measured at fair value on a recurring basis during the years ended December 31, 20192021 and 2018:2020: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exelon | | | | PHI and Pepco | | Operating Revenues | | Purchased Power and Fuel | | Operating and Maintenance | | Other, net | | | | | | | | Operating and Maintenance | | | | | | | | | | | | | | | | | Total (losses) gains included in net income for the year ended December 31, 2021 | $ | (1,343) | | | $ | 531 | | | $ | 3 | | | $ | 5 | | | | | | | | | $ | 3 | | | | | | | | | | | | | | | | | | Total unrealized (losses) gains for the year ended December 31, 2021 | (1,577) | | | 355 | | | 3 | | | 5 | | | | | | | | | 3 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exelon | | | | PHI and Pepco | | Operating Revenues | | Purchased Power and Fuel | | Operating and Maintenance | | Other, net | | | | | | | | Operating and Maintenance | | | | | | | | | | | | | | | | | Total (losses) gains included in net income for the year ended December 31, 2020 | $ | (404) | | | $ | (10) | | | $ | 3 | | | $ | 2 | | | | | | | | | $ | 3 | | | | | | | | | | | | | | | | | | Total unrealized (losses) gains for the year ended December 31, 2020 | (31) | | | 37 | | | 3 | | | 2 | | | | | | | | | 3 | |
299 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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 gains (losses) included in net income for the year ended December 31, 2019 | $ | 219 |
| | $ | (245 | ) | | $ | 3 |
| | $ | 5 |
| | $ | 219 |
| | $ | (245 | ) | | $ | 5 |
| | $ | 3 |
| Change in the unrealized gains (losses) relating to assets and liabilities held for the year ended December 31, 2019 | 546 |
| | (195 | ) | | 3 |
| | 5 |
| | 546 |
| | (195 | ) | | 5 |
| | 3 |
|
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 1718 — 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) gains included in net income for the year ended December 31, 2018 | $ | (7 | ) | | $ | (93 | ) | | $ | 4 |
| | $ | 3 |
| | $ | (7 | ) | | $ | (93 | ) | | $ | 3 |
| | $ | 4 |
| Change in the unrealized gains (losses) relating to assets and liabilities held for the year ended December 31, 2018 | 144 |
| | 21 |
| | — |
| | (2 | ) | | 144 |
| | 21 |
| | (2 | ) | | — |
|
Valuation Techniques Used to Determine Fair Value Cash Equivalents (All Registrants). Investments with original maturities of three months or less when purchased, including mutual and money market funds, are considered cash equivalents. The fair values are based on observable market prices and, therefore, are included in the recurring fair value measurements hierarchy as Level 1. NDT Fund Investments (Exelon and Generation)(Exelon). The trust fund investments have been established to satisfy Generation’s and CENG'sGeneration's nuclear decommissioning obligations as required by the NRC. The NDT funds hold debt and equity securities directly and indirectly through commingled funds and mutual funds, which are included in equities and fixed income. Generation’s and CENG's NDT fund investments policies outline investment guidelines for the trusts and limit the trust funds’ exposures to investments in highly illiquid markets and other alternative investments, including private credit, private equity, and real estate. Investments with maturities of three months or less when purchased, including certain short-term fixed income securities are considered cash equivalents and included in the recurring fair value measurements hierarchy as Level 1 or Level 2. Equities. These investments consist of individually held equity securities, equity mutual funds, and equity commingled funds in domestic and foreign markets. With respect to individually held equity securities, the trustees obtain prices from pricing services, whose prices are generally obtained from direct feeds from market exchanges, which Exelon and Generation areis able to independently corroborate. Equity securities held individually, including real estate investment trusts, rights, and warrants, are primarily traded on exchanges that contain only actively traded securities due to the volume trading requirements imposed by these exchanges. The equity securities that are held directly by the trust funds are valued based on quoted prices in active markets and categorized as Level 1. Certain equity securities have been categorized as Level 2 because they are based on evaluated prices that reflect observable market information, such as actual trade information or similar securities. Certain private placement equity securities are categorized as Level 3 because they are not publicly traded and are priced using significant unobservable inputs. Equity commingled funds and mutual funds are maintained by investment companies, and fund investments are held in accordance with a stated set of fund objectives. The values of some of these funds are publicly quoted. For mutual funds which are publicly quoted, the funds are valued based on quoted prices in active markets and have been categorized as Level 1. For equity commingled funds and mutual funds which are not publicly quoted, the fund administrators value the funds using the NAV per fund share, derived from the quoted prices in active markets ofon the underlying securities and are not classified within the fair value hierarchy. These investments can typically can be redeemed monthly or more frequently, with 30 or less days of notice and without further restrictions. Fixed income. For fixed income securities, which consist primarily of corporate debt securities, U.S. government securities, foreign government securities, municipal bonds, asset and mortgage-backed securities, commingled funds, mutual funds, and derivative instruments, the trustees obtain multiple prices from pricing vendors whenever possible, which enables cross-provider validations in addition to checks for unusual daily movements. A primary price source is identified based on asset type, class, or issue for each security. With respect to individually held fixed income securities, the trustees monitor prices supplied by pricing services and may use a supplemental price source or change the primary price source of a given security if the portfolio managers challenge an assigned price and the trustees determine that another price source is considered to be preferable. Exelon and Generation havehas obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, Exelon and Generation selectively corroboratecorroborates the fair values of securities by comparison to other market-based price sources. Investments in U.S. Treasury securities have been categorized as Level 1 because they trade in highly-liquid and transparent markets. Certain private placement fixed income securities have been categorized as Level 3 because they are priced using certain significant unobservable inputs and are typically illiquid. The remaining fixed income securities, including certain other fixed income investments,
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 17 — Fair Value of Financial Assets and Liabilities
are based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences and are categorized as Level 2. Other fixed income investments primarily consist of fixed income commingled funds and mutual funds, which are maintained by investment companies and hold fund investments in accordance with a stated set of fund objectives. The values of some of these funds are publicly quoted. For mutual funds which are publicly quoted, the funds are valued based on quoted prices in active markets and have been categorized as Level 1. For fixed income commingled funds and mutual funds which are not publicly quoted, the fund administrators value the funds using the NAV per fund share, derived from the quoted prices in active markets of the underlying securities
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 18 — Fair Value of Financial Assets and Liabilities and are not classified within the fair value hierarchy. These investments typically can be redeemed monthly or more frequently, with 30 or less days of notice and without further restrictions. Derivative instruments. These instruments, consisting primarily of futures and swaps to manage risk, are recorded at fair value. Over-the-counter derivatives are valued daily, based on quoted prices in active markets and trade in open markets, and have been categorized as Level 1. Derivative instruments other than over-the-counter derivatives are valued based on external price data of comparable securities and have been categorized as Level 2. Private credit. Private credit investments primarily consist of investments in private debt strategies. These investments are generally less liquid assets with an underlying term of 3 to 5 years and are intended to be held to maturity. The fair value of these investments is determined by the fund manager or administrator using a combination of valuation models including cost models, market models, and include unobservable inputs such as cost, operating results,income models and discounted cash flows.typically cannot be redeemed until maturity of the term loan. Private credit investments held directly by Exelon and Generation are categorized as Level 3 because they are based largely on inputs that are unobservable and utilize complex valuation models. PrivateFor 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. Managed private credit fund investments with multiple investors are not classified within the fair value hierarchy because their fair value is determined using NAV or its equivalent as a practical expedient. Private equity. These investments include those in limited partnerships that invest in operating companies that are not publicly traded on a stock exchange such as leveraged buyouts, growth capital, venture capital, distressed investments, and investments in natural resources. 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 valuations are reported by the fund manager and are based on the valuation of the underlying investments, which include unobservable inputs such as cost, operating results, discounted future cash flows, and market based comparable data. These valuation inputs are unobservable. The fair value of private equity investments is determined using NAV or its equivalent as a practical expedient, and therefore, these investments are not classified within the fair value hierarchy. Real estate. These investments are funds with a direct investment in pools of real estate properties. These funds are valuedreported by investment managersthe fund manager and are generally based on a periodic basis using pricing models that use independent appraisals of the underlying investments from sources with professional qualifications.qualifications, typically using a combination of market based comparable data and discounted cash flows. These valuation inputs are not highly observable.unobservable. Certain real estate investments 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. The remaining liquid real estate investments are generally redeemable from the investment vehicle quarterly, with 30 to 90 days of notice. The fair value of real estate investments is determined using NAV or its equivalent as a practical expedient, and therefore, these investments are not classified within the fair value hierarchy. GenerationExelon evaluated its NDT portfolios for the existence of significant concentrations of credit risk as of December 31, 2019.2021. Types of concentrations that were evaluated include, but are not limited to, investment concentrations in a single entity, type of industry, foreign country, and individual fund. As of December 31, 2019,2021, there were no significant concentrations (generally defined as greater than 10 percent) of risk in Generation'sthe NDT assets.
See Note 910 — Asset Retirement Obligations for additional information on the NDT fund investments. See Note 1415 — Retirement Benefits for the valuation techniques used for hedge fund investments. Rabbi Trust Investments (Exelon, Generation, PECO, BGE, PHI, Pepco, DPL, and ACE). The Rabbi trusts were established to hold assets related to deferred compensation plans existing for certain active and retired members of Exelon’s executive management and directors. The Rabbi trusts' assets are included in investments in the Registrants’ Consolidated Balance Sheets and consist primarily of money market funds, mutual funds, fixed income securities, and life insurance policies. Money market funds and mutual funds are publicly quoted and have been categorized as Level 1 given the clear observability of the prices. The fair values of fixed income securities are based on evaluated prices that reflect observable market information, such as actual trade information or similar securities, adjusted for observable differences and are categorized in Level 2. The life insurance policies are valued using the cash surrender value of the policies, net of loans against those policies, which is provided by a third-party. Certain life insurance policies, which consist primarily of mutual funds that are priced based on observable market data, have been categorized as Level 2 because the life insurance policies
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 1718 — Fair Value of Financial Assets and Liabilities
data, have been categorized as Level 2 because the life insurance policies can be liquidated at the reporting date for the value of the underlying assets. Life insurance policies that are valued using unobservable inputs have been categorized as Level 3, where the fair value is determined based on the cash surrender value of the policy, which contains unobservable inputs and assumptions. Because Exelon relies on its third-party insurance provider to develop the inputs without adjustment for the valuations of its Level 3 investments, quantitative information about significant unobservable inputs used in valuing these investments is not reasonably available to Exelon. Therefore, Exelon has not disclosed such inputs.
Deferred Compensation Obligations (All Registrants). The Registrants’ deferred compensation plans allow participants to defer certain cash compensation into a notional investment account. The Registrants include such plans in other current and noncurrent liabilities in their Consolidated Balance Sheets. The value of the Registrants’ deferred compensation obligations is based on the market value of the participants’ notional investment accounts. The underlying notional investments are comprised primarily of equities, mutual funds, commingled funds, and fixed income securities which are based on directly and indirectly observable market prices. Since the deferred compensation obligations themselves are not exchanged in an active market, they are categorized as Level 2 in the fair value hierarchy. The value of certain employment agreement obligations (which are included with the Deferred Compensation Obligation in the tables above) are based on a known and certain stream of payments to be made over time and are categorized as Level 2 within the fair value hierarchy. Investments in Equities (Exelon).Exelon holds certain investments in equity securities with readily determinable fair values in addition to those held within the NDT funds. These equity securities are valued based on quoted prices in active markets and are categorized as Level 1. Deferred Purchase Price Consideration (Exelon). Exelon has DPP consideration for the sale of certain receivables of retail electricity. This amount is valued based on the sales price of the receivables net of allowance for credit losses based on accounts receivable aging historical experience coupled with specific identification through a credit monitoring process, which considers current conditions and forward-looking information such as industry trends, macroeconomic factors, changes in the regulatory environment, external credit ratings, publicly available news, payment status, payment history, and the exercise of collateral calls. Since the DPP consideration is based on the sales price of the receivables, it is categorized as Level 2 in the fair value hierarchy. See Note 6 — Accounts Receivable for additional information on the sale of certain receivables. Mark-to-Market Derivatives (Exelon Generation, ComEd, PHI and DPL)ComEd). Derivative contracts are traded in both exchange-based and non-exchange-based markets. Exchange-based derivatives that are valued using unadjusted quoted prices in active markets are categorized in Level 1 in the fair value hierarchy. Certain derivatives’ pricing is verified using indicative price quotations available through brokers or over-the-counter, on-line exchanges and are categorized in Level 2. These price quotations reflect the average of the bid-ask, mid-point prices and are obtained from sources that the Registrants believe provide the most liquid market for the commodity. The price quotations are reviewed and corroborated to ensure the prices are observable and representative of an orderly transaction between market participants. This includes consideration of actual transaction volumes, market delivery points, bid-ask spreads, and contract duration. The remainder of derivative contracts are valued using the Black model, an industry standard option valuation model. The Black model takes into account inputs such as contract terms, including maturity, and market parameters, including assumptions of the future prices of energy, interest rates, volatility, credit worthiness, and credit spread. For derivatives that trade in liquid markets, such as generic forwards, swaps, and options, model inputs are generally observable. Such instruments are categorized in Level 2. The Registrants’ derivatives are predominantly at liquid trading points. For derivatives that trade in less liquid markets with limited pricing information, model inputs generally would include both observable and unobservable inputs. These valuations may include an estimated basis adjustment from an illiquid trading point to a liquid trading point for which active price quotations are available. Such instruments are categorized in Level 3. For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations whose contract tenure extends into unobservable periods. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks such as liquidity, volatility, and contract duration. Such instruments are categorized in Level 3 as the model inputs generally are not observable. Forward price curves for the power market utilized by the front office to manage the portfolio, are reviewed and verified by the middle office, and used for financial reporting by the back office. The Registrants consider credit and
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 18 — Fair Value of Financial Assets and Liabilities nonperformance risk in the valuation of derivative contracts categorized in Level 2 and 3, including both historical and current market data, in itstheir assessment of credit and nonperformance risk by counterparty. Due to master netting agreements and collateral posting requirements, the impacts of credit and nonperformance risk were not material to the financial statements. Disclosed below is detail surrounding the Registrants’ significant Level 3 valuations. The calculated fair value includes marketability discounts for margining provisions and other attributes. Generation’sThe Level 3 balance related to Generation generally consists of forward sales and purchases of power and natural gas and certain transmission congestion contracts. GenerationExelon utilizes various inputs and factors including market data and assumptions that market participants would use in pricing assets or liabilities as well as assumptions about the risks inherent in the inputs to the valuation technique. The inputs and factors include forward commodity prices, commodity price volatility, contractual volumes, delivery location, interest rates, credit quality of counterparties, and credit enhancements.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 17 — Fair Value of Financial Assets and Liabilities
For commodity derivatives, the primary input to the valuation models is the forward commodity price curve for each instrument. Forward commodity price curves are derived by risk management for liquid locations and by the traders and portfolio managers for illiquid locations. All locations are reviewed and verified by risk management considering published exchange transaction prices, executed bilateral transactions, broker quotes, and other observable or public data sources. The relevant forward commodity curve used to value each of the derivatives depends on a number of factors, including commodity type, delivery location, and delivery period. Price volatility varies by commodity and location. When appropriate, GenerationExelon discounts future cash flows using risk free interest rates with adjustments to reflect the credit quality of each counterparty for assets and Generation’s own credit quality for liabilities. The level of observability of a forward commodity price varies generally due to the delivery location and delivery period. Certain delivery locations including PJM West Hub (for power) and Henry Hub (for natural gas) are more liquid and prices are observable for up to three years in the future. The observability period of volatility is generally shorter than the underlying power curve used in option valuations. The forward curve for a less liquid location is estimated by using the forward curve from the liquid location and applying a spread to represent the cost to transport the commodity to the delivery location. This spread does not typically represent a majority of the instrument’s market price. As a result, the change in fair value is closely tied to liquid market movements and not a change in the applied spread. The change in fair value associated with a change in the spread is generally immaterial. An average spread calculated across all Level 3 power and gas delivery locations is approximately $2.22$3.33 and $0.54$0.53 for power and natural gas, respectively. Many of the commodity derivatives are short term in nature and thus a majority of the fair value may be based on observable inputs even though the contract as a whole must be classified as Level 3. On December 17, 2010, ComEd entered into several 20-year floating to fixed energy swap contracts with unaffiliated suppliers for the procurement of long-term renewable energy and associated RECs. See Note 1516 — Derivative Financial Instruments for additional information. The fair value of these swaps has been designated as a Level 3 valuation due to the long tenure of the positions and internal modeling assumptions. The modeling assumptions include using natural gas heat rates to project long term forward power curves adjusted by a renewable factor that incorporates time of day and seasonality factors to reflect accurate renewable energy pricing. In addition, marketability reserves are applied to the positions based on the tenor and supplier risk. See Note 1516 — Derivative Financial Instruments for additional information on mark-to-market derivatives.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 1718 — Fair Value of Financial Assets and Liabilities
The following table presents the significant inputs to the forward curve used to value these positions: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Type of trade | | Fair Value as of December 31, 2021 | | Fair Value as of December 31, 2020 | | Valuation Technique | | Unobservable Input | | 2021 Range & Arithmetic Average | | 2020 Range & Arithmetic Average | Mark-to-market derivatives—Economic hedges (Exelon)(a)(b) | | $ | (66) | | | $ | 245 | | | Discounted Cash Flow | | Forward power price | | $8.86 | - | $481 | $55 | | $2.25 | - | $163 | $30 | | | | | | | | | Forward gas price | | $1.69 | - | $17 | $3.50 | | $1.57 | - | $7.88 | $2.59 | | | | | | | Option Model | | Volatility percentage | | 24% | - | 284% | 56% | | 11% | - | 237% | 32% | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Mark-to-market derivatives (Exelon and ComEd) | | $ | (219) | | | $ | (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 | | 92% | - | 120% | 97% | | 91% | - | 123% | 99% |
| | | | | | | | | | | | | | | | | | | Type of trade | | Fair Value at December 31, 2019 | Fair Value at December 31, 2018 | Valuation Technique | | Unobservable Input | | 2019 Range | 2018 Range | Mark-to-market derivatives—Economic hedges (Exelon and Generation)(a)(b) | | $ | 558 |
| $ | 443 |
| Discounted Cash Flow | | Forward power price | | $9 | - | $180 | $12 | - | $174 | | | | | | | Forward gas price | | $0.83 | - | $10.72 | $0.78 | - | $12.38 | | | | | Option Model | | Volatility percentage | | 8% | - | 236% | 10% | - | 277% | | | | | | | | | | | | | | | Mark-to-market derivatives—Proprietary trading (Exelon and Generation)(a)(b) | | $ | 45 |
| $ | 56 |
| Discounted Cash Flow | | Forward power price | | $25 | - | $180 | $14 | - | $174 | | | | | | |
| | | | | | | | Mark-to-market derivatives (Exelon and ComEd) | | $ | (301 | ) | $ | (249 | ) | Discounted Cash Flow | | Forward heat rate(c) | | 9X | - | 10X | 10X | - | 11X | | | | | | | Marketability reserve | | 3% | - | 7% | 4% | - | 8% | | | | | | | Renewable factor | | 91% | - | 123% | 86% | - | 120% |
________________(a)These positions relate to Generation and the valuation techniques, unobservable inputs, ranges, and arithmetic averages are the same for the asset and liability positions.
| | (a) | The valuation techniques, unobservable inputs and ranges are the same for the asset and liability positions. |
| | (b) | The fair values do not include cash collateral posted on level three positions of $214 million and $76 million as of December 31, 2019 and December 31, 2018, 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. |
(b)The fair values do not include cash collateral (received)/posted on level three positions of $(34) million and $162 million as of December 31, 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’sExelon’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 GenerationExelon the obligation or option to purchase a commodity), with offsetting impacts to short positions (contracts that give GenerationExelon 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 factors 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.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 1819 — Commitments and Contingencies
18.19. Commitments and Contingencies (All Registrants)
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 December 31, 2019:2021: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Description | Exelon | | PHI | | Pepco | | DPL | | ACE | Total commitments | $ | 513 | | | $ | 320 | | | $ | 120 | | | $ | 89 | | | $ | 111 | | Remaining commitments(a) | 68 | | | 58 | | | 48 | | | 6 | | | 4 | |
| | | | | | | | | | | | | | | | | | | | | Description | Exelon | | PHI | | Pepco | | DPL | | ACE | Total commitments | $ | 513 |
| | $ | 320 |
| | $ | 120 |
| | $ | 89 |
| | $ | 111 |
| Remaining commitments(a) | $ | 101 |
| | $ | 79 |
| | $ | 65 |
| | $ | 8 |
| | $ | 6 |
|
___________________(a)Remaining commitments extend through 2026 and include rate credits, energy efficiency programs, and delivery system modernization.
| | (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 $127 million, which will generate future earnings at Exelon and Generation.$135 million. 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 December 31, 2019, 272021, approximately 33 MWs of new generation were developed and Exelon and Generation have incurred costs of $120$121 million. Development of the remaining 4 MWs of new generation will be completed by Generation in 2022. 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 March 2019. The third and final 40 MW wind REC tranche will be conducted in 2022.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 1819 — Commitments and Contingencies
Commercial Commitments (All Registrants). The Registrants'Registrants' commercial commitments as of December 31, 2019,2021, representing commitments potentially triggered by future events were as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Expiration within | Exelon | Total | | 2022 | | 2023 | | 2024 | | 2025 | | 2026 | | 2027 and beyond | Letters of credit | $ | 2,397 | | | $ | 2,296 | | | $ | 101 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | Surety bonds(a) | 1,008 | | | 989 | | | 17 | | | 2 | | | — | | | — | | | — | | Financing trust guarantees | 378 | | | — | | | — | | | — | | | — | | | — | | | 378 | | Guaranteed lease residual values(b) | 31 | | | — | | | 5 | | | 6 | | | 6 | | | 5 | | | 9 | | Total commercial commitments | $ | 3,814 | | | $ | 3,285 | | | $ | 123 | | | $ | 8 | | | $ | 6 | | | $ | 5 | | | $ | 387 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ComEd | | | | | | | | | | | | | | Letters of credit | $ | 7 | | | $ | 7 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | Surety bonds(a) | 17 | | | 15 | | | — | | | 2 | | | — | | | — | | | — | | Financing trust guarantees | 200 | | | — | | | — | | | — | | | — | | | — | | | 200 | | Total commercial commitments | $ | 224 | | | $ | 22 | | | $ | — | | | $ | 2 | | | $ | — | | | $ | — | | | $ | 200 | | | | | | | | | | | | | | | | PECO | | | | | | | | | | | | | | Letters of credit | $ | 1 | | | $ | 1 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | Surety bonds(a) | 2 | | | 2 | | | — | | | — | | | — | | | — | | | — | | Financing trust guarantees | 178 | | | — | | | — | | | — | | | — | | | — | | | 178 | | Total commercial commitments | $ | 181 | | | $ | 3 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 178 | | | | | | | | | | | | | | | | BGE | | | | | | | | | | | | | | Letters of credit | $ | 2 | | | $ | 2 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | Surety bonds(a) | 3 | | | 3 | | | — | | | — | | | — | | | — | | | — | | Total commercial commitments | $ | 5 | | | $ | 5 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | | | | | | | | | | | | | | PHI | | | | | | | | | | | | | | | | | | | | | | | | | | | | Surety bonds(a) | $ | 23 | | | $ | 23 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | Guaranteed lease residual values(b) | 31 | | | — | | | 5 | | | 6 | | | 6 | | | 5 | | | 9 | | Total commercial commitments | $ | 54 | | | $ | 23 | | | $ | 5 | | | $ | 6 | | | $ | 6 | | | $ | 5 | | | $ | 9 | | | | | | | | | | | | | | | | Pepco | | | | | | | | | | | | | | | | | | | | | | | | | | | | Surety bonds(a) | $ | 14 | | | $ | 14 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | Guaranteed lease residual values(c) | 10 | | | — | | | 1 | | | 2 | | | 2 | | | 2 | | | 3 | | Total commercial commitments | $ | 24 | | | $ | 14 | | | $ | 1 | | | $ | 2 | | | $ | 2 | | | $ | 2 | | | $ | 3 | | | | | | | | | | | | | | | | DPL | | | | | | | | | | | | | | | | | | | | | | | | | | | | Surety bonds(a) | $ | 5 | | | $ | 5 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | Guaranteed lease residual values(b) | 13 | | | — | | | 2 | | | 3 | | | 2 | | | 2 | | | 4 | | Total commercial commitments | $ | 18 | | | $ | 5 | | | $ | 2 | | | $ | 3 | | | $ | 2 | | | $ | 2 | | | $ | 4 | | | | | | | | | | | | | | | | ACE | | | | | | | | | | | | | | Surety bonds(a) | $ | 4 | | | $ | 4 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | Guaranteed lease residual values(b) | 8 | | | — | | | 2 | | | 1 | | | 2 | | | 1 | | | 2 | | Total commercial commitments | $ | 12 | | | $ | 4 | | | $ | 2 | | | $ | 1 | | | $ | 2 | | | $ | 1 | | | $ | 2 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Expiration within | Exelon | Total | | 2020 | | 2021 | | 2022 | | 2023 | | 2024 | | 2025 and beyond | Letters of credit | $ | 1,455 |
| | $ | 1,314 |
| | $ | 141 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| Surety bonds(a) | 855 |
| | 809 |
| | 46 |
| | — |
| | — |
| | — |
| | — |
| Financing trust guarantees | 378 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 378 |
| Guaranteed lease residual values(b) | 26 |
| | 2 |
| | 2 |
| | 4 |
| | 3 |
| | 6 |
| | 10 |
| Total commercial commitments | $ | 2,714 |
| | $ | 2,125 |
| | $ | 189 |
| | $ | 4 |
| | $ | 3 |
| | $ | 6 |
| | $ | 388 |
| | | | | | | | | | | | | | | Generation | | | | | | | | | | | | | | Letters of credit | $ | 1,440 |
| | $ | 1,302 |
| | $ | 138 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| Surety bonds(a) | 670 |
| | 662 |
| | 8 |
| | — |
| | — |
| | — |
| | — |
| Total commercial commitments | $ | 2,110 |
| | $ | 1,964 |
| | $ | 146 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | | | | | | | | | | | | | | ComEd | | | | | | | | | | | | | | Letters of credit | $ | 7 |
| | $ | 7 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| Surety bonds(a) | 50 |
| | 48 |
| | 2 |
| | — |
| | — |
| | — |
| | — |
| Financing trust guarantees | 200 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 200 |
| Total commercial commitments | $ | 257 |
| | $ | 55 |
| | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 200 |
| | | | | | | | | | | | | | | PECO | | | | | | | | | | | | | | Surety bonds(a) | $ | 9 |
| | $ | 9 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| Financing trust guarantees | 178 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 178 |
| Total commercial commitments | $ | 187 |
| | $ | 9 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 178 |
| | | | | | | | | | | | | | | BGE | | | | | | | | | | | | | | Letters of credit | $ | 2 |
| | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| Surety bonds(a) | 3 |
| | 3 |
| | — |
| | — |
| | — |
| | — |
| | — |
| Total commercial commitments | $ | 5 |
| | $ | 5 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | | | | | | | | | | | | | | PHI | | | | | | | | | | | | | | Surety bonds(a) | $ | 21 |
| | $ | 21 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| Guaranteed lease residual values(b) | 26 |
| | 2 |
| | 2 |
| | 4 |
| | 3 |
| | 6 |
| | 10 |
| Total commercial commitments | $ | 47 |
| | $ | 23 |
| | $ | 2 |
| | $ | 4 |
| | $ | 3 |
| | $ | 6 |
| | $ | 10 |
| | | | | | | | | | | | | | | Pepco | | | | | | | | | | | | | | Surety bonds(a) | $ | 14 |
| | $ | 14 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| Guaranteed lease residual values(b) | 9 |
| | — |
| | — |
| | 1 |
| | 1 |
| | 2 |
| | 5 |
| Total commercial commitments | $ | 23 |
| | $ | 14 |
| | $ | — |
| | $ | 1 |
| | $ | 1 |
| | $ | 2 |
| | $ | 5 |
| | | | | | | | | | | | | | | DPL | | | | | | | | | | | | | | Surety bonds(a) | $ | 4 |
| | $ | 4 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| Guaranteed lease residual values(b) | 11 |
| | 1 |
| | 1 |
| | 2 |
| | 1 |
| | 3 |
| | 3 |
| Total commercial commitments | $ | 15 |
| | $ | 5 |
| | $ | 1 |
| | $ | 2 |
| | $ | 1 |
| | $ | 3 |
| | $ | 3 |
| | | | | | | | | | | | | | | ACE | | | | | | | | | | | | | | Surety bonds(a) | $ | 3 |
| | $ | 3 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| Guaranteed lease residual values(b) | 7 |
| | 1 |
| | 1 |
| | 1 |
| | 1 |
| | 1 |
| | 2 |
| Total commercial commitments | $ | 10 |
| | $ | 4 |
| | $ | 1 |
| | $ | 1 |
| | $ | 1 |
| | $ | 1 |
| | $ | 2 |
|
__________(a)Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds. (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 million guaranteed by Exelon and PHI, of which $25 million, $31 million, and $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. 306
_________
| | (a) | Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds. |
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 1819 — 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 $69 million guaranteed by Exelon and PHI, of which $23 million, $29 million and $18 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.
|
Nuclear Insurance (Exelon and Generation)(Exelon) Generation is subject to liability, property damage, and other risks associated with major incidents at any of its nuclear stations. Generation has mitigated its financial exposure to these risks through insurance and other industry risk-sharing provisions. The Price-Anderson Act was enacted to ensure the availability of funds for public liability claims arising from an incident at any of the U.S. licensed nuclear facilities and to limit the liability of nuclear reactor owners for such claims from any single incident. As of December 31, 2019,2021, the current liability limit per incident is $13.9$13.5 billion and is subject to change to account for the effects of inflation and changes in the number of licensed reactors at least once every five years with the last adjustment effective November 1, 2018. In accordance with the Price-Anderson Act, Generation maintains financial protection at levels equal to the amount of liability insurance available from private sources through the purchase of private nuclear energy liability insurance for public liability claims that could arise in the event of an incident. Effective January 1, 2017, the required amount of nuclear energy liability insurance purchased is $450 million for each operating site. Claims exceeding that amount are covered through mandatory participation in a financial protection pool, as required by the Price Anderson-Act, which provides the additional $13.5$13.1 billion per incident in funds available for public liability claims. Participation in this secondary financial protection pool requires the operator of each reactor to fund its proportionate share of costs for any single incident that exceeds the primary layer of financial protection. Exelon’sGeneration’s share of this secondary layer would be approximately $2.9$2.8 billion, however any amounts payable under this secondary layer would be capped at $434$413 million per year. In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay public liability claims exceeding the $13.9$13.5 billion limit for a single incident. As part of the execution of the NOSA on April 1, 2014, Generation executed an Indemnity Agreement pursuant to which Generation agreed to indemnify EDF and its affiliates 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. See Note 22 — Variable Interest Entities for additional information on Generation’s operations relating to CENG.
Generation is required each year to report to the NRC the current levels and sources of property insurance that demonstrates Generation possesses sufficient financial resources to stabilize and decontaminate a reactor and reactor station site in the event of an accident. The property insurance maintained for each facility is currently provided through insurance policies purchased from NEIL, an industry mutual insurance company of which Generation is a member. NEIL may declare distributions to its members as a result of favorable operating experience. In recent years, NEIL has made distributions to its members, but Generation cannot predict the level of future distributions or if they will continue at all.members. Generation's portion of the annual distribution declared by NEIL is estimated to be $113 million for 2021, and was $75 million and $136 million for 2020 and 2019, and was $58 million and $60 million for 2018 and 2017, respectively. In addition, in March 2018, NEIL declared a supplemental distribution. Generation's portion of the supplemental distribution declared by NEIL was $31 million. The distributions were recorded as a reduction to Operating and maintenance expense within Exelon and Generation’sExelon’s Consolidated Statements of Operations and Comprehensive Income. Premiums paid to NEIL by its members are also subject to a potential assessment for adverse loss experience in the form of a retrospective premium obligation. NEIL has never assessed this retrospective premium since its formation in 1973, and Generation cannot predict the level of future assessments, if any. The current maximum aggregate annual retrospective premium obligation for Generation is approximately $334 million. NEIL requires its members to maintain an investment grade credit rating or to ensure collectability of their annual retrospective premium obligation by providing a financial guarantee, letter of credit, deposit premium, or some other means of assurance.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 18 — Commitments and Contingencies
NEIL provides “all risk” property damage, decontamination and premature decommissioning insurance for each station for losses resulting from damage to its nuclear plants, either due to accidents or acts of terrorism. If the decision is made to decommission the facility, a portion of the insurance proceeds will be allocated to a fund, which Generation is required by the NRC to maintain, to provide for decommissioning the facility. In the event of an insured loss, Generation is unable to predict the timing of the availability of insurance proceeds to Generation and the amount of such proceeds that would be available. In the event that one or more acts of terrorism cause accidental property damage within a twelve-month period from the first accidental property damage under one or more policies for all insured plants, the maximum recovery by Exelon will be an aggregate of $3.2 billion plus such additional amounts as the insurer may recover for all such losses from reinsurance, indemnity and any other source, applicable to such losses.
For its insured losses, Generation is self-insured to the extent that losses are within the policy deductible or exceed the amount of insurance maintained. Uninsured losses and other expenses, to the extent not recoverable from insurers or the nuclear industry, could also be borne by Generation. Any such losses could have a material adverse effect on Exelon’s and Generation’s financial statements.
Spent Nuclear Fuel Obligation (Exelon and Generation)(Exelon) Under the NWPA, the DOE is responsible for the development of a geologic repository for and the disposal of SNF and high-level radioactive waste. As required by the NWPA, Generation is a party to contracts with the DOE (Standard Contracts) to provide for disposal of SNF from Generation’s nuclear generating stations. In accordance with the NWPA and the Standard Contracts, Generation historically had paid the DOE one mill ($0.001)($0.001) per kWh of net nuclear generation for the cost of SNF disposal. Due to the lack of a viable disposal program, the DOE reduced the SNF disposal fee to zero in May 2014. Until a new fee structure is in effect, Exelon and Generation will not accrue any further costs related to SNF disposal fees. This fee may be adjusted prospectively to ensure full cost recovery. Generation currently assumes the DOE will begin accepting SNF in 20302035 and uses that date for purposes of estimating the nuclear decommissioning asset retirement obligations. The SNF acceptance date assumption is based on management’s estimates of the amount of time required for DOE to select a site location and develop the necessary infrastructure for long-term SNF storage. The NWPA and the Standard Contracts required the DOE to begin taking possession of SNF generated by nuclear generating units by no later than January 31, 1998. The DOE, however, failed to meet that deadline and its performance is expected to be delayed significantly. In August 2004, Generation and the DOJ, in close consultation with the DOE, reached a settlement under which the government agreed to reimburse Generation, subject to certain damage limitations based on the extent of the government’s breach, for costs associated with storage of SNF at Generation’sGeneration’s nuclear stations pending the DOE’s fulfillment of its obligations. Generation’s settlement agreement does not include FitzPatrick and FitzPatrick does not currently have a settlement agreement in place. Calvert Cliffs, Ginna, and Nine Mile Point each have separate settlement agreements in place with the DOE which were
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 19 — Commitments and Contingencies extended during 20172020 to provide for the reimbursement of SNF storage costs through December 31, 2019. Generation expects2022. FitzPatrick also has a separate settlement agreement in place with the termsDOE which was established in 2021 to provide for eachreimbursement of the settlement agreements to be extended during 2020 for another three years to cover SNF storage costs through December 31, 2022. Generation submits annual reimbursement requests to the DOE for costs associated with the storage of SNF. In all cases, reimbursement requests are made only after costs are incurred and only for costs resulting from DOE delays in acceptingaccepting the SNF. UnderUnder the settlement agreements, Generation has received total cumulative cash reimbursements of $1,492 million through December 31, 2021 for costs incurred as follows:
| | | | | | | | | | Total | | Net(a) | Cumulative cash reimbursements
| $ | 1,288 |
| | $ | 1,113 |
|
__________
| | (a) | Total afterincurred. After considering the amounts due to co-owners of certain nuclear stations and to the former owner of Oyster Creek. |
Combined Notescertain nuclear stations and to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 18 — Commitments and Contingencies
the former owner of Oyster Creek, Generation received net cumulative cash reimbursements of $1,294 million.As of December 31, 20192021 and 2018,2020, the amount of SNF storage costs for which reimbursement has been or will be requested from the DOE under the DOE settlement agreements is as follows: | | | December 31, 2019 | | December 31, 2018 | | December 31, 2021 | | December 31, 2020 | DOE receivable - current(a) | $ | 249 |
| | $ | 124 |
| DOE receivable - current(a) | $ | 241 | | | $ | 129 | | DOE receivable - noncurrent(b) | 30 |
| | 15 |
| DOE receivable - noncurrent(b) | 85 | | | 70 | | Amounts owed to co-owners(a)(c) | (37 | ) | | (17 | ) | | Amounts owed to co-owners(c) | | Amounts owed to co-owners(c) | (35) | | | (23) | |
__________ | | (a) | Recorded in Accounts receivable, other. |
| | (b) | Recorded in Deferred debits and other assets, other. |
| | (c) | Non-CENG amounts owed to co-owners are recorded in Accounts receivable, other. CENG amounts owed to co-owners are recorded in Accounts payable. Represents amounts owed to the co-owners of Peach Bottom, Quad Cities, and Nine Mile Point Unit 2 generating facilities. |
(a)Recorded in Other accounts receivable. (b)Recorded in Deferred debits and other assets, other. (c)Recorded in Other accounts receivable. Represents amounts owed to the co-owners of Peach Bottom, Quad Cities, and Nine Mile Point Unit 2 generating facilities. The Standard Contracts with the DOE also required the payment to the DOE of a one-time fee applicable to nuclear generation through April 6, 1983. The below table outlines the SNF liability recorded at Exelon and Generation as of December 31, 20192021 and 2018:2020: | | | | | | | | | | | | | December 31, 2021 | | December 31, 2020 | Former ComEd units(a) | $ | 1,083 | | | $ | 1,082 | | Fitzpatrick(b) | 127 | | | 126 | | Total SNF Obligation | $ | 1,210 | | | $ | 1,208 | |
| | | | | | | | | | December 31, 2019 | | December 31, 2018 | Former ComEd units(a) | $ | 1,075 |
| | $ | 1,052 |
| Fitzpatrick(b) | 124 |
| | 119 |
| Total SNF Obligation | $ | 1,199 |
| | $ | 1,171 |
|
____________________(a)ComEd previously elected to defer payment of the one-time fee of $277 million for its units (which are now part of Generation), with interest to the date of payment, until just prior to the first delivery of SNF to the DOE. The unfunded liabilities for SNF disposal costs, including the one-time fee, were transferred to Generation as part of Exelon’s 2001 corporate restructuring.
| | (a) | ComEd previously elected to defer payment of the one-time fee of $277 million for its units (which are now part of Generation), with interest to the date of payment, until just prior to the first delivery of SNF to the DOE. The unfunded liabilities for SNF disposal costs, including the one-time fee, were transferred to Generation as part of Exelon’s 2001 corporate restructuring. |
| | (b) | A prior owner of FitzPatrick elected to defer payment of the one-time fee of $34 million, with interest to the date of payment, for the FitzPatrick unit. As part of the FitzPatrick acquisition on March 31, 2017, Generation assumed a SNF liability for the DOE one-time fee obligation with interest related to FitzPatrick along with an offsetting asset, included in Other deferred debits and other assets, for the contractual right to reimbursement from NYPA, a prior owner of FitzPatrick, for amounts paid for the FitzPatrick DOE one-time fee obligation.(b)A prior owner of FitzPatrick elected to defer payment of the one-time fee of $34 million, with interest to the date of payment, for the FitzPatrick unit. As part of the FitzPatrick acquisition on March 31, 2017, Generation assumed a SNF liability for the DOE one-time fee obligation with interest related to FitzPatrick along with an offsetting asset, included in Other deferred debits and other assets, for the contractual right to reimbursement from NYPA, a prior owner of FitzPatrick, for amounts paid for the FitzPatrick DOE one-time fee obligation. |
Interest for Exelon's and Generation's SNF liabilities accrues at the 13-week Treasury Rate. The 13-week Treasury Rate in effect for calculation of the interest accrual at December 31, 20192021 was 1.551%0.051% for the deferred amount transferred from ComEd and 1.879%0.041% for the deferred FitzPatrick amount. The following table summarizes sites for which Exelon and Generation dodoes not have an outstanding SNF Obligation: | | | | | | Description | Sites | Fees have been paid | Former PECO units, Clinton and Calvert Cliffs | Outstanding SNF Obligation remains with former owners | Nine Mile Point, Ginna and TMI |
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 Federal and state environmental laws, the Registrants are generally liable for the costs of remediating environmental contamination of property
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 19 — Commitments and Contingencies 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
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 18 — Commitments and Contingencies
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 2025. 2027. •PECO has 8 siteshas 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 2022.2023. •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 2021.2023. •DPL has 1 sitesite 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 the PAPUC, 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. As of December 31, 20192021 and 2018,2020, the Registrants had accrued the following undiscounted amounts for environmental liabilities in Other current liabilities and Other deferred credits and other liabilities withinin their respective Consolidated Balance Sheets: | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 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 | $ | 469 | | | $ | 303 | | | $ | 483 | | | $ | 314 | | | | | | | | | | ComEd | 279 | | | 279 | | | 293 | | | 293 | | PECO | 22 | | | 20 | | | 23 | | | 21 | | BGE | 6 | | | 4 | | | 2 | | | — | | PHI | 42 | | | — | | | 44 | | | — | | Pepco | 40 | | | — | | | 42 | | | — | | DPL | 1 | | | — | | | 1 | | | — | | ACE | 1 | | | — | | | 1 | | | — | |
| | | | | | | | | | | | | | | | | | December 31, 2019 | | December 31, 2018 | | Total environmental investigation and remediation reserve | | Portion of total related to MGP investigation and remediation | | Total environmental investigation and remediation reserve | | Portion of total related to MGP investigation and remediation | Exelon | $ | 478 |
| | $ | 320 |
| | $ | 496 |
| | $ | 356 |
| Generation | 105 |
| | — |
| | 108 |
| | — |
| ComEd | 304 |
| | 303 |
| | 329 |
| | 327 |
| PECO | 19 |
| | 17 |
| | 27 |
| | 25 |
| BGE | 2 |
| | — |
| | 5 |
| | 4 |
| PHI | 48 |
| | — |
| | 27 |
| | — |
| Pepco | 46 |
| | — |
| | 25 |
| | — |
| DPL | 1 |
| | — |
| | 1 |
| | — |
| ACE | 1 |
| | — |
| | 1 |
| | — |
|
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 19 — Commitments and Contingencies Cotter Corporation (Exelon and Generation)(Exelon). 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.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 18 — Commitments and Contingencies
In September 2018, the EPA issued its Record of Decision (ROD) Amendment (RODA) for the selection of thea final remedy. The RODRODA modified the EPA’sremedy previously proposed plan forselected 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 by reducingin addition to the depths of the excavation.previously selected capping remedy. The RODRODA 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 the 2020 - 2021 time frame.late 2024. In March 2019 the PRPs received Special Notice Letters from the EPA to perform the Remedial Action work. On October 8, 2019, GenerationCotter (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 $280$290 million, including cost escalation on an undiscounted basis, which would be allocated among the final group of PRPs. GenerationExelon 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’sExelon’s ultimate liability will depend on the actual costs incurred to implement the required remediation 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 Generation’sCotter's associated allocable share could differ significantly once these uncertainties are resolved, which could have a material impact on Exelon's and Generation's future financial statements.resolved. One of the other PRPs has indicated it will be making a contribution claim against Cotter for costs that it has incurred to prevent thea 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 dodoes 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 on 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 Settlement Agreement and Order on Consent for the performance by the PRPs of the groundwater Remedial Investigation (RI)/and Feasibility Study (FS)(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. GenerationExelon estimates the undiscounted cost for the groundwater RI/FS to be approximately $20$40 million. GenerationExelon 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 GenerationExelon 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 on 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. The DOJ has not yet formally advised the PRPs of the amount that it is seeking, but it is believed to be approximately $90 million from all PRPs.FUSRAP (Formerly Utilized Sites Remedial Action Program). Pursuant to a series of annual agreements since 2011, the DOJ and the PRPs have tolled the statute of limitations until February 202028, 2022 so that settlement discussions couldcan proceed. GenerationOn August 3, 2020, the DOJ advised Cotter and the other PRPs that it is seeking approximately
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 19 — Commitments and Contingencies $90 million from all the PRPs and has directed that the PRPs must submit a good faith joint proposed settlement offer. In December 2021, a good faith offer was submitted to the government and negotiations are expected to commence in the first quarter of 2022. Exelon 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. 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 was formerly the location of a Pepco Energy Services electric 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 with the DOEE, which
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 18 — Commitments and Contingencies
requires Pepco and Pepco Energy Services to conduct a RI/FS for the Benning Road site and an approximately 10 to 15-acre portion of the adjacent Anacostia River. Since 2013, Pepco and 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. In September 2019, Pepco and Generation issued a draft “final” RI report which DOEE approved and on October 4, 2019 released this document for review and comment by the public. The 45 day comment period ended on November 18, 2019 and a public meeting was held by Pepco on November 2, 2019.February 3, 2020. Pepco and Generation will proceed to developare 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 September 16, 2021. 2022. After completion and approval of the FS, DOEE will then prepare a Proposed Plan for public comment and then issue a Record of DecisionROD identifying any further response actions determined to be necessary, after considering public comment on the Proposed Plan.necessary. 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 Pepco and Generation, DOEE and the National 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 Pepco and Pepco Energy Services 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. DOEE asked Pepco, along with parties responsible for other sites along the river, to participate in a "Consultative Working Group" to provide input into the process for future remedial actions and to ensure proper coordination with the other river cleanup efforts currently underway, including cleanup of the river segment adjacent to the Benning Road site resulting from the Benning Road site RI/FS. In addition, the District of Columbia Council directed DOEE to form an official advisory committee made up of members of federal, state and local environmental regulators, community and environmental groups and various academic and technical experts to provide guidance and support to DOEE as the project progressed. This group, called the Anacostia Leadership Council, has met regularly since it was formed. Pepco has participated in the Consultative Working Group. 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 based on DOEE’s stated position following a series of meetings attended by representatives from the Anacostia Leadership Council and the Consultative Working Group.costs. On December 27, 2019,September 30, 2020, DOEE released a Focused Feasibility Study (FFS) and a Proposed Plan (PP) for review and comment by the public which will be the basis for theits Interim ROD. The Interim ROD which is expected to be completed in September 2020. The FFS and PP are consistent with the DOEE’s stated position to followreflects an adaptive management approach which will allowrequire 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 termlong-term 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. The comment period ends on March 2, 2020 and a public meeting will be held on January 23, 2021. Pepco concluded that incremental exposure remains reasonably possible, howeverbut 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, there is a complementary statutory program thatCERCLA 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 determine if any natural resources have been damagedwithin their jurisdiction as a result of the contamination that is being remediated, and, if so, that a plan be developed by the federal, state and local Natural Resource Damageremediated. The Trustees who are defined by CERCLA as thecan seek compensation from responsible parties for thesuch damages, including restoration or compensation for any loss of those resources from the environmental contaminants at the site. If natural resources cannot be restored, then compensation for the injury can be sought from the responsible parties. The assessment of Natural Resource Damages (NRD) typically takes place following cleanup because cleanups sometimes also effectively restore habitat.costs. During the second quarter of 2018, Pepco became aware that the Trustees are in the beginning stages of thisa Natural Resources Damages (NRD) assessment, a process that often takes many years beyond the remedial decision to complete. 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 range of loss.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 1819 — Commitments and Contingencies
Litigation and Regulatory Matters Asbestos Personal Injury Claims (Exelon and Generation)(Exelon). GenerationExelon 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 December 31, 20192021 and 2018,December 31, 2020, Exelon and Generation had recorded estimated liabilities of approximately $83$81 million and $79$89 million, respectively, in total for asbestos-related bodily injury claims. As of December 31, 2019,2021, approximately $26$17 million of this amount related to 263211 open claims presented to Generation, while the remaining $57$64 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 on Exelon’s and Generation’s financial statements.
Fund Transfer Restrictions (All Registrants). Under applicable law, Exelon may borrow or receive an extension of credit from its subsidiaries. Under the terms of Exelon’s intercompany money pool agreement, Exelon can lend to, but not borrow from the money pool. Under applicable law, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE can pay dividends only from retained, undistributed or current earnings. A significant loss recorded at Generation, ComEd, PECO, BGE, PHI, Pepco, DPL, or ACE may limit the dividends that these companies can distribute to Exelon. ComEd has agreed in connection with financings arranged through ComEd Financing III that it will not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debt securities issued to ComEd Financing III; (2) it defaults on its guarantee of the payment of distributions on the preferred trust securities of ComEd Financing III; or (3) an event of default occurs under the Indenture under which the subordinated debt securities are issued. No such event has occurred. PECO has agreed in connection with financings arranged through PEC L.P. and PECO Trust IV that PECO will not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debentures, which were issued to PEC L.P. or PECO Trust IV; (2) it defaults on its guarantee of the payment of distributions on the Series D Preferred Securities of PEC L.P. or the preferred trust securities of PECO Trust IV; or (3) an event of default occurs under the Indenture under which the subordinated debentures are issued. No such event has occurred. BGE is subject to restrictions established by the MDPSC that prohibit BGE from paying a dividend on its common shares if (a) after the dividend payment, BGE’s equity ratio would be below 48% as calculated pursuant to the MDPSC’s ratemaking precedents or (b) BGE’s senior unsecured credit rating is rated by two of the three major credit rating agencies below investment grade. No such event has occurred. Pepco is subject to certain dividend restrictions established by settlements approved in Maryland and the District of Columbia. Pepco is prohibited from paying a dividend on its common shares if (a) after the dividend payment, Pepco's equity ratio would be 48% as equity levels are calculated under the ratemaking precedents of the MDPSC and DCPSC or (b) Pepco’s senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. No such event has occurred. DPL is subject to certain dividend restrictions established by settlements approved in Delaware and Maryland. DPL is prohibited from paying a dividend on its common shares if (a) after the dividend payment, DPL's equity ratio would be 48% as equity levels are calculated under the ratemaking precedents of the DPSCDEPSC and MDPSC or (b) DPL’s senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. No such event has occurred. ACE is subject to certain dividend restrictions established by settlements approved in New Jersey. ACE is prohibited from paying a dividend on its common shares if (a) after the dividend payment, ACE's equity ratio would be 48% as equity levels are calculated under the ratemaking precedents of the NJBPU or (b) ACE's senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. ACE is also subject to a
dividend restriction which requires ACE to obtain the prior approval of the NJBPU before
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 1819 — Commitments and Contingencies
dividend restriction which requires ACE to obtain the prior approval of the NJBPU before dividends can be paid itif its equity as a percent of its total capitalization, excluding securitization debt, falls below 30%. No such events have occurred.
City of Everett Tax Increment FinancingDeferred Prosecution Agreement (Exelon(DPA) and Generation). On April 10, 2017, the City of Everett petitioned the Massachusetts Economic Assistance Coordinating Council (EACC) to revoke the 1999 tax increment financing agreement (TIF Agreement) relating to Mystic Units 8 and 9 on the grounds that the total investment in Mystic Units 8 and 9 materially deviates from the investment set forth in the TIF Agreement. On October 31, 2017, a three-member panel of the EACC conducted an administrative hearing on the City’s petition. On November 30, 2017, the hearing panel issued a tentative decision denying the City’s petition, finding that there was no material misrepresentation that would justify revocation of the TIF Agreement. On December 13, 2017, the tentative decision was adopted by the full EACC. On January 12, 2018, the City filed a complaint in Massachusetts Superior Court requesting, among other things, that the court set aside the EACC’s decision, grant the City’s request to decertify the Project and the TIF Agreement, and award the City damages for alleged underpaid taxes over the period of the TIF Agreement. On January 8, 2020, the Massachusetts Superior Court affirmed the decision of the EACC denying the City's petition. The deadline for appeal is March 9, 2020. Generation continues to believe that the City’s claim lacks merit. Accordingly, Generation has not recorded a liability for payment resulting from such a revocation, nor can Generation estimate a reasonably possible range of loss, if any, associated with any such revocation. Further, it is reasonably possible that property taxes assessed in future periods, including those following the expiration of the current TIF Agreement in 2020, could be material to Generation’s financial statements.
SubpoenasRelated 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 U.S. Attorney's Office for the Northern District of IllinoisUSAO requiring production of records of any communications with certain individuals and entities. On October 22, 2019, the SEC notified Exelon and ComEd that it hashad 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 and expeditiously with the U.S. Attorney’s Office and the SEC. Exelon and ComEd cannot predict the outcome of the U.S. Attorney's Office or the SEC investigations.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. Management is currently unable to estimate a range of reasonably possible loss as these matters are subject to change.
Subsequent to Exelon announcing the receipt of the subpoenas, avarious 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 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 the ruling to the Seventh Circuit Court of Appeals. Plaintiffs' opening appeal brief was filed on January 14, 2022. Exelon and ComEd have requested an extension until March 7, 2022 to file their response brief. Plaintiff's reply brief will be due approximately 21 days thereafter.Plaintiffs also refiled their state law claims in state court and have moved to consolidate that action with the already pending consumer state court class action, discussed below. CUB also refiled its state law claims in state court. •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 its 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
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 19 — Commitments and Contingencies 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. On December 23, 2021, the state court granted ComEd and Exelon’s motion to dismiss with 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 January 21, 2022. Plaintiffs have appealed the court's ruling dismissing their complaint to the First District Court of Appeals. On February 15, 2022, Exelon and ComEd moved to dismiss the federal plaintiffs' refiled state law claims, seeking dismissal on the same legal grounds as those asserted in their motion to dismiss the original state court plaintiffs' complaint. The parties agreed to submit their motion to dismiss briefing as a package, which included Exelon' and ComEd's motion, plaintiffs' response, and Exelon's and ComEd's reply, in order to facilitate a speedy resolution by the court. The court granted dismissal of the refiled state claims on February 16, 2022. The original federal plaintiffs filed their notice of appeal of that dismissal on February 18, 2022. •A putative class action lawsuit has been filed against Exelon and certain officers of Exelon and ComEd was filed in federal court in December 2019 alleging misrepresentations orand 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. That motion was 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 and the parties engaged thereafter in discovery. On September 9, 2021, the U.S. government moved to intervene in the lawsuit and stay discovery 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 protective order on November 15, 2021 and discovery resumed. The parties are required to substantially complete discovery by February 15, 2022. On February 10, 2022, the court granted an extension of the amendment to the protective order, at the U.S. government's request, to May 15, 2022, and directed the parties to submit a proposed joint schedule for the additional case proceedings by May 13, 2022. •Six shareholders have sent letters to the Exelon Board of Directors from 2020 through January 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 purportingand ComEd officers and directors related to relatethe conduct described in the DPA. In the first quarter of 2021, the Exelon Board of Directors appointed a Special Litigation Committee ("SLC") consisting of disinterested and independent parties to matters that areinvestigate and address these shareholders' allegations and make recommendations to the subjectExelon Board of Directors based on the outcome of the subpoenasSLC'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. On January 31, 2022, the parties jointly moved the court to extend the stay an additional 120 days. •Two separate shareholder requests seeking review of certain Exelon books and records were received in August 2021 and January 2022. Exelon has responded to the first request and the SEC investigation.shareholder thereafter sent a formal shareholder demand to the Exelon believes that these claims lack meritBoard as discussed above. Exelon is in the process of responding to the second request. No loss contingencies have been reflected in Exelon’s and intends to defend against them, and though the costs or any loss associated with the lawsuit cannot be reasonably estimated at this time, Exelon does not believe that the lawsuit will have a material adverse impact on Exelon’s or ComEd’s consolidated financial statements.statements with respect to these matters, as such contingencies are neither probable nor reasonably estimable at this time. The 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 costs recovered from customers related to the 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 and who failed,
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 19 — Commitments and Contingencies during their tenure at ComEd, to perform work to management expectations. Exelon and ComEd recorded a loss contingency for these compensation costs as of December 31, 2021, which for financial statement disclosure purposes is not material. The testimony supports the calculation of the refund amount and proposes a refund mechanism (one time bill credit in February 2023) and also addresses other topics outlined by statute and the ICC orders initiating the investigation. ComEd also presented evidence concerning the lawfulness of ComEd’s past rates more generally. However, in response to pre-hearing motions concerning the scope of the hearing and permissible discovery and testimony, the ICC Administrate Law Judge ("ALJ") assigned ruled that scope of this proceeding was limited to whether ComEd used ratepayer funds to pay the “effectuation costs” for the conduct described in the DPA and to pay the criminal fine. Consistent with that scope, the ALJ limited the testimony to those subjects. Consistent with that ruling and a failure to exhaust other discovery, on January 18, 2022 the ALJ denied plaintiffs’ counsel’s request to depose witnesses including several current and former ComEd and Exelon executives. Impacts of the February 2021 Extreme Cold Weather Event and Texas-based Generating Assets Outages (Exelon). Beginning on February 15, 2021, Exelon’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 Exelon since March 2021 related to these events, including: •On March 5, 2021, Exelon, along with more than 160 power generators and transmission and distribution companies, was sued by approximately 160 individually named plaintiffs, purportedly on behalf of all Texans who allegedly suffered loss of life or sustained personal injury, property damage or other losses as a result of the weather events. The plaintiffs allege that the defendants failed to properly prepare for 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 was filed on behalf of approximately 90 plaintiffs against more than 300 defendants, including Exelon, involving similar allegations of liability and claims of personal injury and property damage. Since March 2021, approximately 60 additional lawsuits, naming multiple defendants including Exelon, were filed by individual or multiple plaintiffs in different Texas counties, all arising out 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. On December 28, 2021, approximately 130 insurance companies which insured Texas homeowners and businesses filed a subrogation lawsuit against multiple defendants, including Exelon, alleging that defendants were at fault for the energy failure that resulted from the winter storm, causing significant property damage to the insureds. Additionally, as of January 28, 2022, Exelon has been added to approximately 80 additional wrongful death, personal injury and property damage lawsuits through the Multi-District-Litigation (MDL) pending in Texas state court. The MDL now includes all of the above-described Texas state court matters. Exelon disputes liability and denies that it is responsible for any of plaintiffs’ alleged claims and is vigorously contesting them. No loss contingencies have been reflected in Exelon’s consolidated 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 Exelon’s customers and by Exelon’s refusal to pay the resulting penalties. On March 26, 2021, Exelon 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 Exelon 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 Exelon’s complaint with two other similar complaints from other companies. On January 4, 2022, the court denied Exelon's motion to dismiss, but in the alternative granted its motion to stay pending MPSC resolution of Exelon's complaint. The MPSC has scheduled an evidentiary hearing for the three consolidated complaint cases in April 2022. Based on the penalty provisions within the tariff
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 19 — Commitments and Contingencies that was in effect at the relevant time, Exelon recorded a liability of approximately $40 million as of December 31, 2021. 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 marketplace and permitting a third-party administrative service provider/recordkeeper and an investment adviser to charge excessive fees for the services provided. The plaintiffs seek declaratory, equitable and monetary relief on behalf of the Plan and participants. On February 16, 2022, the court granted the parties' stipulated dismissal of the individual named defendants without prejudice. The remaining defendants' responsive pleading is due February 25, 2022. No loss contingencies have been reflected in Exelon’s consolidated financial statements with respect to this matter, as such contingencies are neither probable nor reasonably estimable at this time. 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.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 19 — Shareholders' Equity
19. 20.Shareholders' Equity (Exelon and Utility(All Registrants)
ComEd Common Stock Warrants The following table presents warrants outstanding to purchase ComEd common stock and shares of common stock reserved for the conversion of warrants. The warrants entitle the holders to convert such warrants into common stock of ComEd at a conversion rate of one share of common stock for three warrants. | | | | | | | | December 31, | | 2019 | | 2018 | Warrants outstanding | 60,228 |
| | 60,285 |
| Common Stock reserved for conversion | 20,076 |
| | 20,095 |
|
Equity Securities Offering
In June 2014, Exelon issued $1.15 billion of junior subordinated notes in the form of 23 million equity units. In June 2017, Exelon settled the forward equity purchase contract on these equity units through issuance of 33 million shares of common stock from treasury stock, which triggered full dilution in the EPS calculation. Previously, the equity units were included in the calculation of diluted EPS using the treasury stock method. | | | | | | | | | | | | | December 31, | | 2021 | | 2020 | Warrants outstanding | 60,061 | | | 60,143 | | Common Stock reserved for conversion | 20,020 | | | 20,048 | |
Share Repurchases There currently is 0no Exelon Board of Director authority to repurchase shares. Any previous shares repurchased are held as treasury shares, at cost, unless cancelled or reissued at the discretion of Exelon’s management. Preferred and Preference Securities The following table presents the Registrants'Exelon, ComEd, PECO, BGE, Pepco, and ACE's shares of preferred securities authorized, none of which arewere outstanding, as of December 31, 20192021 and 2018: | | | | | Preferred Securities Authorized | Exelon | 100,000,000 |
| ComEd | 850,000 |
| PECO | 15,000,000 |
| BGE | 1,000,000 |
| Pepco | 6,000,000 |
| ACE(a)
| 2,799,979 |
|
__________
| | (a) | Includes 799,9792020. There are no shares of cumulative preferred stock and 2,000,000 of no-par preferred stock as of December 31, 2019 and 2018, respectively. |
The following table presents ComEd's, BGE's and ACE's preference securities authorized none of which are outstanding as of December 31, 2019 and 2018:for DPL.
| | | | | Preference Securities Authorized | ComEd - Cumulative preference securities | 6,810,451 |
| 316 BGE(a)
| 6,500,000 |
| ACE | 3,000,000 |
|
__________
| | (a) | Includes 4,600,000 shares of unclassified preference securities and 1,900,000 shares of previously redeemed preference securities as of December 31, 2019 and 2018, respectively. |
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 1920 — Shareholders' Equity
| | | | | | | Preferred Securities Authorized | Exelon | 100,000,000 | | ComEd | 850,000 | | PECO | 15,000,000 | | BGE | 1,000,000 | | Pepco | 6,000,000 | | ACE(a) | 2,799,979 | |
__________
(a)Includes 799,979 shares of cumulative preferred stock and 2,000,000 of no-par preferred stock as of December 31, 2021 and 2020. 20.The following table presents ComEd's, BGE's, and ACE's preference securities authorized, none of which were outstanding as of December 31, 2021 and 2020. There are no shares of preference securities authorized for Exelon, PECO, Pepco, and DPL.
| | | | | | | Preference Securities Authorized | ComEd | 6,810,451 | | BGE(a) | 6,500,000 | | ACE | 3,000,000 | |
__________ (a)Includes 4,600,000 shares of unclassified preference securities and 1,900,000 shares of previously redeemed preference securities as of December 31, 2021 and 2020.
21. Stock-Based Compensation Plans (All Registrants) Stock-Based Compensation Plans Exelon grants stock-based awards through its LTIP, which primarily includes performance share awards, restricted stock units, and stock options. At December 31, 2019,2021, there were approximately 1233 million shares authorized for issuance under the LTIP. For the years ended December 31, 2019, 20182021, 2020, and 2017,2019, exercised and distributed stock-based awards were primarily issued from authorized but unissued common stock shares. The Registrants grant cash awards. The following table does not include expense related to these plans as they are not considered stock-based compensation plans under the applicable authoritative guidance.guidance. The following table presents the stock-based compensation expense included in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. The Utility Registrants' stock-based compensation expense for the years ended December 31, 2019, 20182021, 2020, and 20172019 was not material. | | | | | | | | | | | | | Exelon | Year Ended December 31, | Components of Stock-Based Compensation Expense | 2019 | | 2018 | | 2017 | Total stock-based compensation expense included in operating and maintenance expense | $ | 77 |
| | $ | 208 |
| | $ | 191 |
| Income tax benefit | (20 | ) | | (54 | ) | | (74 | ) | Total after-tax stock-based compensation expense | $ | 57 |
| | $ | 154 |
| | $ | 117 |
| Generation | | | | | | Components of Stock-Based Compensation Expense | | | | | | Total stock-based compensation expense included in operating and maintenance expense | $ | 37 |
| | $ | 77 |
| | $ | 88 |
| Income tax benefit | (10 | ) | | (20 | ) | | (34 | ) | Total after-tax stock-based compensation expense | $ | 27 |
| | $ | 57 |
| | $ | 54 |
|
| | | | | | | | | | | | | | | | | | | Year Ended December 31, | Exelon | 2021 | | 2020 | | 2019 | Total stock-based compensation expense included in operating and maintenance expense | $ | 142 | | | $ | 64 | | | $ | 77 | | Income tax benefit | (37) | | | (16) | | | (20) | | Total after-tax stock-based compensation expense | $ | 105 | | | $ | 48 | | | $ | 57 | | | | | | | | | | | | | | | | | | | | | | | | | |
Exelon receives a tax deduction based on the intrinsic value of the award on the exercise date for stock options and the distribution date for performance share awards and restricted stock units. For each award, throughout the requisite service period, Exelon recognizes the tax benefit related to compensation costs. The following table presents information regarding Exelon’s realized tax benefit when distributed: | | | | | | | | | | | | | | Year Ended December 31, | | 2019 | | 2018 | | 2017 | Performance share awards | $ | 41 |
| | $ | 16 |
| | $ | 29 |
| Restricted stock units | 24 |
| | 28 |
| | 35 |
|
317
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 21 — Stock-Based Compensation Plans | | | | | | | | | | | | | | | | | | | Year Ended December 31, | | 2021 | | 2020 | | 2019 | Performance share awards | $ | 9 | | | $ | 21 | | | $ | 41 | | Restricted stock units | 11 | | | 15 | | | 24 | |
Performance Share Awards Performance share awards are granted under the LTIP. The performance share awards are settled 50% in common stock and 50% in cash at the end of the three-year performance period, except for awards granted to vice presidents and higher officers that are settled 100% in cash if certain ownership requirements are satisfied. The common stock portion of the performance share awards is considered an equity award and is valued based on Exelon's stock price on the grant date. The cash portion of the performance share awards is considered a liability award which is remeasured each reporting period based on Exelon’s current stock price. As the value of the common stock and cash portions of the awards are based on Exelon’s stock price during the performance period, coupled with changes in the total shareholder return modifier and expected payout of the award, the compensation costs are subject to volatility until payout is established.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 20 — Stock-Based Compensation Plans
For nonretirement-eligible employees, stock-based compensation costs are recognized over the vesting period of three years using the straight-line method. For performance share awards granted to retirement-eligible employees, the value of the performance shares is recognized ratably over the vesting period, which is the year of grant. Exelon processes forfeitures as they occur for employees who do not complete the requisite service period. The following table summarizes Exelon’s nonvested performance share awards activity: | | | | | | | Shares | | Weighted Average Grant Date Fair Value (per share) | | Shares | | Weighted Average Grant Date Fair Value (per share) | | Nonvested at December 31, 2018(a) | 3,403,228 |
| | $ | 33.13 |
| | Nonvested at December 31, 2020(a) | | Nonvested at December 31, 2020(a) | 930,392 | | | $ | 43.67 | | Granted | 1,089,903 |
| | 47.37 |
| Granted | 1,131,788 | | | 43.37 | | Change in performance | (799,618 | ) | | 40.85 |
| Change in performance | 713,202 | | | 45.59 | | Vested | (1,610,146 | ) | | 28.90 |
| Vested | (327,551) | | | 38.66 | | Forfeited | (25,249 | ) | | 45.03 |
| Forfeited | (157,552) | | | 44.45 | | Undistributed vested awards(b) | (348,363 | ) | | 48.82 |
| Undistributed vested awards(b) | (1,067,763) | | | 44.58 | | Nonvested at December 31, 2019(a) | 1,709,755 |
| | $ | 39.21 |
| | Nonvested at December 31, 2021(a) | | Nonvested at December 31, 2021(a) | 1,222,516 | | | $ | 44.96 | |
__________ | | (a) | Excludes 2,017,870 and 3,586,259 of performance share awards issued to retirement-eligible employees as of December 31, 2019 and 2018, respectively, as they are fully vested. |
| | (b) | Represents performance share awards that vested but were not distributed to retirement-eligible employees during 2019. |
(a)Excludes 1,934,238 and 1,414,661 of performance share awards issued to retirement-eligible employees as of December 31, 2021 and 2020, respectively, as they are fully vested. (b)Represents performance share awards that vested but were not distributed to retirement-eligible employees during 2021. The following table summarizes the weighted average grant date fair value and the total fair value of performance share awards granted and settled.vested. | | | Year Ended December 31, | | Year Ended December 31, | | 2019 (a) | | 2018 | | 2017 | | 2021(a) | | 2020 | | 2019 | Weighted average grant date fair value (per share) | $ | 47.37 |
| | $ | 38.15 |
| | $ | 35.00 |
| Weighted average grant date fair value (per share) | $ | 43.37 | | | $ | 46.61 | | | $ | 47.37 | | Total fair value of performance shares settled | 158 |
| | 61 |
| | 72 |
| | Total fair value of performance shares vested | | Total fair value of performance shares vested | 44 | | | 39 | | | 158 | | Total fair value of performance shares settled in cash | 131 |
| | 49 |
| | 56 |
| Total fair value of performance shares settled in cash | 28 | | | 63 | | | 131 | |
__________ | | (a) | As of December 31, 2019, $17 million of total unrecognized compensation costs related to nonvested performance shares are expected to be recognized over the remaining weighted-average period of 1.6 years. |
(a)As of December 31, 2021, $26 million of total unrecognized compensation costs related to nonvested performance shares are expected to be recognized over the remaining weighted-average period of 1.8 years. Restricted Stock Units
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 21 — Stock-Based Compensation Plans Restricted stock units are granted under the LTIP with the majority being settled in a specific number of shares of common stock after the service condition has been met. The corresponding cost of services is measured based on the grant date fair value of the restricted stock unit issued. The value of the restricted stock units is expensed over the requisite service period using the straight-line method. The requisite service period for restricted stock units is generally three to five years. However, certain restricted stock unit awards become fully vested upon the employee reaching retirement-eligibility. The value of the restricted stock units granted to retirement-eligible employees is either recognized immediately uponratably over the datefirst six months in the year of grant if the employee reaches retirement eligibility prior to July 1st of the grant year or through the date atof which the employee reaches retirement eligibility. Exelon processes forfeitures as they occur for employees who do not complete the requisite service period.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 20 — Stock-Based Compensation Plans
The following table summarizes Exelon’s nonvested restricted stock unit activity: | | | | | | | Shares | | Weighted Average Grant Date Fair Value (per share) | | Shares | | Weighted Average Grant Date Fair Value (per share) | | Nonvested at December 31, 2018(a) | 2,293,341 |
| | $ | 35.06 |
| | Nonvested at December 31, 2020(a) | | Nonvested at December 31, 2020(a) | 1,114,130 | | | $ | 43.67 | | Granted | 902,857 |
| | 45.65 |
| Granted | 879,606 | | | 44.21 | | Vested | (1,232,704 | ) | | 32.83 |
| Vested | (397,526) | | | 44.39 | | Forfeited | (33,603 | ) | | 39.01 |
| Forfeited | (57,646) | | | 44.98 | | Undistributed vested awards (b) | (431,178 | ) | | 44.75 |
| Undistributed vested awards(b) | (396,515) | | | 43.66 | | Nonvested at December 31, 2019(a) | 1,498,713 |
| | $ | 40.35 |
| | Nonvested at December 31, 2021(a) | | Nonvested at December 31, 2021(a) | 1,142,049 | | $ | 43.52 | |
__________ | | (a) | Excludes 863,196 and 1,131,487 of restricted stock units issued to retirement-eligible employees as of December 31, 2019 and 2018, respectively, as they are fully vested. |
| | (b) | Represents restricted stock units that vested but were not distributed to retirement-eligible employees during 2019. |
(a)Excludes 609,934 and 748,165 of restricted stock units issued to retirement-eligible employees as of December 31, 2021 and 2020, respectively, as they are fully vested. (b)Represents restricted stock units that vested but were not distributed to retirement-eligible employees during 2021. The following table summarizes the weighted average grant date fair value and the total fair value of restricted stock units granted and vested. | | | Year Ended December 31, | | Year Ended December 31, | | 2019 (a) | | 2018 | | 2017 | | 2021(a) | | 2020 | | 2019 | Weighted average grant date fair value (per share) | $ | 45.65 |
| | $ | 38.60 |
| | $ | 34.98 |
| Weighted average grant date fair value (per share) | $ | 44.21 | | | $ | 46.33 | | | $ | 45.65 | | Total fair value of restricted stock units vested | 92 |
| | 106 |
| | 88 |
| Total fair value of restricted stock units vested | 34 | | | 54 | | | 92 | |
__________ | | (a) | As of December 31, 2019, $28 million of total unrecognized compensation costs related to nonvested restricted stock units are expected to be recognized over the remaining weighted-average period of 2.8 years. |
(a)As of December 31, 2021, $22 million of total unrecognized compensation costs related to nonvested restricted stock units are expected to be recognized over the remaining weighted-average period of 2.3 years. Stock Options Non-qualified stock options to purchase shares of Exelon’s common stock were granted through 2012 under the LTIP. The exercise price of the stock options is equal to the fair market value of the underlying stock on the date of option grant. Stock options will expire no later than ten years from the date of grant. At December 31, 20192021 all stock options were vested and there were no unrecognized compensation costs. The following table presents information with respect to stock option activity:319 | | | | | | | | | | | | | | | Shares | | Weighted Average Exercise Price (per share) | | Weighted Average Remaining Contractual Life (years) | | Aggregate Intrinsic Value | Balance of shares outstanding at December 31, 2018 | 4,027,652 |
| | $ | 43.95 |
| | 2.90 | | $ | 14 |
| Options exercised | (1,388,165 | ) | | 42.25 |
| | | | | Options expired | (750,442 | ) | | 55.96 |
| | | | | Balance of shares outstanding at December 31, 2019 | 1,889,045 |
| | $ | 40.43 |
| | 1.56 | | $ | 10 |
| Exercisable at December 31, 2019(a) | 1,889,045 |
| | $ | 40.43 |
| | 1.56 | | $ | 10 |
|
__________
| | (a) | Includes stock options issued to retirement eligible employees. |
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 2021 — Stock-Based Compensation Plans
The following table presents information with respect to stock option activity:
| | | | | | | | | | | | | | | | | | | | | | | | | Shares | | Weighted Average Exercise Price (per share) | | Weighted Average Remaining Contractual Life (years) | | Aggregate Intrinsic Value | Balance of shares outstanding at December 31, 2020 | 1,265,410 | | | $ | 40.57 | | | 0.91 | | $ | 3 | | Options exercised | (928,003) | | | 39.45 | | | | | 11 | | | | | | | | | | Options expired | (310,400) | | | 43.40 | | | | | | Balance of shares outstanding at December 31, 2021 | 27,007 | | | $ | 46.47 | | | 0.15 | | $ | — | | Exercisable at December 31, 2021(a) | 27,007 | | | $ | 46.47 | | | 0.15 | | $ | — | |
__________ (a)Includes stock options issued to retirement eligible employees. The following table summarizes additional information regarding stock options exercised: | | | Year Ended December 31, | | Year Ended December 31, | | 2019 | | 2018 | | 2017 | | 2021 | | 2020 | | 2019 | Intrinsic value(a) | $ | 9 |
| | $ | 12 |
| | $ | 15 |
| Intrinsic value(a) | $ | 11 | | | $ | 5 | | | $ | 9 | | Cash received for exercise price | 59 |
| | 56 |
| | 107 |
| Cash received for exercise price | 37 | | | 18 | | | 59 | |
__________ | | (a) | The difference between the market value on the date of exercise and the option exercise price. |
(a)The difference between the market value on the date of exercise and the option exercise price. 21.
22. Changes in Accumulated Other Comprehensive Income (Exelon) The following tables present changes in Exelon's AOCI, net of tax, by component: | | | | | | | | | | | | | | | | Losses on Cash Flow Hedges | | | Pension and Non-Pension Postretirement Benefit Plan Items (a) | | Foreign Currency Items | | AOCI of Investments Unconsolidated Affiliates (b) | | Total | | Gains and (Losses) on Cash Flow Hedges |
| Unrealized Gains and (Losses) on Marketable Securities |
| Pension and Non-Pension Postretirement Benefit Plan Items (a) |
| Foreign Currency Items |
| AOCI of Investments Unconsolidated Affiliates (b) |
| Total | | Balance at December 31, 2016 | $ | (17 | ) |
| $ | 4 |
|
| $ | (2,610 | ) |
| $ | (30 | ) |
| $ | (7 | ) |
| $ | (2,660 | ) | | OCI before reclassifications | (1 | ) | | 6 |
| | 11 |
| | 7 |
| | 6 |
| | 29 |
| | Amounts reclassified from AOCI | 4 |
| | — |
| | 140 |
| | — |
| | — |
| | 144 |
| | Net current-period OCI | 3 |
| | 6 |
| | 151 |
| | 7 |
| | 6 |
| | 173 |
| | Impact of adoption of Reclassification of Certain Tax Effects from AOCI(c) | — |
| | — |
| | (539 | ) | | — |
| | — |
| | (539 | ) | | Balance at December 31, 2017 | $ | (14 | ) |
| $ | 10 |
|
| $ | (2,998 | ) |
| $ | (23 | ) |
| $ | (1 | ) |
| $ | (3,026 | ) | | OCI before reclassifications | 11 |
| | — |
| | (143 | ) | | (10 | ) | | 1 |
| | (141 | ) | | Amounts reclassified from AOCI | 1 |
|
| — |
|
| 181 |
|
| — |
| | — |
|
| 182 |
| | Net current-period OCI | 12 |
|
| — |
|
| 38 |
|
| (10 | ) |
| 1 |
| | 41 |
| | Impact of adoption of Recognition and Measurement of Financial Assets and Financial Liabilities standard(d) | — |
| | (10 | ) | | — |
| | — |
| | — |
| | (10 | ) | | Balance at December 31, 2018 | $ | (2 | ) |
| $ | — |
|
| $ | (2,960 | ) |
| $ | (33 | ) |
| $ | — |
|
| $ | (2,995 | ) | Balance at December 31, 2018 | $ | (2) | | | | $ | (2,960) | |
| $ | (33) | | | $ | — | | | $ | (2,995) | | OCI before reclassifications | — |
| | — |
| | (289 | ) | | 6 |
| | (2 | ) | | (285 | ) | OCI before reclassifications | — | | | | (289) | | | 6 | | | (2) | | | (285) | | Amounts reclassified from AOCI | — |
| | — |
| | 84 |
| | — |
| | 2 |
| | 86 |
| Amounts reclassified from AOCI | — | | | | 84 | | | — | | | 2 | | | 86 | | Net current-period OCI | — |
| | — |
| | (205 | ) | | 6 |
| | — |
| | (199 | ) | Net current-period OCI | — | | | | (205) | | | 6 | | | — | | | (199) | | | Balance at December 31, 2019 | $ | (2 | ) |
| $ | — |
|
| $ | (3,165 | ) |
| $ | (27 | ) |
| $ | — |
|
| $ | (3,194 | ) | Balance at December 31, 2019 | $ | (2) | | | | $ | (3,165) | | | $ | (27) | | | $ | — | | | $ | (3,194) | | OCI before reclassifications | | OCI before reclassifications | (3) | | | | (357) | | | 4 | | | — | | | (356) | | Amounts reclassified from AOCI | | Amounts reclassified from AOCI | — | | | | 150 | | | — | | | — | | | 150 | | Net current-period OCI | | Net current-period OCI | (3) | | | | (207) | | | 4 | | | — | | | (206) | | Balance at December 31, 2020 | | Balance at December 31, 2020 | $ | (5) | | | | $ | (3,372) | | | $ | (23) | | | $ | — | | | $ | (3,400) | | OCI before reclassifications | | OCI before reclassifications | (1) | | | | 432 | | | — | | | — | | | 431 | | Amounts reclassified from AOCI | | Amounts reclassified from AOCI | — | | | | 219 | | | — | | | — | | | 219 | | Net current-period OCI | | Net current-period OCI | (1) | | | | 651 | | | — | | | — | | | 650 | | Balance at December 31, 2021 | | Balance at December 31, 2021 | $ | (6) | | | | $ | (2,721) | | | $ | (23) | | | $ | — | | | $ | (2,750) | |
__________ | | (a) | This AOCI component is included in the computation of net periodic pension and OPEB cost. See Note 14 — Retirement Benefits for additional information. See Exelon's Statements of Operations and Comprehensive Income for individual components of AOCI. |
| | (b) | All amounts are net of noncontrolling interests. |
| | (c) | Exelon early adopted the new standard Reclassification of Certain Tax Effects from AOCI. The standard was adopted retrospectively as of December 31, 2017, which resulted in an increase to Exelon’s Retained earnings and Accumulated other comprehensive loss of $539 million, primarily related to deferred income taxes associated with Exelon’s pension and OPEB obligations. |
| | (d) | Exelon prospectively adopted the new standard Recognition and Measurement of Financial Assets and Financial Liabilities. The standard was adopted as of January 1, 2018, which resulted in an increase to Retained earnings and Accumulated other comprehensive loss of $10 million for Exelon. The amounts reclassified related to Rabbi Trusts. |
(a)This AOCI component is included in the computation of net periodic pension and OPEB cost. See Note 15 — Retirement Benefits for additional information. See Exelon's Statements of Operations and Comprehensive Income for individual components of AOCI.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 2122 — Changes in Accumulated Other Comprehensive Income
(b)All amounts are net of noncontrolling interests.
The following table presents income tax benefit (expense) allocated to each component of Exelon's other comprehensive income (loss): | | | | | | | | | | | | | | For the Year Ended December 31, | | 2019 | | 2018 | | 2017 | Pension and non-pension postretirement benefit plans: | | | | | | Prior service benefit reclassified to periodic benefit cost | $ | 23 |
| | $ | 24 |
| | $ | 36 |
| Actuarial loss reclassified to periodic benefit cost | (52 | ) | | (86 | ) | | (128 | ) | Pension and non-pension postretirement benefit plans valuation adjustment | 100 |
| | 50 |
| | 13 |
|
| | | | | | | | | | | | | | | | | | | For the Year Ended December 31, | | 2021 | | 2020 | | 2019 | Pension and non-pension postretirement benefit plans: | | | | | | Prior service benefit reclassified to periodic benefit cost | $ | 4 | | | $ | 16 | | | $ | 23 | | Actuarial loss reclassified to periodic benefit cost | (76) | | | (66) | | | (52) | | Pension and non-pension postretirement benefit plans valuation adjustment | (153) | | | 122 | | | 100 | |
22.23. Variable Interest Entities (Exelon, Generation, PHI, and ACE)
At December 31, 20192021 and 2018,2020, 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.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 23 — Variable Interest Entities 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 December 31, 20192021 and 2018.2020. 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 footnotes to the table below, are such that creditors, or beneficiaries, do not have recourse to the general credit of Exelon, Generation, PHI, and ACE. | | | December 31, 2019 | | December 31, 2018 | | December 31, 2021 | | December 31, 2020 | | Exelon(a) | | Generation | | PHI(a) | | ACE | | Exelon | | Generation | | PHI | | ACE | | Exelon | | | PHI | | ACE | | Exelon | | | PHI(a) | | ACE | Cash and cash equivalents | $ | 163 |
| | $ | 163 |
| | $ | — |
| | $ | — |
| | $ | 414 |
| | $ | 414 |
| | $ | — |
| | $ | — |
| Cash and cash equivalents | $ | 35 | | | | $ | — | | | $ | — | | | $ | 98 | | | | $ | — | | | $ | — | | Restricted cash and cash equivalents | 88 |
| | 85 |
| | 3 |
| | 3 |
| | 66 |
| | 62 |
| | 4 |
| | 4 |
| Restricted cash and cash equivalents | 48 | | | | — | | | — | | | 47 | | | | 3 | | | 3 | | Accounts receivable, net | | | | | | | | | | | | | | | | | Accounts receivable | | Accounts receivable | | | | | | Customer | 151 |
| | 151 |
| | — |
| | — |
| | 146 |
| | 146 |
| | — |
| | — |
| Customer | 24 | | | | — | | | — | | | 148 | | | | — | | | — | | Other | 39 |
| | 39 |
| | — |
| | — |
| | 23 |
| | 23 |
| | — |
| | — |
| Other | 6 | | | | — | | | — | | | 36 | | | | — | | | — | | Unamortized energy contract asset (b) | 23 |
| | 23 |
| | — |
| | — |
| | 25 |
| | 25 |
| | — |
| | — |
| | | Inventories, net | | | | | | | | | | | | | | | | Inventories, net | | | | | | | Materials and supplies | 227 |
| | 227 |
| | — |
| | — |
| | 212 |
| | 212 |
| | — |
| | — |
| Materials and supplies | 14 | | | | — | | | — | | | 244 | | | | — | | | — | | Assets held for sale(b) | | Assets held for sale(b) | — | | | | — | | | — | | | 101 | | | | — | | | — | | Other current assets | 32 |
| | 31 |
| | 1 |
| | — |
| | 52 |
| | 49 |
| | 3 |
| | — |
| Other current assets | 405 | | | | — | | | — | | | 696 | | | | 5 | | | — | | Total current assets | 723 |
|
| 719 |
|
| 4 |
|
| 3 |
| | 938 |
| | 931 |
| | 7 |
| | 4 |
| Total current assets | 532 | | | | — | | | — | | | 1,370 | | | | 8 | | | 3 | | Property, plant and equipment, net (c) | 6,022 |
| | 6,022 |
| | — |
| | — |
| | 6,188 |
| | 6,188 |
| | — |
| | — |
| | | Property, plant and equipment, net | | Property, plant and equipment, net | 2,027 | | | | — | | | — | | | 5,803 | | | | — | | | — | | Nuclear decommissioning trust funds | 2,741 |
| | 2,741 |
| | — |
| | — |
| | 2,351 |
| | 2,351 |
| | — |
| | — |
| Nuclear decommissioning trust funds | — | | | | — | | | — | | | 3,007 | | | | — | | | — | | Unamortized energy contract asset (b) | 250 |
| | 250 |
| | — |
| | — |
| | 274 |
| | 274 |
| | — |
| | — |
| | | Other noncurrent assets | 89 |
| | 73 |
| | 16 |
| | 14 |
| | 258 |
| | 232 |
| | 26 |
| | 19 |
| Other noncurrent assets | 215 | | | | — | | | — | | | 301 | | | | 10 | | | 10 | | Total noncurrent assets | 9,102 |
|
| 9,086 |
|
| 16 |
|
| 14 |
| | 9,071 |
| | 9,045 |
| | 26 |
| | 19 |
| Total noncurrent assets | 2,242 | | | | — | | | — | | | 9,111 | | | | 10 | | | 10 | | Total assets | $ | 9,825 |
|
| $ | 9,805 |
|
| $ | 20 |
|
| $ | 17 |
| | $ | 10,009 |
| | $ | 9,976 |
| | $ | 33 |
| | $ | 23 |
| | Total assets(c) | | Total assets(c) | $ | 2,774 | | | | $ | — | | | $ | — | | | $ | 10,481 | | | | $ | 18 | | | $ | 13 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Long-term debt due within one year | $ | 544 |
| | $ | 523 |
| | $ | 21 |
| | $ | 20 |
| | $ | 87 |
| | $ | 66 |
| | $ | 21 |
| | $ | 18 |
| Long-term debt due within one year | $ | 70 | | | | $ | — | | | $ | — | | | $ | 94 | | | | $ | 26 | | | $ | 21 | | Accounts payable | 106 |
| | 106 |
| | — |
| | — |
| | 96 |
| | 96 |
| | — |
| | — |
| Accounts payable | 10 | | | | — | | | — | | | 81 | | | | — | | | — | | Accrued expenses | 70 |
| | 70 |
| | — |
| | — |
| | 73 |
| | 72 |
| | 1 |
| | 1 |
| Accrued expenses | 21 | | | | — | | | — | | | 70 | | | | — | | | — | | | Unamortized energy contract liabilities | 8 |
| | 8 |
| | — |
| | — |
| | 15 |
| | 15 |
| | — |
| | — |
| Unamortized energy contract liabilities | — | | | | — | | | — | | | 4 | | | | — | | | — | | Liabilities held for sale(b) | | Liabilities held for sale(b) | — | | | | — | | | — | | | 16 | | | | — | | | — | | Other current liabilities | 3 |
| | 3 |
| | — |
| | — |
| | 3 |
| | 3 |
| | — |
| | — |
| Other current liabilities | 1 | | | | — | | | — | | | 5 | | | | — | | | — | | Total current liabilities | 731 |
|
| 710 |
|
| 21 |
|
| 20 |
| | 274 |
| | 252 |
| | 22 |
| | 19 |
| Total current liabilities | 102 | | | | — | | | — | | | 270 | | | | 26 | | | 21 | | | Long-term debt | 527 |
| | 504 |
| | 23 |
| | 21 |
| | 1,072 |
| | 1,025 |
| | 47 |
| | 40 |
| Long-term debt | 822 | | | | — | | | — | | | 889 | | | | — | | | — | | Asset retirement obligations (d) | 2,128 |
| | 2,128 |
| | — |
| | — |
| | 2,165 |
| | 2,165 |
| | — |
| | — |
| | Unamortized energy contract liabilities | 1 |
| | 1 |
| | — |
| | — |
| | 1 |
| | 1 |
| | — |
| | — |
| | | Asset retirement obligations | | Asset retirement obligations | 151 | | | | — | | | — | | | 2,318 | | | | — | | | — | | | Other noncurrent liabilities | 89 |
| | 89 |
| | — |
| | — |
| | 42 |
| | 42 |
| | — |
| | — |
| Other noncurrent liabilities | 3 | | | | — | | | — | | | 129 | | | | — | | | — | | Total noncurrent liabilities | 2,745 |
|
| 2,722 |
|
| 23 |
|
| 21 |
| | 3,280 |
| | 3,233 |
| | 47 |
| | 40 |
| Total noncurrent liabilities | 976 | | | | — | | | — | | | 3,336 | | | | — | | | — | | Total liabilities | $ | 3,476 |
|
| $ | 3,432 |
|
| $ | 44 |
|
| $ | 41 |
| | $ | 3,554 |
| | $ | 3,485 |
| | $ | 69 |
| | $ | 59 |
| | Total liabilities(d) | | Total liabilities(d) | $ | 1,078 | | | | $ | — | | | $ | — | | | $ | 3,606 | | | | $ | 26 | | | $ | 21 | |
__________ | | (a) | Includes certain purchase accounting adjustments not pushed down to the ACE standalone entity. |
| | (b) | These are unrestricted assets to Exelon and Generation. |
| | (c) | Exelon's and Generation's balances include unrestricted assets of $20 million and $43 million as of December 31, 2019 and 2018, respectively. |
| | (d) | Exelon's and Generation's balances include liabilities with recourse of $3 million and $5 million as of December 31, 2019 and 2018, respectively. |
(a)Includes certain purchase accounting adjustments from the PHI merger not pushed down to ACE.
(b)Generation entered into an agreement for the sale of a significant portion of Generation's solar business. As a result of this transaction, in the fourth quarter of 2020, Exelon reclassified the consolidated VIEs' solar assets and liabilities as held for sale. Refer to Note 2 — Mergers, Acquisitions, and Dispositions for additional information on the sale of the solar business. (c)Exelon's balances include unrestricted assets for current unamortized energy contract assets of $23 million and $22 million, disclosed within other current assets in the table above, non-current unamortized energy contract assets of $202 million and $249 million, disclosed within other noncurrent assets in the table above, Assets held for sale of $0 million and $9 million, and other unrestricted assets of $0 million and $1 million as of December 31, 2021 and 2020, respectively. (d)Exelon's balances include liabilities with recourse of $1 million and $8 million as of December 31, 2021 and 2020, respectively.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 2223 — Variable Interest Entities
As of December 31, 20192021 and 2018,2020, Exelon's and Generation's consolidated VIEs consist of: associated with Generation included the following: | | | | | | | | | Consolidated VIE or VIE groups: | Reason entity is a VIE: | Reason GenerationExelon is primary beneficiary: | CENG - A joint venture between Generation and EDF. Generation hashad a 50.01% equity ownership in CENG.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 Nuclear Operating Services Agreement (NOSA)NOSA described further below. | Generation conducts the operational activities. | EGRPCRP - A collection of wind and solar project entities. Generation has a 51% equity ownership in EGRP.CRP. 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. | Blue StemBluestem Wind Energy Holdings, LLC - A Tax Equity structure which is consolidated by EGRP.CRP. Generation ishas a minority interest holder.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).
GenerationExelon fully impaired this investment in the third quarter of 2019. See note 11- Refer to Note 12 — Asset Impairments for additional information.
| 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. Refer to Note 6 —Accounts Receivablefor 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. See 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. 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 provided a $400 million loan
Combined Notes to CENG. The remaining balance was fully paid by CENGConsolidated Financial Statements (Dollars in January 2019.millions, except per share data unless otherwise noted)
Note 23 — Variable Interest Entities •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 and will continue to do so post-separation, however, any calls on this guarantee would require Generation to reimburse Exelon under the terms of the Separation Agreement. (SeeSee Note 1819 — Commitments and Contingencies and Note 26 - Separation for more details),details. Generation and EDF share in the $688 million of contingent payment obligations for the payment of contingent retrospective premium adjustments for the nuclear liability insurance, and
•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. Both the support agreement and guarantee terminated upon separation. Prior to August 6, 2021, Generation and EDF shared in the $688 million of the 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. EGRPCRP - EGRPCRP 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.CRP. While Generation or EGRPCRP owns 100% of the solar entities and 100% of the majority of the wind entities, it has been determined that certain of the wholly owned 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
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 22 — Variable Interest Entities
facilities, or theentities' customers absorb price variability from the entities through the fixed price power and/or REC purchase agreements. Additionally, for the wind entities that have minority interests, it has been determined that these entities are VIEs because the governance rights of some investors are not proportional to their financial rights. Generation is the primary beneficiary of these solar and wind entities that qualify as VIEs because Generation controls the design, construction,operations and operationdirect all activities of the facilities. Generation provides operating and capital funding to the solar and wind entities for ongoing construction, operations and maintenance and thereThere is limited recourse related to Generation related to certain solar and wind entities.
In 2017, Generation’sExelon's interests in EGRPCRP were contributed to and are pledged for the ExGen Renewables IVCR non-recourse debt project financing structure. Refer to Note 1617 — Debt and Credit Agreements for additional information on ExGen Renewables IV.information. As of December 31, 20192021 and 2018,2020, 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 Transition 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.Transition Bonds. Proceeds from the sale of each series of transition bondsTransition 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 bondsTransition Bonds and related taxes, expenses, and fees. In the fourth quarter of 2021, the Transition bonds were fully redeemed and ACE remitted its final payment to ATF. Upon redemption of the bonds, ATF no longer meets the definition of a variable interest entity. | ACE’s equity investment is a variable interest as, by design, it absorbs any initial variability of ACETF.ATF. The bondholders also have a variable interest for the investment made to purchase the transition bonds.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 predominatelypredominantly 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.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 23 — Variable Interest Entities As of December 31, 20192021 and 2018,2020, 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. The following table presents summary information about Exelon and Generation’sExelon's significant unconsolidated VIE entities: | | | December 31, 2019 | | December 31, 2018 | | December 31, 2021 | | December 31, 2020 | | Commercial Agreement VIEs | | Equity Investment VIEs | | Total | | Commercial Agreement VIEs | | Equity Investment VIEs | | Total | | Commercial Agreement VIEs | | Equity Investment VIEs | | Total | | Commercial Agreement VIEs | | Equity Investment VIEs | | Total | Total assets(a) | $ | 636 |
| | $ | 443 |
| | $ | 1,079 |
| | $ | 597 |
| | $ | 472 |
| | $ | 1,069 |
| Total assets(a) | $ | 772 | | | $ | 372 | | | $ | 1,144 | | | $ | 777 | | | $ | 401 | | | $ | 1,178 | | Total liabilities(a) | 33 |
| | 227 |
| | 260 |
| | 37 |
| | 222 |
| | 259 |
| Total liabilities(a) | 80 | | | 216 | | | 296 | | | 61 | | | 223 | | | 284 | | Exelon's ownership interest in VIE(a) | — |
| | 191 |
| | 191 |
| | — |
| | 223 |
| | 223 |
| Exelon's ownership interest in VIE(a) | — | | | 139 | | | 139 | | | — | | | 157 | | | 157 | | Other ownership interests in VIE(a) | 604 |
| | 25 |
| | 629 |
| | 560 |
| | 27 |
| | 587 |
| Other ownership interests in VIE(a) | 692 | | | 17 | | | 709 | | | 716 | | | 21 | | | 737 | | Registrants’ maximum exposure to loss: | | | | |
|
| | | | | |
|
| | Carrying amount of equity method investments | — |
| | — |
| | — |
| | — |
| | 223 |
| | 223 |
| | |
__________ | | (a) | These items represent amounts on(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. |
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 22 — Variable Interest Entities
For each of the unconsolidated VIEs,VIEs. Exelon and Generationdoes not have assessed the risk of a loss equal to their maximumany exposure to be remoteloss as they do not have a carrying amount in the equity investment VIEs as of December 31, 2021 and accordingly, Exelon and Generation have not recognized a liability associated with any portion of the maximum exposure to loss.2020.
As of December 31, 20192021 and 2018,2020, Exelon's and Generation's unconsolidated VIEs consist of: | | | | | | | | | Unconsolidated VIE groups: | Reason entity is a VIE: | Reason GenerationExelon 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 aanother distributed energy company (See Consolidated VIEs disclosure above).
GenerationExelon fully impaired this investment in the third quarter of 2019. See note 11- Refer to Note 12 — Asset Impairments for additional information.
| 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. |
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 24 — Supplemental Financial Information
24. 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. | | | | | | | | | | | | | | | | | | | | | | Taxes other than income taxes | | Taxes other than income taxes | | Exelon | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | For the year ended December 31, 2021 | | For the year ended December 31, 2021 | | | | | | | | | | | | | | | | | Utility(a) | | Utility(a) | $ | 873 | | | | $ | 246 | | | $ | 139 | | | $ | 88 | | | $ | 301 | | | $ | 278 | | | $ | 22 | | | $ | 3 | | Property | | Property | 633 | | | | 39 | | | 18 | | | 176 | | | 131 | | | 88 | | | 40 | | | 3 | | Payroll | | Payroll | 233 | | | | 27 | | | 16 | | | 18 | | | 27 | | | 7 | | | 5 | | | 3 | | | For the year ended December 31, 2020 | | For the year ended December 31, 2020 | | | | Utility(a) | | Utility(a) | $ | 859 | | | | $ | 238 | | | $ | 135 | | | $ | 87 | | | $ | 299 | | | $ | 275 | | | $ | 21 | | | $ | 3 | | Property | | Property | 602 | | | | 30 | | | 16 | | | 164 | | | 126 | | | 84 | | | 39 | | | 3 | | Payroll | | Payroll | 235 | | | | 27 | | | 16 | | | 17 | | | 25 | | | 7 | | | 5 | | | 3 | | | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | | | | For the year ended December 31, 2019 | | | | | | | | | | | | | | | | | | For the year ended December 31, 2019 | | | | Utility(a) | $ | 881 |
| | $ | 112 |
| | $ | 242 |
| | $ | 132 |
| | $ | 90 |
| | $ | 304 |
| | $ | 286 |
| | $ | 18 |
| | $ | — |
| Utility(a) | $ | 881 | | | | $ | 242 | | | $ | 132 | | | $ | 90 | | | $ | 304 | | | $ | 286 | | | $ | 18 | | | $ | — | | Property | 595 |
| | 274 |
| | 29 |
| | 17 |
| | 153 |
| | 122 |
| | 85 |
| | 34 |
| | 2 |
| Property | 595 | | | | 29 | | | 17 | | | 153 | | | 122 | | | 85 | | | 34 | | | 2 | | Payroll | 232 |
| | 115 |
| | 27 |
| | 15 |
| | 17 |
| | 24 |
| | 7 |
| | 4 |
| | 2 |
| Payroll | 232 | | | | 27 | | | 15 | | | 17 | | | 24 | | | 7 | | | 4 | | | 2 | | | | | | | | | | | | | | | | | | | | | For the year ended December 31, 2018 | | | | | | | | | | | | | | | | | | | Utility(a) | $ | 919 |
| | $ | 114 |
| | $ | 243 |
| | $ | 131 |
| | $ | 94 |
| | $ | 337 |
| | $ | 316 |
| | $ | 21 |
| | $ | — |
| | Property | 557 |
| | 273 |
| | 30 |
| | 15 |
| | 143 |
| | 94 |
| | 58 |
| | 32 |
| | 3 |
| | Payroll | 247 |
| | 130 |
| | 27 |
| | 16 |
| | 17 |
| | 24 |
| | 5 |
| | 3 |
| | 2 |
| | | | | | | | | | | | | | | | | | | | | For the year ended December 31, 2017 | | | | | | | | | | | | | | | | | | | Utility(a) | $ | 898 |
| | $ | 126 |
| | $ | 240 |
| | $ | 125 |
| | $ | 89 |
| | $ | 318 |
| | $ | 300 |
| | $ | 18 |
| | $ | — |
| | Property | 545 |
| | 269 |
| | 28 |
| | 14 |
| | 132 |
| | 101 |
| | 62 |
| | 32 |
| | 3 |
| | Payroll | 230 |
| | 121 |
| | 26 |
| | 15 |
| | 15 |
| | 26 |
| | 6 |
| | 4 |
| | 2 |
| |
__________ | | (a) | Generation’s utility tax represents gross receipts tax related to its retail operations and the Utility Registrants’ utility taxes represents municipal and state utility taxes and gross receipts taxes related to their operating revenues. |
(a)Exelon’s utility tax represents gross receipts tax related to Generation's retail operations, and the Utility Registrants’ utility taxes represents 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.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 2324 — Supplemental Financial Information
| | | | | | | | | | | | | | | | | | | | | | Other, net | | Other, Net | | Exelon | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | For the year ended December 31, 2021 | | For the year ended December 31, 2021 | | | | | | | | | | | | | | | | | Decommissioning-related activities: | | Decommissioning-related activities: | Net realized income on NDT funds(a) | | Net realized income on NDT funds(a) | Regulatory Agreement Units | | Regulatory Agreement Units | $ | 817 | | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | Non-Regulatory Agreement Units | | Non-Regulatory Agreement Units | 449 | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Net unrealized gains on NDT funds | | Net unrealized gains on NDT funds | | | | Regulatory Agreement Units | | Regulatory Agreement Units | 351 | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Non-Regulatory Agreement Units | | Non-Regulatory Agreement Units | 209 | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Regulatory offset to NDT fund-related activities(b) | | Regulatory offset to NDT fund-related activities(b) | (917) | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Decommissioning-related activities | | Decommissioning-related activities | 909 | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | AFUDC—Equity | | AFUDC—Equity | 136 | | | | 34 | | | 26 | | | 27 | | | 49 | | | 40 | | | 6 | | | 3 | | Non-service net periodic benefit cost | | Non-service net periodic benefit cost | 91 | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Net unrealized losses from equity investments(c) | | Net unrealized losses from equity investments(c) | (160) | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | | For the year ended December 31, 2020 | | For the year ended December 31, 2020 | | | | Decommissioning-related activities: | | Decommissioning-related activities: | Net realized income on NDT funds(a) | | Net realized income on NDT funds(a) | Regulatory Agreement Units | | Regulatory Agreement Units | $ | 185 | | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | Non-Regulatory Agreement Units | | Non-Regulatory Agreement Units | 160 | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Net unrealized gains on NDT funds | | Net unrealized gains on NDT funds | | | | Regulatory Agreement Units | | Regulatory Agreement Units | 724 | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Non-Regulatory Agreement Units | | Non-Regulatory Agreement Units | 391 | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Regulatory offset to NDT fund-related activities(b) | | Regulatory offset to NDT fund-related activities(b) | (729) | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Decommissioning-related activities | | Decommissioning-related activities | 731 | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | AFUDC—Equity | | AFUDC—Equity | 104 | | | | 29 | | | 17 | | | 22 | | | 36 | | | 28 | | | 4 | | | 4 | | Non-service net periodic benefit cost | | Non-service net periodic benefit cost | 53 | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Net unrealized gains from equity investments(c) | | Net unrealized gains from equity investments(c) | 186 | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | | | | For the year ended December 31, 2019 | | | | | | | | | | | | | | | | | | For the year ended December 31, 2019 | | | | Decommissioning-related activities: | Decommissioning-related activities: | Decommissioning-related activities: | Net realized income on NDT funds(a) | Net realized income on NDT funds(a) | Net realized income on NDT funds(a) | Regulatory agreement units | $ | 297 |
| | $ | 297 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | Non-regulatory agreement units | 363 |
| | 363 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | Regulatory Agreement Units | | Regulatory Agreement Units | $ | 297 | | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | Non-Regulatory Agreement Units | | Non-Regulatory Agreement Units | 363 | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Net unrealized gains on NDT funds | | | | | | | | | | | | | | | | | | Net unrealized gains on NDT funds | | | | Regulatory agreement units | 795 |
| | 795 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | Non-regulatory agreement units | 411 |
| | 411 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | Regulatory Agreement Units | | Regulatory Agreement Units | 795 | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Non-Regulatory Agreement Units | | Non-Regulatory Agreement Units | 411 | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Regulatory offset to NDT fund-related activities(b) | (876 | ) | | (876 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Regulatory offset to NDT fund-related activities(b) | (876) | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Decommissioning-related activities | 990 |
|
| 990 |
|
| — |
|
| — |
|
| — |
| | — |
|
| — |
|
| — |
|
| — |
| Decommissioning-related activities | 990 | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | AFUDC—Equity | 85 |
| | — |
| | 17 |
| | 13 |
| | 21 |
| | 34 |
| | 25 |
| | 4 |
| | 5 |
| AFUDC—Equity | 85 | | | | 17 | | | 13 | | | 21 | | | 34 | | | 25 | | | 4 | | | 5 | | Non-service net periodic benefit cost | 13 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Non-service net periodic benefit cost | 13 | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | | | | | | | | | | | | | | | | | | | For the year ended December 31, 2018 | | | | | | | | | | | | | | | | | | | Decommissioning-related activities: | | Net realized income on NDT funds(a) | | Regulatory agreement units | $ | 506 |
| | $ | 506 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | Non-regulatory agreement units | 302 |
| | 302 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | Net unrealized losses on NDT funds | | | | | | | | | | | | | | | | | | | Regulatory agreement units | (715 | ) | | (715 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | Non-regulatory agreement units | (483 | ) | | (483 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | Regulatory offset to NDT fund-related activities(b) | 171 |
| | 171 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | Decommissioning-related activities | (219 | ) | | (219 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | AFUDC—Equity | 69 |
| | — |
| | 19 |
| | 7 |
| | 18 |
| | 25 |
| | 22 |
| | 2 |
| | 1 |
| | Non-service net periodic benefit cost | (47 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | | | | | | | | | | | | | | | | | | | For the year ended December 31, 2017 | | | | | | | | | | | | | | | | | | | Decommissioning-related activities: | | Net realized income on NDT funds(a) | | Regulatory agreement units | $ | 488 |
| | $ | 488 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | Non-regulatory agreement units | 209 |
| | 209 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | Net unrealized gains on NDT funds | | | | | | | | | | | | | | | | | | | Regulatory agreement units | 455 |
| | 455 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | Non-regulatory agreement units | 521 |
| | 521 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | Regulatory offset to NDT fund-related activities(b) | (724 | ) | | (724 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | Decommissioning-related activities | 949 |
| | 949 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | AFUDC—Equity | 73 |
| | — |
| | 12 |
| | 9 |
| | 16 |
| | 36 |
| | 23 |
| | 7 |
| | 6 |
| | Non-service net periodic benefit cost | (109 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| |
__________ | | (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, including the elimination of income taxes related to all NDT fund activity for those units. See Note 9 — Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning. |
(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 the 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 for additional information regarding the accounting for nuclear decommissioning and the contractual offset suspension for the Byron units. (c)Net unrealized (losses) gains from equity investments that became publicly traded entities in the fourth quarter of 2020 and the first half of 2021.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 2324 — Supplemental Financial Information
Supplemental Cash Flow Information The following tables provide additional information about material items recorded in the Registrants' Consolidated Statements of Cash Flows. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Depreciation, amortization, and accretion | | Exelon | | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | For the year ended December 31, 2021 | | | | | | | | | | | | | | | | | Property, plant, and equipment(a) | $ | 5,384 | | | | | $ | 970 | | | $ | 336 | | | $ | 439 | | | $ | 627 | | | $ | 274 | | | $ | 169 | | | $ | 155 | | Amortization of regulatory assets(a) | 594 | | | | | 235 | | | 12 | | | 152 | | | 194 | | | 129 | | | 41 | | | 24 | | Amortization of intangible assets, net(a) | 58 | | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Amortization of energy contract assets and liabilities(b) | 31 | | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Nuclear fuel(c) | 992 | | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | ARO accretion(d) | 514 | | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Total depreciation, amortization, and accretion | $ | 7,573 | | | | | $ | 1,205 | | | $ | 348 | | | $ | 591 | | | $ | 821 | | | $ | 403 | | | $ | 210 | | | $ | 179 | | | | | | | | | | | | | | | | | | | | For the year ended December 31, 2020 | | | | | | | | | | | | | | | | | Property, plant, and equipment(a) | $ | 4,364 | | | | | $ | 922 | | | $ | 319 | | | $ | 397 | | | $ | 586 | | | $ | 257 | | | $ | 155 | | | $ | 140 | | Amortization of regulatory assets(a) | 588 | | | | | 211 | | | 28 | | | 153 | | | 196 | | | 120 | | | 36 | | | 40 | | Amortization of intangible assets, net(a) | 62 | | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Amortization of energy contract assets and liabilities(b) | 30 | | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Nuclear fuel(c) | 983 | | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | ARO accretion(d) | 500 | | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Total depreciation, amortization, and accretion | $ | 6,527 | | | | | $ | 1,133 | | | $ | 347 | | | $ | 550 | | | $ | 782 | | | $ | 377 | | | $ | 191 | | | $ | 180 | | | | | | | | | | | | | | | | | | | | For the year ended December 31, 2019 | | | | | | | | | | | | | | | | | Property, plant, and equipment(a) | $ | 3,665 | | | | | $ | 886 | | | $ | 303 | | | $ | 359 | | | $ | 547 | | | $ | 239 | | | $ | 146 | | | $ | 123 | | Amortization of regulatory assets(a) | 528 | | | | | 147 | | | 30 | | | 143 | | | 207 | | | 135 | | | 38 | | | 34 | | Amortization of intangible assets, net(a) | 59 | | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Amortization of energy contract assets and liabilities(b) | 21 | | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Nuclear fuel(c) | 1,016 | | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | ARO accretion(d) | 491 | | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Total depreciation, amortization, and accretion | $ | 5,780 | | | | | $ | 1,033 | | | $ | 333 | | | $ | 502 | | | $ | 754 | | | $ | 374 | | | $ | 184 | | | $ | 157 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Depreciation, amortization and accretion | | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | For the year ended December 31, 2019 | | | | | | | | | | | | | | | | | Property, plant and equipment | $ | 3,665 |
| | $ | 1,485 |
| | $ | 886 |
| | $ | 303 |
| | $ | 359 |
| | $ | 547 |
| | $ | 239 |
| | $ | 146 |
| | $ | 123 |
| Amortization of regulatory assets | 528 |
| | — |
| | 147 |
| | 30 |
|
| 143 |
|
| 207 |
|
| 135 |
|
| 38 |
|
| 34 |
| Amortization of intangible assets, net | 59 |
|
| 50 |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
| Amortization of energy contract assets and liabilities(a) | 21 |
|
| 21 |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
| Nuclear fuel(b) | 1,016 |
|
| 1,016 |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
| ARO accretion(c) | 491 |
|
| 491 |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
| Total depreciation, amortization and accretion | $ | 5,780 |
| | $ | 3,063 |
| | $ | 1,033 |
|
| $ | 333 |
| | $ | 502 |
|
| $ | 754 |
| | $ | 374 |
|
| $ | 184 |
|
| $ | 157 |
| | | | | | | | | | | | | | | | | | | For the year ended December 31, 2018 | | | | | | | | | | | | | | | | | Property, plant and equipment | $ | 3,740 |
| | $ | 1,748 |
| | $ | 820 |
| | $ | 274 |
| | $ | 335 |
| | $ | 480 |
| | $ | 218 |
| | $ | 131 |
| | $ | 94 |
| Amortization of regulatory assets | 555 |
| | — |
| | 120 |
| | 27 |
|
| 148 |
|
| 260 |
|
| 167 |
|
| 51 |
|
| 42 |
| Amortization of intangible assets, net | 58 |
|
| 49 |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
| Amortization of energy contract assets and liabilities(a) | 14 |
|
| 14 |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
| Nuclear fuel(b) | 1,115 |
|
| 1,115 |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
| ARO accretion(c) | 489 |
|
| 489 |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
| Total depreciation, amortization and accretion | $ | 5,971 |
| | $ | 3,415 |
| | $ | 940 |
| | $ | 301 |
| | $ | 483 |
| | $ | 740 |
| | $ | 385 |
| | $ | 182 |
| | $ | 136 |
| | | | | | | | | | | | | | | | | | | For the year ended December 31, 2017 | | | | | | | | | | | | | | | | | Property, plant and equipment | $ | 3,293 |
| | $ | 1,409 |
| | $ | 777 |
| | $ | 261 |
| | $ | 312 |
| | $ | 457 |
| | $ | 203 |
| | $ | 124 |
| | $ | 89 |
| Amortization of regulatory assets | 478 |
| | — |
| | 73 |
| | 25 |
|
| 161 |
|
| 218 |
|
| 118 |
|
| 43 |
|
| 57 |
| Amortization of intangible assets, net | 57 |
|
| 48 |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
| Amortization of energy contract assets and liabilities(a) | 35 |
|
| 35 |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
| Nuclear fuel(b) | 1,096 |
|
| 1,096 |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
| ARO accretion(c) | 468 |
|
| 468 |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
| Total depreciation, amortization and accretion | $ | 5,427 |
| | $ | 3,056 |
|
| $ | 850 |
|
| $ | 286 |
|
| $ | 473 |
| | $ | 675 |
| | $ | 321 |
|
| $ | 167 |
|
| $ | 146 |
|
____________________(a)Included in Depreciation and amortization in the Registrants' Consolidated Statements of Operations and Comprehensive Income.
| | (a) | Included in Operating revenues or Purchased power and fuel expense in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. |
| | (b) | Included in Purchased power and fuel expense in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. |
| | (c) | Included in Operating and maintenance expense in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. |
(b)Included in Operating revenues or Purchased power and fuel expense in Exelon’s Consolidated Statements of Operations and Comprehensive Income.
(c)Included in Purchased power and fuel expense in Exelon’s Consolidated Statements of Operations and Comprehensive Income. (d)Included in Operating and maintenance expense in Exelon'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 2324 — Supplemental Financial Information
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Cash paid (refunded) during the year: | | Exelon | | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | For the year ended December 31, 2021 | | | | | | | | | | | | | | | | | | Interest (net of amount capitalized) | $ | 1,505 | | | | | $ | 372 | | | $ | 152 | | | $ | 134 | | | $ | 255 | | | $ | 132 | | | $ | 59 | | | $ | 56 | | Income taxes (net of refunds) | 281 | | | | | (72) | | | (4) | | | (38) | | | — | | | 12 | | | (9) | | | 2 | | For the year ended December 31, 2020 | | | | | | | | | | | | | | | | | | Interest (net of amount capitalized) | $ | 1,521 | | | | | $ | 371 | | | $ | 144 | | | $ | 125 | | | $ | 257 | | | $ | 129 | | | $ | 61 | | | $ | 57 | | Income taxes (net of refunds) | 10 | | | | | (61) | | | (37) | | | (57) | | | 46 | | | 40 | | | 12 | | | (3) | | For the year ended December 31, 2019 | | | | | | | | | | | | | | | | | | Interest (net of amount capitalized) | $ | 1,470 | | | | | $ | 343 | | | $ | 129 | | | $ | 106 | | | $ | 255 | | | $ | 130 | | | $ | 59 | | | $ | 55 | | Income taxes (net of refunds) | 265 | | | | | (42) | | | 82 | | | 17 | | | 29 | | | 7 | | | 19 | | | (5) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Cash paid (refunded) during the year: | | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | For the year ended December 31, 2019 | | | | | | | | | | | | | | | | | | Interest (net of amount capitalized) | $ | 1,470 |
| | $ | 373 |
| | $ | 343 |
| | $ | 129 |
| | $ | 106 |
| | $ | 255 |
| | $ | 130 |
| | $ | 59 |
| | $ | 55 |
| Income taxes (net of refunds) | 265 |
| | (44 | ) | | (42 | ) | | 82 |
| | 17 |
| | 29 |
| | 7 |
| | 19 |
| | (5 | ) | | | | | | | | | | | | | | | | | | | For the year ended December 31, 2018 | | | | | | | | | | | | | | | | | | Interest (net of amount capitalized) | $ | 1,421 |
| | $ | 369 |
| | $ | 332 |
| | $ | 125 |
| | $ | 94 |
| | $ | 250 |
| | $ | 123 |
| | $ | 56 |
| | $ | 61 |
| Income taxes (net of refunds) | 95 |
| | 746 |
| | (153 | ) | | (2 | ) | | 14 |
| | (32 | ) | | 41 |
| | (6 | ) | | (12 | ) | | | | | | | | | | | | | | | | | | | For the year ended December 31, 2017 | | | | | | | | | | | | | | | | | | Interest (net of amount capitalized) | $ | 2,430 |
| | $ | 391 |
| | $ | 307 |
| | $ | 103 |
| | $ | 96 |
| | $ | 236 |
| | $ | 114 |
| | $ | 49 |
| | $ | 59 |
| Income taxes (net of refunds) | 540 |
| | 337 |
| | 83 |
| | 47 |
| | (2 | ) | | (144 | ) | | (104 | ) | | (49 | ) | | (2 | ) |
329
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 2324 — Supplemental Financial Information
| | | | Other non-cash operating activities: | | | | Exelon | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | For the year ended December 31, 2021 | | For the year ended December 31, 2021 | | | | | | | | | | | | | | | | | Pension and non-pension postretirement benefit costs | | Pension and non-pension postretirement benefit costs | $ | 411 | | | | $ | 129 | | | $ | 8 | | | $ | 61 | | | $ | 49 | | | $ | 6 | | | $ | 2 | | | $ | 11 | | Allowance for credit losses | | Allowance for credit losses | 160 | | | | 47 | | | 39 | | | 17 | | | 24 | | | 9 | | | 5 | | | 10 | | Other decommissioning-related activity(a) | | Other decommissioning-related activity(a) | (946) | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Energy-related options(b) | | Energy-related options(b) | 125 | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | True-up adjustments to decoupling mechanisms and formula rates(c) | | True-up adjustments to decoupling mechanisms and formula rates(c) | (171) | | | | (42) | | | (26) | | | (12) | | | (91) | | | (53) | | | (14) | | | (24) | | Severance costs | | Severance costs | (57) | | | | 2 | | | — | | | — | | | 1 | | | — | | | — | | | — | | | Long-term incentive plan | | Long-term incentive plan | 137 | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Amortization of operating ROU asset | | Amortization of operating ROU asset | 183 | | | | 1 | | | — | | | 29 | | | 28 | | | 6 | | | 8 | | | 4 | | | AFUDC - Equity | | AFUDC - Equity | (136) | | | | (34) | | | (26) | | | (27) | | | (49) | | | (40) | | | (6) | | | (3) | | | For the year ended December 31, 2020 | | For the year ended December 31, 2020 | | | | Pension and non-pension postretirement benefit costs | | Pension and non-pension postretirement benefit costs | $ | 411 | | | | $ | 114 | | | $ | 5 | | | $ | 62 | | | $ | 70 | | | $ | 15 | | | $ | 7 | | | $ | 14 | | Allowance for credit losses | | Allowance for credit losses | 150 | | | | 32 | | | 42 | | | 15 | | | 43 | | | 24 | | | 16 | | | 2 | | Other decommissioning-related activity(a) | | Other decommissioning-related activity(a) | (659) | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Energy-related options(b) | | Energy-related options(b) | 104 | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | True-up adjustments to decoupling mechanisms and formula rates(c) | | True-up adjustments to decoupling mechanisms and formula rates(c) | (6) | | | | 47 | | | (16) | | | (16) | | | (21) | | | (40) | | | 7 | | | 12 | | Severance costs | | Severance costs | 105 | | | | 1 | | | 1 | | | — | | | — | | | — | | | — | | | — | | | Provision for excess and obsolete inventory | | Provision for excess and obsolete inventory | 131 | | | | 2 | | | 1 | | | — | | | — | | | — | | | — | | | — | | | Long-term incentive plan | | Long-term incentive plan | 56 | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Amortization of operating ROU asset | | Amortization of operating ROU asset | 222 | | | | 2 | | | 1 | | | 31 | | | 28 | | | 7 | | | 8 | | | 3 | | Asset impairments | | Asset impairments | — | | | | 15 | | | — | | | — | | | 13 | | | — | | | 7 | | | 6 | | | AFUDC - Equity | | AFUDC - Equity | (104) | | | | (29) | | | (17) | | | (22) | | | (36) | | | (28) | | | (4) | | | (4) | | | For the year ended December 31, 2019 | | For the year ended December 31, 2019 | | | | Pension and non-pension postretirement benefit costs | | Pension and non-pension postretirement benefit costs | $ | 438 | | | | $ | 96 | | | $ | 12 | | | $ | 61 | | | $ | 95 | | | $ | 25 | | | $ | 15 | | | $ | 16 | | Allowance for credit losses | | Allowance for credit losses | 120 | | | | 33 | | | 31 | | | 8 | | | 17 | | | 7 | | | 4 | | | 5 | | Other decommissioning-related activity(a) | | Other decommissioning-related activity(a) | (506) | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Energy-related options(b) | | Energy-related options(b) | 22 | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | True-up adjustments to decoupling mechanisms and formula rates(d) | | True-up adjustments to decoupling mechanisms and formula rates(d) | 124 | | | | 128 | | | — | | | — | | | (4) | | | (4) | | | — | | | — | | | | | Other non-cash operating activities: | | | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | | For the year ended December 31, 2019 | | | | | | | | | | | | | | | | | | | Pension and non-pension postretirement benefit costs | $ | 438 |
| | $ | 135 |
| | $ | 96 |
| | $ | 12 |
| | $ | 61 |
| | $ | 95 |
| | $ | 25 |
| | $ | 15 |
| | $ | 16 |
| | Provision for uncollectible accounts | 120 |
| | 31 |
| | 33 |
| | 31 |
| | 8 |
| | 17 |
| | 7 |
| | 4 |
| | 5 |
| | Other decommissioning-related activity(a) | (506 | ) | | (506 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | Energy-related options(b) | 22 |
| | 22 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | Amortization of rate stabilization deferral | (4 | ) | | — |
| | — |
| | — |
| | — |
| | (4 | ) | | (4 | ) | | — |
| | — |
| | Discrete impacts from EIMA and FEJA(d) | 128 |
| | — |
| | 128 |
| | — |
| �� | — |
| | — |
| | — |
| | — |
| | — |
| | Long-term incentive plan | 10 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Long-term incentive plan | 10 | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Amortization of operating ROU asset | 244 |
| | 172 |
| | 3 |
| | — |
| | 30 |
| | 33 |
| | 8 |
| | 8 |
| | 4 |
| | Amortization of operating ROU Asset | | Amortization of operating ROU Asset | 244 | | | | 3 | | | — | | | 30 | | | 33 | | | 8 | | | 8 | | | 4 | | Change in environmental liabilities | 23 |
| | — |
| | — |
| | — |
| | — |
| | 23 |
| | 23 |
| | — |
| | — |
| Change in environmental liabilities | 23 | | | | — | | | — | | | — | | | 23 | | | 23 | | | — | | | — | | | | | | | | | | | | | | | | | | | | | For the year ended December 31, 2018 | | | | | | | | | | | | | | | | | | | Pension and non-pension postretirement benefit costs | $ | 583 |
| | $ | 204 |
| | $ | 177 |
| | $ | 18 |
| | $ | 59 |
| | $ | 67 |
| | $ | 15 |
| | $ | 6 |
| | $ | 12 |
| | Provision for uncollectible accounts | 159 |
| | 48 |
| | 40 |
| | 33 |
| | 10 |
| | 28 |
| | 11 |
| | 6 |
| | 11 |
| | Other decommissioning-related activity(a) | (2 | ) | | (2 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | Energy-related options(b) | 10 |
| | 10 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | Amortization of rate stabilization deferral | 21 |
| | — |
| | — |
| | — |
| | — |
| | 21 |
| | 21 |
| | — |
| | — |
| | Asset retirement costs | 20 |
| | — |
| | — |
| | — |
| | — |
| | 20 |
| | 22 |
| | (1 | ) | | (1 | ) | | Discrete impacts from EIMA and FEJA(d) | 28 |
| | — |
| | 28 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | Long-term incentive plan | 140 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | | | | | | | | | | | | | | | | | | | For the year ended December 31, 2017 | | | | | | | | | | | | | | | | | | | Pension and non-pension postretirement benefit costs | $ | 643 |
| | $ | 227 |
| | $ | 176 |
| | $ | 29 |
| | $ | 62 |
| | $ | 94 |
| | $ | 25 |
| | $ | 13 |
| | $ | 13 |
| | Provision for uncollectible accounts | 125 |
| | 38 |
| | 34 |
| | 26 |
| | 8 |
| | 19 |
| | 8 |
| | 3 |
| | 8 |
| | Other decommissioning-related activity(a) | (313 | ) | | (313 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | Energy-related options(b) | 7 |
| | 7 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | Amortization of rate stabilization deferral | (3 | ) | | — |
| | — |
| | — |
| | 7 |
| | (10 | ) | | (10 | ) | | — |
| | — |
| | Discrete impacts from EIMA and FEJA(d) | (52 | ) | | — |
| | (52 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | Vacation accrual adjustment(e) | (68 | ) | | (35 | ) | | (12 | ) | | — |
| | — |
| | (8 | ) | | (8 | ) | | — |
| | — |
| | Long-term incentive plan | 109 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | Change in environmental liabilities | 44 |
| | 44 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | AFUDC - Equity | | AFUDC - Equity | (85) | | | | (17) | | | (13) | | | (21) | | | (34) | | | (25) | | | (4) | | | (5) | |
__________ | | (a) | Includes the elimination of decommissioning-related activities for the Regulatory Agreement Units, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income and income taxes related to all NDT fund activity for these units. See Note 9 — Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning. |
| | (b) | Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations. |
| | (c) | See Note 2 - Mergers, Acquisitions and Dispositions for additional information. |
(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 taxes related to all NDT fund activity for these units. With the 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 for additional information regarding the accounting for nuclear decommissioning and for additional information on the contractual offset suspension for the Byron units.
(b)Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 2324 — Supplemental Financial Information (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 rate. See Note 3 — Regulatory Matters for additional information. (d)For ComEd, reflects the true-up adjustments in regulatory assets and liabilities associated with its distribution and energy efficiency formula rates. For Pepco and DPL, reflects the change in regulatory assets and liabilities associated with their decoupling mechanisms. See Note 3 — Regulatory Matters for additional information.
| | (d) | Reflects the change in ComEd's distribution and energy efficiency formula rates . See Note 3 — Regulatory Matters for additional information. |
| | (e) | On December 1, 2017, Exelon adopted a single, standard vacation accrual policy for all non-represented, non-craft (represented and craft policies remained unchanged) employees effective January 1, 2018. To reflect the new policy, Exelon recorded a one-time, $68 million pre-tax credit to expense to reverse 2018 vacation cost originally accrued throughout 2017 that was accrued ratably during 2018. |
The following tables provide a reconciliation of cash, restricted cash, and 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 | | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | December 31, 2021 | | | | | | | | | | | | | | | | | | Cash and cash equivalents | $ | 1,182 | | | | | $ | 131 | | | $ | 36 | | | $ | 51 | | | $ | 136 | | | $ | 34 | | | $ | 28 | | | $ | 29 | | Restricted cash and cash equivalents | 393 | | | | | 210 | | | 8 | | | 4 | | | 77 | | | 34 | | | 43 | | | — | | Restricted cash included in other long-term assets | 44 | | | | | 43 | | | — | | | — | | | — | | | — | | | — | | | — | | Total cash, restricted cash, and cash equivalents | $ | 1,619 | | | | | $ | 384 | | | $ | 44 | | | $ | 55 | | | $ | 213 | | | $ | 68 | | | $ | 71 | | | $ | 29 | | | | | | | | | | | | | | | | | | | | December 31, 2020 | | | | | | | | | | | | | | | | | | Cash and cash equivalents | $ | 663 | | | | | $ | 83 | | | $ | 19 | | | $ | 144 | | | $ | 111 | | | $ | 30 | | | $ | 15 | | | $ | 17 | | Restricted cash and cash equivalents | 438 | | | | | 279 | | | 7 | | | 1 | | | 39 | | | 35 | | | — | | | 3 | | Restricted cash included in other long-term assets | 53 | | | | | 43 | | | — | | | — | | | 10 | | | — | | | — | | | 10 | | Cash, restricted cash, and cash equivalents - Held for Sale | 12 | | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Total cash, restricted cash, and cash equivalents | $ | 1,166 | | | | | $ | 405 | | | $ | 26 | | | $ | 145 | | | $ | 160 | | | $ | 65 | | | $ | 15 | | | $ | 30 | | | | | | | | | | | | | | | | | | | | December 31, 2019 | | | | | | | | | | | | | | | | | | Cash and cash equivalents | $ | 587 | | | | | $ | 90 | | | $ | 21 | | | $ | 24 | | | $ | 131 | | | $ | 30 | | | $ | 13 | | | $ | 12 | | Restricted cash and cash equivalents | 358 | | | | | 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 | | | | | $ | 403 | | | $ | 27 | | | $ | 25 | | | $ | 181 | | | $ | 63 | | | $ | 13 | | | $ | 28 | | | | | | | | | | | | | | | | | | | | December 31, 2018 | | | | | | | | | | | | | | | | | | Cash and cash equivalents | $ | 1,349 | | | | | $ | 135 | | | $ | 130 | | | $ | 7 | | | $ | 124 | | | $ | 16 | | | $ | 23 | | | $ | 7 | | Restricted cash and cash equivalents | 247 | | | | | 29 | | | 5 | | | 6 | | | 43 | | | 37 | | | 1 | | | 4 | | Restricted cash included in other long-term assets | 185 | | | | | 166 | | | — | | | — | | | 19 | | | — | | | — | | | 19 | | Total cash, restricted cash, and cash equivalents | $ | 1,781 | | | | | $ | 330 | | | $ | 135 | | | $ | 13 | | | $ | 186 | | | $ | 53 | | | $ | 24 | | | $ | 30 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | December 31, 2019 | | | | | | | | | | | | | | | | | | Cash and cash equivalents | $ | 587 |
| | $ | 303 |
| | $ | 90 |
| | $ | 21 |
| | $ | 24 |
| | $ | 131 |
| | $ | 30 |
| | $ | 13 |
| | $ | 12 |
| Restricted cash | 358 |
| | 146 |
| | 150 |
| | 6 |
| | 1 |
| | 36 |
| | 33 |
| | — |
| | 2 |
| Restricted cash included in other long-term assets | 177 |
| | — |
| | 163 |
| | — |
| | — |
| | 14 |
| | — |
| | — |
| | 14 |
| Total cash, cash equivalents and restricted cash | $ | 1,122 |
| | $ | 449 |
| | $ | 403 |
| | $ | 27 |
| | $ | 25 |
| | $ | 181 |
| | $ | 63 |
| | $ | 13 |
| | $ | 28 |
| | | | | | | | | | | | | | | | | | | December 31, 2018 | | | | | | | | | | | | | | | | | | Cash and cash equivalents | $ | 1,349 |
| | $ | 750 |
| | $ | 135 |
| | $ | 130 |
| | $ | 7 |
| | $ | 124 |
| | $ | 16 |
| | $ | 23 |
| | $ | 7 |
| Restricted cash | 247 |
| | 153 |
| | 29 |
| | 5 |
| | 6 |
| | 43 |
| | 37 |
| | 1 |
| | 4 |
| Restricted cash included in other long-term assets | 185 |
| | — |
| | 166 |
| | — |
| | — |
| | 19 |
| | — |
| | — |
| | 19 |
| Total cash, cash equivalents and restricted cash | $ | 1,781 |
| | $ | 903 |
| | $ | 330 |
| | $ | 135 |
| | $ | 13 |
| | $ | 186 |
| | $ | 53 |
| | $ | 24 |
| | $ | 30 |
| | | | | | | | | | | | | | | | | | | December 31, 2017 | | | | | | | | | | | | | | | | | | Cash and cash equivalents | $ | 898 |
| | $ | 416 |
| | $ | 76 |
| | $ | 271 |
| | $ | 17 |
| | $ | 30 |
| | $ | 5 |
| | $ | 2 |
| | $ | 2 |
| Restricted cash | 207 |
| | 138 |
| | 5 |
| | 4 |
| | 1 |
| | 42 |
| | 35 |
| | — |
| | 6 |
| Restricted cash included in other long-term assets | 85 |
| | — |
| | 63 |
| | — |
| | — |
| | 23 |
| | — |
| | — |
| | 23 |
| Total cash, cash equivalents and restricted cash | $ | 1,190 |
| | $ | 554 |
| | $ | 144 |
| | $ | 275 |
| | $ | 18 |
| | $ | 95 |
| | $ | 40 |
| | $ | 2 |
| | $ | 31 |
| | | | | | | | | | | | | | | | | | | December 31, 2016 | | | | | | | | | | | | | | | | | | Cash and cash equivalents | $ | 635 |
| | $ | 290 |
| | $ | 56 |
| | $ | 63 |
| | $ | 23 |
| | $ | 170 |
| | $ | 9 |
| | $ | 46 |
| | $ | 101 |
| Restricted cash | 253 |
| | 158 |
| | 2 |
| | 4 |
| | 24 |
| | 43 |
| | 33 |
| | — |
| | 9 |
| Restricted cash included in other long-term assets | 26 |
| | — |
| | — |
| | — |
| | 3 |
| | 23 |
| | — |
| | — |
| | 23 |
| Total cash, cash equivalents and restricted cash | $ | 914 |
| | $ | 448 |
| | $ | 58 |
| | $ | 67 |
| | $ | 50 |
| | $ | 236 |
| | $ | 42 |
| | $ | 46 |
| | $ | 133 |
|
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 2324 — Supplemental Financial Information
Supplemental Balance Sheet Information The following tables provide additional information about material items recorded in the Registrants' Consolidated Balance Sheets. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Investments | | Exelon | | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | December 31, 2021 | | | | | | | | | | | | | | | | | | Equity method investments: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Other equity method investments | $ | 77 | | | | | $ | 6 | | | $ | 7 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | | | | | | | | | | | | | | | | | | Other investments: | | | | | | | | | | | | | | | | | | Employee benefit trusts and investments(a) | 315 | | | | | — | | | 27 | | | 14 | | | 145 | | | 120 | | | — | | | — | | | | | | | | | | | | | | | | | | | | Equity investments without readily determinable fair values | 44 | | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Other available for sale debt security investments | 7 | | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | | | | | | | | | | | | | | | | | | Total investments | $ | 443 | | | | | $ | 6 | | | $ | 34 | | | $ | 14 | | | $ | 145 | | | $ | 120 | | | $ | — | | | $ | — | | | | | | | | | | | | | | | | | | | | December 31, 2020 | | | | | | | | | | | | | | | | | | Equity method investments: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Other equity method investments | $ | 81 | | | | | $ | 6 | | | $ | 8 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | | | | | | | | | | | | | | | | | | Other investments: | | | | | | | | | | | | | | | | | | Employee benefit trusts and investments(a) | 283 | | | | | — | | | 22 | | | 10 | | | 140 | | | 115 | | | — | | | — | | Equity investments without readily determinable fair values | 73 | | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Other available for sale debt security investments | 3 | | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | | | | | | | | | | | | | | | | | | Total investments | $ | 440 | | | | | $ | 6 | | | $ | 30 | | | $ | 10 | | | $ | 140 | | | $ | 115 | | | $ | — | | | $ | — | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Unbilled customer revenues(a) | | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | December 31, 2019 | $ | 1,535 |
| | $ | 807 |
| | $ | 218 |
| | $ | 146 |
| | $ | 170 |
| | $ | 194 |
| | $ | 100 |
| | $ | 61 |
| | $ | 33 |
| December 31, 2018 | 1,656 |
| | 965 |
| | 223 |
| | 114 |
| | 168 |
| | 186 |
| | 97 |
| | 59 |
| | 30 |
|
__________(a)The Registrants’ debt and equity security investments are recorded at fair market value.
__________
| | (a) | Unbilled customer revenues are classified in customer accounts receivables, net in Exelon's and the Utility Registrants' Consolidated Balance Sheets. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Investments | | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | December 31, 2019 | | | | | | | | | | | | | | | | | | Equity method investments: | | | | | | | | | | | | | | | | | | Other equity method investments | $ | 92 |
|
| $ | 71 |
|
| $ | 6 |
|
| $ | 8 |
|
| $ | — |
|
| $ | — |
|
| $ | — |
|
| $ | — |
|
| $ | — |
| Other investments: | | | | | | | | | | | | | | | | | | Employee benefit trusts and investments(a) | 262 |
|
| 54 |
|
| — |
|
| 19 |
|
| 7 |
|
| 135 |
|
| 110 |
|
| — |
|
| — |
| Equity investments without readily determinable fair values | 69 |
|
| 69 |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
| Other available for sale debt security investments | 41 |
|
| 41 |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
| Total investments | $ | 464 |
|
| $ | 235 |
|
| $ | 6 |
|
| $ | 27 |
|
| $ | 7 |
|
| $ | 135 |
|
| $ | 110 |
|
| $ | — |
|
| $ | — |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2018 | | | | | | | | | | | | | | | | | | Equity method investments: | | | | | | | | | | | | | | | | | | Distributed energy companies | $ | 180 |
| | $ | 180 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| Other equity method investments | 87 |
| | 71 |
| | 6 |
| | 8 |
| | — |
| | — |
| | — |
| | — |
| | — |
| Total equity method investments | 267 |
|
| 251 |
|
| 6 |
|
| 8 |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
| Other investments: | | | | | | | | | | | | | | | | | | Employee benefit trusts and investments(a) | 244 |
|
| 49 |
|
| — |
|
| 17 |
|
| 5 |
|
| 130 |
|
| 105 |
|
| — |
|
| — |
| Equity investments without readily determinable fair values | 72 |
|
| 72 |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
| Other available for sale debt security investments | 40 |
|
| 40 |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
| Other | 2 |
|
| 2 |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
| Total investments | $ | 625 |
| | $ | 414 |
| | $ | 6 |
| | $ | 25 |
| | $ | 5 |
| | $ | 130 |
| | $ | 105 |
| | $ | — |
| | $ | — |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Accrued expenses | | Exelon | | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | December 31, 2021 | | | | | | | | | | | | | | | | | | Compensation-related accruals(a) | $ | 991 | | | | | $ | 155 | | | $ | 77 | | | $ | 78 | | | $ | 113 | | | $ | 35 | | | $ | 20 | | | $ | 17 | | Taxes accrued | 495 | | | | | 94 | | | 14 | | | 53 | | | 96 | | | 88 | | | 9 | | | 11 | | Interest accrued | 341 | | | | | 116 | | | 41 | | | 44 | | | 52 | | | 28 | | | 8 | | | 11 | | | | | | | | | | | | | | | | | | | | December 31, 2020 | | | | | | | | | | | | | | | | | | Compensation-related accruals(a) | $ | 1,069 | | | | | $ | 170 | | | $ | 73 | | | $ | 84 | | | $ | 109 | | | $ | 36 | | | $ | 18 | | | $ | 17 | | Taxes accrued | 527 | | | | | 94 | | | 16 | | | 73 | | | 117 | | | 90 | | | 18 | | | 12 | | Interest accrued | 331 | | | | | 109 | | | 37 | | | 46 | | | 51 | | | 26 | | | 7 | | | 12 | |
__________ | | (a) | The Registrants’ debt and equity security investments are recorded at fair market value. |
(a)Primarily includes accrued payroll, bonuses and other incentives, vacation, and benefits.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 2325 — Supplemental Financial InformationRelated Party Transactions
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Accrued expenses | | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | December 31, 2019 | | | | | | | | | | | | | | | | | | Compensation-related accruals(a) | $ | 1,052 |
| | $ | 422 |
| | $ | 171 |
| | $ | 58 |
| | $ | 78 |
| | $ | 101 |
| | $ | 28 |
| | $ | 19 |
| | $ | 15 |
| Taxes accrued | 414 |
| | 222 |
| | 83 |
| | 3 |
| | 26 |
| | 117 |
| | 90 |
| | 14 |
| | 8 |
| Interest accrued | 337 |
| | 65 |
| | 110 |
| | 37 |
| | 46 |
| | 49 |
| | 23 |
| | 8 |
| | 12 |
| | | | | | | | | | | | | | | | | | | December 31, 2018 | | | | | | | | | | | | | | | | | | Compensation-related accruals(a) | $ | 1,191 |
| | $ | 479 |
| | $ | 187 |
| | $ | 49 |
| | $ | 68 |
| | $ | 99 |
| | $ | 29 |
| | $ | 19 |
| | $ | 12 |
| Taxes accrued | 412 |
| | 226 |
| | 71 |
| | 28 |
| | 46 |
| | 74 |
| | 58 |
| | 4 |
| | 5 |
| Interest accrued | 334 |
| | 77 |
| | 105 |
| | 33 |
| | 39 |
| | 50 |
| | 25 |
| | 8 |
| | 12 |
|
__________
| | (a) | Primarily includes accrued payroll, bonuses and other incentives, vacation and benefits. |
24.25. Related Party Transactions (All Registrants)
Operating revenues from affiliates
Utility Registrants' expense with Generation The followingUtility Registrants incur expenses from transactions with the Generation affiliate as described in the footnotes to the table presents Generation’s Operating revenues from affiliates, whichbelow. Such expenses are primarily recorded as Purchased power from affiliates and an immaterial amount recorded as Operating and maintenance expense from affiliates at the Utility Registrants: | | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | | 2021 | | 2020 | | 2019 | ComEd(a) | $ | 376 | | | $ | 330 | | | $ | 369 | | PECO(b) | 196 | | | 190 | | | 158 | | BGE(c) | 236 | | | 315 | | | 289 | | PHI | 366 | | | 367 | | | 353 | | Pepco(d) | 270 | | | 279 | | | 264 | | DPL(e) | 79 | | | 75 | | | 70 | | ACE(f) | 17 | | | 13 | | | 19 | | | | | | | | | | | | | |
| | | | | | | | | | | | | | For the Years Ended December 31, | | 2019 | | 2018 | | 2017 | Operating revenues from affiliates: | | | | | | ComEd (a)(b) | $ | 369 |
| | $ | 523 |
| | $ | 121 |
| PECO (c) | 158 |
| | 128 |
| | 138 |
| BGE (d) | 289 |
| | 260 |
| | 388 |
| PHI | 353 |
| | 355 |
| | 463 |
| Pepco (e) | 264 |
| | 206 |
| | 255 |
| DPL (f) | 70 |
| | 120 |
| | 179 |
| ACE (g) | 19 |
| | 29 |
| | 29 |
| Other | 3 |
| | 2 |
| | 5 |
| Total operating revenues from affiliates (Generation) | $ | 1,172 |
| | $ | 1,268 |
| | $ | 1,115 |
|
____________________(a)ComEd has an ICC-approved RFP contract with Generation to provide a portion of ComEd’s electric supply requirements. ComEd also purchases RECs and ZECs from Generation.
| | (a) | Generation has an ICC-approved RFP contract with ComEd to provide a portion of ComEd’s electricity supply requirements. Generation also sells RECs and ZECs to ComEd. |
| | (b) | For 2019, ComEd’s Purchased power from Generation of $376 million is recorded as Operating revenues from ComEd of $369 million and Purchased power and fuel from ComEd of $7 million at Generation. For 2018, ComEd’s Purchased power from Generation of $529 million is recorded as Operating revenues from ComEd of $523 million and Purchased power and fuel from ComEd of $6 million at Generation. |
| | (c) | Generation provides electric supply to PECO under contracts executed through PECO’s competitive procurement process. In addition, Generation has a ten-year agreement with PECO to sell solar AECs. |
| | (d) | Generation provides a portion of BGE’s energy requirements under its MDPSC-approved market-based SOS and gas commodity programs. |
| | (e) | Generation provides electric supply to Pepco under contracts executed through Pepco's competitive procurement process approved by the MDPSC and DCPSC. |
| | (f) | Generation provides a portion of DPL's energy requirements under its MDPSC and DPSC approved market based SOS and gas commodity programs. |
(b)PECO receives electric supply from Generation under contracts executed through PECO’s competitive procurement process. In addition, PECO has a ten-year agreement with Generation to sell solar AECs.
Combined Notes to Consolidated Financial Statements(d)Pepco receives electric supply from Generation under contracts executed through Pepco's competitive procurement process approved by the MDPSC and DCPSC.
(Dollars in millions, except per share data unless otherwise noted)(e)DPL receives a portion of its energy requirements from Generation under its MDPSC and DEPSC approved market-based SOS commodity programs.
(f)ACE receives electric supply from Generation under contracts executed through ACE's competitive procurement process.
Note 24 — Related Party Transactions
| | (g) | Generation provides electric supply to ACE under contracts executed through ACE's competitive procurement process. |
PHI
PHI’s Operating revenues from affiliates are primarily with BSCService Company Costs for services that PHISCO provides to BSC.
Operating and maintenance expense from affiliatesCorporate 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:333 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Operating and maintenance from affiliates | | Operating and maintenance | | Capitalized costs | | | For the years ended December 31, | | For the years ended December 31, | | For the years ended December 31, | | | 2019 | | 2018 | | 2017 | | 2017 | | 2019 | | 2018 | | 2017 | Exelon | | | | | | | | | | | | | | | BSC | |
| |
| |
| |
| | $ | 516 |
| | $ | 448 |
| | $ | 330 |
| PHISCO | |
| |
| |
| |
| | 72 |
| | 79 |
| | — |
| Generation | | | | | | | | | | | | | | | BSC | | $ | 570 |
| | $ | 652 |
| | $ | 689 |
| | $ | — |
| | 66 |
| | 67 |
| | 98 |
| ComEd | | | | | | | | | | | | | | | BSC | | 263 |
| | 265 |
| | 270 |
| | — |
| | 148 |
| | 135 |
| | 118 |
| PECO | | | | | | | | | | | | | | | BSC | | 149 |
| | 146 |
| | 146 |
| | — |
| | 88 |
| | 64 |
| | 59 |
| BGE | | | | | | | | | | | | | | | BSC | | 157 |
| | 157 |
| | 152 |
| | — |
| | 126 |
| | 79 |
| | 54 |
| PHI | | | | | | | | | | | | | | | BSC | | 139 |
| | 147 |
| | 145 |
| | — |
| | 88 |
| | 102 |
| | — |
| PHISCO (a) | | — |
| | — |
| | — |
| | — |
| | 72 |
| | 79 |
| | — |
| Pepco | | | | | | | | | | | | | | | BSC | | 85 |
| | 89 |
| | 53 |
| | — |
| | 38 |
| | 40 |
| | — |
| PHISCO (a) | | 124 |
| | 137 |
| | 5 |
| | 219 |
| | 33 |
| | 32 |
| | — |
| PES (b) | | — |
| | — |
| | — |
| | 29 |
| | — |
| | — |
| | — |
| DPL | | | | | | | | | | | | | | | BSC | | 52 |
| | 51 |
| | 31 |
| | — |
| | 25 |
| | 28 |
| | — |
| PHISCO (a) | | 100 |
| | 111 |
| | — |
| | 165 |
| | 20 |
| | 25 |
| | — |
| PES (b) | | — |
| | — |
| | — |
| | 9 |
| | — |
| | — |
| | — |
| ACE | | | | | | | | | | | | | | | BSC | | 42 |
| | 42 |
| | 25 |
| | — |
| | 19 |
| | 20 |
| | — |
| PHISCO (a) | | 90 |
| | 98 |
| | — |
| | 135 |
| | 19 |
| | 21 |
| | — |
|
__________
| | (a) | Due to the PHI entities' system conversion to Exelon's accounting systems on January 1, 2018, corporate support services received from PHISCO are reported in Operating and maintenance from affiliates and in Capitalized costs beginning in 2018. |
| | (b) | PES performed underground transmission, distribution construction and maintenance services, including services that are treated as capital costs, for Pepco and DPL. |
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 2425 — Related Party Transactions
The following table presents the service company costs allocated to the Registrants:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Operating and maintenance from affiliates | | Capitalized costs | | | For the years ended December 31, | | For the years ended December 31, | | | 2021 | | 2020 | | 2019 | | 2021 | | 2020 | | 2019 | Exelon | | | | | | | | | | | | | BSC | | | | | | | | $ | 637 | | | $ | 585 | | | $ | 516 | | PHISCO | | | | | | | | 72 | | | 61 | | | 72 | | | | | | | | | | | | | | | | | | | | | | | | | | | | ComEd | | | | | | | | | | | | | BSC | | 304 | | | 283 | | | 263 | | | 207 | | | 186 | | | 148 | | PECO | | | | | | | | | | | | | BSC | | 169 | | | 150 | | | 149 | | | 81 | | | 76 | | | 88 | | BGE | | | | | | | | | | | | | BSC | | 189 | | | 170 | | | 157 | | | 92 | | | 132 | | | 126 | | PHI | | | | | | | | | | | | | BSC | | 168 | | | 152 | | | 139 | | | 128 | | | 149 | | | 88 | | PHISCO | | — | | | — | | | — | | | 72 | | | 61 | | | 72 | | Pepco | | | | | | | | | | | | | BSC | | 96 | | | 85 | | | 85 | | | 50 | | | 55 | | | 38 | | PHISCO | | 114 | | | 120 | | | 124 | | | 31 | | | 27 | | | 33 | | DPL | | | | | | | | | | | | | BSC | | 61 | | | 54 | | | 52 | | | 43 | | | 51 | | | 25 | | PHISCO | | 99 | | | 97 | | | 100 | | | 22 | | | 18 | | | 20 | | ACE | | | | | | | | | | | | | BSC | | 53 | | | 45 | | | 42 | | | 33 | | | 40 | | | 19 | | PHISCO | | 86 | | | 87 | | | 90 | | | 19 | | | 16 | | | 19 | |
Current Receivables from/Payables to affiliates The following tables present currentCurrent receivables from affiliates and currentCurrent payables to affiliates: December 31, 20192021 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
334
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Receivables from affiliates: | | | Payables to affiliates: | | Generation | | Comed | | PECO | | BGE | | ACE | | BSC | | PHISCO | | Other | | Total | Generation | | | | $ | 27 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 67 |
| | $ | — |
| | $ | 23 |
| | $ | 117 |
| ComEd | | $ | 78 |
| (a) | | | — |
| | — |
| | — |
| | 54 |
| | — |
| | 8 |
| | 140 |
| PECO | | 27 |
| | — |
| | | | — |
| | — |
| | 25 |
| | — |
| | 3 |
| | 55 |
| BGE | | 28 |
| | — |
| | — |
| | | | — |
| | 34 |
| | — |
| | 4 |
| | 66 |
| PHI | | — |
| | — |
| | — |
| | — |
| | — |
| | 4 |
| | — |
| | 10 |
| | 14 |
| Pepco | | 34 |
| | — |
| | — |
| | — |
| | — |
| | 16 |
| | 15 |
| | 1 |
| | 66 |
| DPL | | 7 |
| | — |
| | — |
| | — |
| | 3 |
| | 10 |
| | 11 |
| | 1 |
| | 32 |
| ACE | | 7 |
| | — |
| | — |
| | — |
| |
| | 7 |
| | 10 |
| | 1 |
| | 25 |
| Other | | 9 |
| | 1 |
| | 1 |
| | 1 |
| | 1 |
| | — |
| | — |
| | | | 13 |
| Total | | $ | 190 |
| | $ | 28 |
| | $ | 1 |
| | $ | 1 |
| | $ | 4 |
| | $ | 217 |
| | $ | 36 |
| | $ | 51 |
| | $ | 528 |
|
December 31, 2018
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Receivables from affiliates: | | | Payables to affiliates: | | Generation | | Comed | | BGE | | Pepco | | ACE | | BSC | | PHISCO | | Other | | Total | Generation | | | | $ | 19 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 95 |
| | $ | — |
| | $ | 25 |
| | $ | 139 |
| ComEd | | $ | 69 |
| (a) | | | — |
| | — |
| | — |
| | 56 |
| | — |
| | 8 |
| | 133 |
| PECO | | 30 |
| | — |
| | — |
| | — |
| | — |
| | 26 |
| | — |
| | 3 |
| | 59 |
| BGE | | 24 |
| | — |
| | | | — |
| | — |
| | 38 |
| | — |
| | 3 |
| | 65 |
| PHI | | — |
| | — |
| | — |
| | — |
| | — |
| | 3 |
| | — |
| | 9 |
| | 12 |
| Pepco | | 28 |
| | — |
| | — |
| | | | — |
| | 19 |
| | 14 |
| | 1 |
| | 62 |
| DPL | | 7 |
| | — |
| | — |
| | 1 |
| | 1 |
| | 11 |
| | 12 |
| | 1 |
| | 33 |
| ACE | | 5 |
| | — |
| | — |
| | — |
| | | | 8 |
| | 13 |
| | 2 |
| | 28 |
| Other | | 10 |
| | 1 |
| | 1 |
| | — |
| | — |
| | — |
| | — |
| | | | 12 |
| Total | | $ | 173 |
| | $ | 20 |
| | $ | 1 |
| | $ | 1 |
| | $ | 1 |
| | $ | 256 |
| | $ | 39 |
| | $ | 52 |
| | $ | 543 |
|
__________
| | (a) | At December 31, 2019 and 2018, Generation also had a contract liability with ComEd for $37 million and $14 million, respectively, that was included in Other liabilities on Generation’s Consolidated Balance Sheets. At December 31, 2019 and 2018, ComEd had a Current Payable to Generation of $41 million and $55 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. |
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 2425 — Related Party Transactions
December 31, 2020
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Receivables from affiliates: | | | Payables to affiliates: | | ComEd | | PECO | | BGE | | | | Pepco | | DPL | | ACE | | Generation | | BSC | | PHISCO | | Other | | Total | ComEd | | | | $ | — | | | $ | — | | | | | $ | — | | | $ | — | | | $ | — | | | $ | 28 | | | $ | 59 | | | $ | — | | | $ | 9 | | | $ | 96 | | PECO | | 1 | | | | | — | | | | | — | | | — | | | — | | | 17 | | | 28 | | | — | | | 4 | | | 50 | | BGE | | — | | | — | | | | | | | — | | | — | | | — | | | 11 | | | 47 | | | — | | | 3 | | | 61 | | PHI | | — | | | — | | | — | | | | | — | | | — | | | — | | | — | | | 4 | | | — | | | 11 | | | 15 | | Pepco | | 2 | | | — | | | 1 | | | | | | | — | | | — | | | 13 | | | 25 | | | 14 | | | — | | | 55 | | DPL | | 1 | | | — | | | — | | | | | — | | | | | — | | | 3 | | | 21 | | | 10 | | | 1 | | | 36 | | ACE | | — | | | — | | | — | | | | | — | | | — | | | | | 6 | | | 15 | | | 9 | | | 1 | | | 31 | | Generation | | 13 | | | — | | | — | | | | | — | | | — | | | — | | | | | 72 | | | — | | | 22 | | | 107 | | Other | | 5 | | | 2 | | | 2 | | | | | 2 | | | 1 | | | 6 | | | 25 | | | — | | | — | | | | | 43 | | Total | | $ | 22 | | | $ | 2 | | | $ | 3 | | | | | $ | 2 | | | $ | 1 | | | $ | 6 | | | $ | 103 | | | $ | 271 | | | $ | 33 | | | $ | 51 | | | $ | 494 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
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. See Note 910 — Asset Retirement Obligations for additional information.
The following table presents noncurrent receivables from affiliates at ComEd and PECO which are recorded as noncurrent payables to affiliates at Generation:
| | | | | | | | | | December 31, | | 2019 | | 2018 | ComEd | $ | 2,622 |
| | $ | 2,217 |
| PECO | 480 |
| | 389 |
| Other | 1 |
| | — |
| Total: | $ | 3,103 |
| | $ | 2,606 |
|
Long-term debt to financing trusts The following table presents Long-term debt to financing trusts: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | As of December 31, | | 2021 | | 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 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | As of December 31, | | 2019 | | 2018 | | 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
26. Separation (Exelon) On February 21, 2021, Exelon’s Board of Directors approved a plan to affiliates In connectionseparate the Utility Registrants and Generation, creating two publicly traded companies ("the separation").
On February 25, 2021, Exelon 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 debt obligations assumed by Exelon as partIRS to confirm the tax-free treatment of the Constellation merger,separation, which was received on September 23, 2021. Exelon received approval from FERC on August 24, 2021, NRC on November 16, 2021, and subsidiaries of Generation (former Constellation subsidiaries) assumed intercompany loan agreements that mirrorNYPSC on December 16, 2021 for the terms and amounts ofseparation.
The Form 10 registration statement was declared effective by 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. SEC on December 29, 2021.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 2526 — Quarterly DataSeparation
25. Quarterly Data (Unaudited) (All Registrants)
Exelon The data shown below, which may not equal completed the totalseparation on February 1, 2022, through the distribution of 326,663,937 common stock shares of Constellation Energy Corporation, 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 Energy Corporation common stock for every three shares of Exelon common stock held on January 20, 2022, the record date for the year duedistribution, in a transaction that is tax-free to Exelon and its shareholders for U.S. federal income tax purposes.
In order to govern the ongoing relationships between Exelon and Constellation Energy Corporation after the separation, and to facilitate an orderly transition, Exelon and Constellation Energy Corporation have entered into several agreements, including a Separation Agreement, Tax Matters Agreement, a Transition Services Agreement, and an Employee Matters Agreement, and other ancillary agreements. Pursuant to the effectsSeparation Agreement, Exelon made a cash payment of rounding$1.75 billion to Generation on January 31, 2022. Exelon issued term loans of $2.0 billion on January 21, 2022 and dilution, includes all adjustments that Exelon considers necessaryJanuary 24, 2022 primarily to fund the cash payment to Constellation Energy Corporation and for a fair presentation of such amounts:general corporate purposes. See Note 17 — Debt and Credit Agreements for additional information. | | | | | | | | | | | | | | | | | | | | | | | | | | Operating Revenues | | Operating Income | | Net Income Attributable to Common Shareholders | | 2019 | | 2018 | | 2019 | | 2018 | | 2019 | | 2018 | Quarter ended: | | | | | | | | | | | | March 31 | $ | 9,477 |
| | $ | 9,691 |
| | $ | 1,218 |
| | $ | 1,099 |
| | $ | 907 |
| | $ | 583 |
| June 30 | 7,689 |
| | 8,074 |
| | 841 |
| | 940 |
| | 484 |
| | 537 |
| September 30 | 8,929 |
| | 9,401 |
| | 1,353 |
| | 1,144 |
| | 772 |
| | 731 |
| December 31(a) | 8,343 |
| | 8,812 |
| | 962 |
| | 706 |
| | 773 |
| | 152 |
|
| | | | | | | | | | | | | | | | | | Net Income per Basic Share | | Net Income per Diluted Share | | 2019 | | 2018 | | 2019 | | 2018 | Quarter ended: | | | | | | | | March 31 | $ | 0.93 |
| | $ | 0.60 |
| | $ | 0.93 |
| | $ | 0.60 |
| June 30 | 0.50 |
| | 0.56 |
| | 0.50 |
| | 0.55 |
| September 30 | 0.79 |
| | 0.76 |
| | 0.79 |
| | 0.75 |
| December 31 | 0.79 |
| | 0.16 |
| | 0.79 |
| | 0.16 |
|
__________
| | | | | | (a) | Operating revenues, Operating income and Net income attributable to common shareholders for the quarter ended December 31, 2019 include a $6 million reduction related to a correction for Pepco’s decoupling mechanism for the 2019 interim periods. See Note 1 — Significant Accounting Policies for additional information. |
Generation
The data shown below includes all adjustments that Generation considers necessary for a fair presentation of such amounts:
| | | | | | | | | | | | | | | | | | | | | | | | | | Operating Revenues | | Operating Income | | Net Income (Loss) Attributable to Membership Interest | | 2019 | | 2018 | | 2019 | | 2018 | | 2019 | | 2018 | Quarter ended: | | | | | | | | | | | | March 31 | $ | 5,296 |
| | $ | 5,512 |
| | $ | 333 |
| | $ | 347 |
| | $ | 363 |
| | $ | 136 |
| June 30 | 4,210 |
| | 4,579 |
| | 147 |
| | 282 |
| | 108 |
| | 178 |
| September 30 | 4,774 |
| | 5,278 |
| | 482 |
| | 311 |
| | 257 |
| | 234 |
| December 31 | 4,644 |
| | 5,069 |
| | 362 |
| | 35 |
| | 397 |
| | (178 | ) |
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 25 — Quarterly Data
ComEd
The data shown below includes all adjustments that ComEd considers necessary for a fair presentation of such amounts:
| | | | | | | | | | | | | | | | | | | | | | | | | | Operating Revenues | | Operating Income | | Net Income | | 2019 | | 2018 | | 2019 | | 2018 | | 2019 | | 2018 | Quarter ended: | | | | | | | | | | | | March 31 | $ | 1,408 |
| | $ | 1,512 |
| | $ | 276 |
| | $ | 292 |
| | $ | 157 |
| | $ | 165 |
| June 30 | 1,351 |
| | 1,398 |
| | 311 |
| | 288 |
| | 186 |
| | 164 |
| September 30 | 1,583 |
| | 1,598 |
| | 328 |
| | 323 |
| | 200 |
| | 193 |
| December 31 | 1,405 |
| | 1,373 |
| | 255 |
| | 242 |
| | 144 |
| | 141 |
|
PECO
The data shown below includes all adjustments that PECO considers necessary for a fair presentation of such amounts:
| | | | | | | | | | | | | | | | | | | | | | | | | | Operating Revenues | | Operating Income | | Net Income | | 2019 | | 2018 | | 2019 | | 2018 | | 2019 | | 2018 | Quarter ended: | | | | | | | | | | | | March 31 | $ | 900 |
| | $ | 866 |
| | $ | 222 |
| | $ | 142 |
| | $ | 168 |
| | $ | 113 |
| June 30 | 655 |
| | 653 |
| | 145 |
| | 127 |
| | 102 |
| | 96 |
| September 30 | 778 |
| | 757 |
| | 183 |
| | 154 |
| | 140 |
| | 126 |
| December 31 | 766 |
| | 765 |
| | 162 |
| | 165 |
| | 118 |
| | 124 |
|
BGE
The data shown below includes all adjustments that BGE considers necessary for a fair presentation of such amounts:
| | | | | | | | | | | | | | | | | | | | | | | | | | Operating Revenues | | Operating Income | | Net Income | | 2019 | | 2018 | | 2019 | | 2018 | | 2019 | | 2018 | Quarter ended: | | | | | | | | | | | | March 31 | $ | 976 |
| | $ | 977 |
| | $ | 220 |
| | $ | 177 |
| | $ | 160 |
| | $ | 128 |
| June 30 | 649 |
| | 662 |
| | 80 |
| | 85 |
| | 45 |
| | 51 |
| September 30 | 703 |
| | 731 |
| | 91 |
| | 103 |
| | 55 |
| | 63 |
| December 31 | 779 |
| | 799 |
| | 142 |
| | 109 |
| | 99 |
| | 71 |
|
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 25 — Quarterly Data
PHI
The data shown below includes all adjustments that PHI considers necessary for a fair presentation of such amounts:
| | | | | | | | | | | | | | | | | | | | | | | | | | Operating Revenues | | Operating Income | | Net Income | | 2019 | | 2018 | | 2019 | | 2018 | | 2019 | | 2018 | Quarter ended: | | | | | | | | | | | | March 31 | $ | 1,228 |
| | $ | 1,249 |
| | $ | 175 |
| | $ | 124 |
| | $ | 117 |
| | $ | 63 |
| June 30 | 1,091 |
| | 1,074 |
| | 165 |
| | 151 |
| | 106 |
| | 82 |
| September 30 | 1,380 |
| | 1,359 |
| | 256 |
| | 243 |
| | 189 |
| | 185 |
| December 31(a) | 1,107 |
| | 1,115 |
| | 128 |
| | 124 |
| | 65 |
| | 62 |
|
__________
| | (a) | Operating revenues, Operating income and Net income attributable to common shareholders for the quarter ended December 31, 2019 include a $6 million reduction related to a correction for Pepco’s decoupling mechanism for the 2019 interim periods. See Note 1 — Significant Accounting Policies for additional information. |
Pepco
The data shown below includes all adjustments that Pepco considers necessary for a fair presentation of such amounts:
| | | | | | | | | | | | | | | | | | | | | | | | | | Operating Revenues | | Operating Income | | Net Income | | 2019 | | 2018 | | 2019 | | 2018 | | 2019 | | 2018 | Quarter ended: | | | | | | | | | | | | March 31 | $ | 575 |
| | $ | 555 |
| | $ | 84 |
| | $ | 54 |
| | $ | 55 |
| | $ | 29 |
| June 30 | 531 |
| | 521 |
| | 93 |
| | 83 |
| | 64 |
| | 52 |
| September 30 | 642 |
| | 626 |
| | 127 |
| | 110 |
| | 98 |
| | 87 |
| December 31(a) | 513 |
| | 529 |
| | 57 |
| | 63 |
| | 26 |
| | 36 |
|
_________
| | (a) | Operating revenues, Operating income and Net income attributable to common shareholders for the quarter ended December 31, 2019 include a $6 million reduction related to a correction for Pepco’s decoupling mechanism for the 2019 interim periods. See Note 1 — Significant Accounting Policies for additional information. |
DPL
The data shown below includes all adjustments that DPL considers necessary for a fair presentation of such amounts:
| | | | | | | | | | | | | | | | | | | | | | | | | | Operating Revenues | | Operating Income | | Net Income | | 2019 | | 2018 | | 2019 | | 2018 | | 2019 | | 2018 | Quarter ended: | | | | | | | | | | | | March 31 | $ | 380 |
| | $ | 384 |
| | $ | 72 |
| | $ | 49 |
| | $ | 53 |
| | $ | 31 |
| June 30 | 287 |
| | 289 |
| | 44 |
| | 42 |
| | 30 |
| | 26 |
| September 30 | 319 |
| | 328 |
| | 51 |
| | 51 |
| | 33 |
| | 33 |
| December 31 | 319 |
| | 331 |
| | 50 |
| | 48 |
| | 31 |
| | 30 |
|
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 25 — Quarterly Data
ACE
The data shown below includes all adjustments that ACE considers necessary for a fair presentation of such amounts:
| | | | | | | | | | | | | | | | | | | | | | | | | | Operating Revenues | | Operating Income | | Net Income (Loss) | | 2019 | | 2018 | | 2019 | | 2018 | | 2019 | | 2018 | Quarter ended: | | | | | | | | | | | | March 31 | $ | 273 |
| | $ | 310 |
| | $ | 21 |
| | $ | 23 |
| | $ | 10 |
| | $ | 7 |
| June 30 | 274 |
| | 265 |
| | 28 |
| | 25 |
| | 14 |
| | 8 |
| September 30 | 419 |
| | 406 |
| | 79 |
| | 84 |
| | 63 |
| | 61 |
| December 31 | 274 |
| | 254 |
| | 23 |
| | 14 |
| | 12 |
| | (1 | ) |
| | | ITEM 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
All Registrants None. | | | | | | ITEM 9A. | CONTROLS AND PROCEDURES |
All Registrants—Disclosure Controls and Procedures During the fourth quarter of 2019,2021, each registrant’sof the Registrant’s management, including its principal executive officer and principal financial officer, evaluated the effectiveness of that registrant’s disclosure controls and procedures related to the recording, processing, summarizing, and reporting of information in that registrant’s periodic reports that it files with the SEC. These disclosure controls and procedures have been designed by each registrant to ensure that (a) information relating to that registrant,Registrant, including its consolidated subsidiaries, that is required to be included in filings under the Securities Exchange Act of 1934, is accumulated and made known to that 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 December 31, 2019,2021, the principal executive officer and principal financial officer of each registrantof the Registrants concluded that such registrant’sRegistrant’s disclosure controls and procedures were effective to accomplish their objectives. All Registrants—Changes in Internal Control Over Financial Reporting Each registrant continually strives to improve its disclosure controls and procedures to enhance the quality of its financial reporting and to maintain dynamic systems that change as conditions warrant. However, there have been no changes in internal control over financial reporting that occurred during the fourth quarter of 20192021 that have materially affected, or are reasonably likely to materially affect, any of the registrant'sRegistrant's internal control over financial reporting. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - Executive Overview for additional information on COVID-19. All Registrants—Internal Control Over Financial Reporting Management is required to assess and report on the effectiveness of its internal control over financial reporting as of December 31, 2019.2021. As a result of that assessment, management determined that there were no material weaknesses as of December 31, 20192021 and, therefore, concluded that each registrant’s internal control over
financial reporting was effective. Management’s Report on Internal Control Over Financial Reporting is included in ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. | | | | | | ITEM 9B. | OTHER INFORMATION |
All Registrants None.
| | | | | | ITEM 9C. | DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS |
Not Applicable
PART III Exelon Generation Company, LLC, PECO Energy Company, Baltimore Gas and Electric Company, Pepco Holdings LLC, Potomac Electric Power Company, Delmarva Power & Light Company, and Atlantic City Electric Company meet the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K for a reduced disclosure format. Accordingly, all items in this section relating to Generation, PECO, BGE, PHI, Pepco, DPL, and ACE are not presented.
| | | | | | ITEM 10. | DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE |
Executive Officers The information required by ITEM 10.10 relating to executive officers is set forth above in ITEM 1. BUSINESS—Executive officers of the Registrants at February 11, 2020.25, 2022. Directors, Director Nomination Process and Audit Committee The information required under ITEM 10 concerning directors and nominees for election as directors at the annual meeting of shareholders (Item 401 of Regulation S-K), the director nomination process (Item 407(c)(3)), the audit committee (Item 407(d)(4) and (d)(5)), and the beneficial reporting compliance (Sec. 16(a)) is incorporated herein by reference to information to be contained in Exelon’s definitive 20202022 proxy statement (2020(2022 Exelon Proxy Statement) and the ComEd information statement (2020(2022 ComEd Information Statement) to be filed with the SEC on or before April 30, 20202022 pursuant to Regulation 14A or 14C, as applicable, under the Securities Exchange Act of 1934. Code of Ethics Exelon’s Code of Business Conduct is the code of ethics that applies to Exelon’s and ComEd’s Chief Executive Officer, Chief Financial Officer, Corporate Controller, and other finance organization employees. The Code of Business Conduct is filed as Exhibit 14 to this report and is available on Exelon’s website at www.exeloncorp.com. The Code of Business Conduct will be made available, without charge, in print to any shareholder who requests such document from Carter C. Culver, Senior Vice President and Deputy General Counsel, Exelon Corporation, P.O. Box 805398, Chicago, Illinois 60680-5398. If any substantive amendments to the Code of Business Conduct are made or any waivers are granted, including any implicit waiver, from a provision of the Code of Business Conduct, to its Chief Executive Officer, Chief Financial Officer or Corporate Controller, Exelon will disclose the nature of such amendment or waiver on Exelon’s website, www.exeloncorp.com, or in a report on Form 8-K.
| | | | | | ITEM 11. | EXECUTIVE COMPENSATION |
The information required by this item will be set forth under Executive Compensation Data and Report of the Compensation Committee in the Exelon Proxy Statement for the 20202022 Annual Meeting of Shareholders or the ComEd 20202022 Information Statement, which are incorporated herein by reference.
| | | | | | ITEM 12. | SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS |
The additional information required by this item will be set forth under Ownership of Exelon Stock in the 20202022 Exelon Proxy Statement or the ComEd 20202022 Information Statement and incorporated herein by reference. Securities Authorized for Issuance under Exelon Equity Compensation Plans | | | [A] | | [B] | | [C] | | [A] | | [B] | | [C] | Plan Category | Number of securities to be issued upon exercise of outstanding Options, warrants and rights (Note 1) | | Weighted-average price of outstanding Options, warrants and rights (Note 2) | | Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column [A]) (Note 3) | Plan Category | Number of securities to be issued upon exercise of outstanding Options, warrants and rights (Note 1) | | Weighted-average price of outstanding Options, warrants and rights (Note 2) | | Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column [A]) (Note 3) | Equity compensation plans approved by security holders | 8,738,206 |
| | $ | 21.17 |
| | 31,091,584 |
| Equity compensation plans approved by security holders | 5,343,357 | | | $ | 0.22 | | | 48,184,437 | |
__________ | | (1) | Balance includes stock options, unvested performance shares, and unvested restricted shares granted under the Exelon LTIP or predecessor company plans including shares awarded under those plans and deferred into the stock deferral plan, and deferred stock units granted to directors as part of their compensation. Unvested performance shares are subject to performance metrics ranging from 0% to 150% of target award values and to a total shareholder return modifier. For performance shares granted in 2017, 2018 and 2019, the total includes the number of shares that could be issued pursuant to the terms of the Exelon LTIP plan, which provides that final payouts are made 50% in shares of stock and 50% in cash, and if the performance and total shareholder return modifier metrics were both at maximum, representing a best case performance scenario, for a total of 4,005,200 shares. If the performance and total shareholder return modifier metrics were at target, the number of securities to be issued for such awards would be 2,002,600. The deferred stock units granted to directors includes 467,218 shares to be issued upon the conversion of deferred stock units awarded to members of the Exelon Board of Directors. Conversion of the deferred stock units to shares occurs after a director terminates service to the Exelon board or the board of any of its subsidiary companies. See Note 20 — Stock-Based Compensation Plans of the Combined Notes to Consolidated Financial Statements for additional information about the material features of the plans. |
| | (2) | The weighted-average price reported in column B does not take the performance shares and shares credited to deferred compensation plans into account. |
| | (3) | Includes 17,125,705 shares remaining available for issuance from the employee stock purchase plan. |
(1)Balance includes stock options, unvested performance shares, and unvested restricted stock units that were granted under the Exelon LTIP or predecessor company plans (including shares awarded under those plans and deferred into the stock deferral plan) and deferred stock units granted to directors as part of their compensation. Unvested performance shares are subject to performance metrics and to a total shareholder return modifier. Additionally, pursuant to the terms of the Exelon LTIP plan, 50% of final payouts are made in the form of shares of common stock and 50% is made in form of in cash, or if the participant has exceeded 200% of their stock ownership requirement, 100% of the final payout is made in cash. For performance shares granted in 2019, 2020, and 2021, the total includes the maximum number of shares that could be issued assuming all participants receive 50% of payouts in shares and assuming the performance and total shareholder return modifier metrics were both at maximum, representing best case performance, for a total of 3,110,870 shares. If the performance and total shareholder return modifier metrics were at "target", the number of securities to be issued for such awards would be 1,555,435. The balance also includes 431,918 shares to be issued upon the conversion of deferred stock units awarded to members of the Exelon board of directors. Conversion of the deferred stock units to shares of common stock occurs after a director terminates service to the Exelon board or the board of any of its subsidiary companies. See Note 21 — Stock-Based Compensation Plans of the Combined Notes to Consolidated Financial Statements for additional information about the material features of the plans. (2)The weighted-average price reported in column B does not take the performance shares and shares credited to deferred compensation plans into account. (3)Includes 13,633,243 shares remaining available for issuance from the employee stock purchase plan and 4,556,610 shares remaining available for issuance to former Constellation employees with outstanding awards made under the prior Constellation LTIP. No ComEd securities are authorized for issuance under equity compensation plans.
| | | | | | ITEM 13. | CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE |
The additional information required by this item will be set forth under Related Persons Transactions and Director Independence in the Exelon Proxy Statement for the 20202022 Annual Meeting of Shareholders or the ComEd 20202022 Information Statement, which are incorporated herein by reference.
| | | | | | ITEM 14. | PRINCIPAL ACCOUNTING FEES AND SERVICES |
The information required by this item will be set forth under The Ratification of PricewaterhouseCoopers LLP as Exelon’s Independent Accountant for 20202022 in the Exelon Proxy Statement for the 20202022 Annual Meeting of Shareholders and the ComEd 20202022 Information Statement, which are incorporated herein by reference.
PART IV | | | | | | ITEM 15. | EXHIBITS, FINANCIAL STATEMENT SCHEDULES |
(a)The following documents are filed as a part of this report: (1) Exelon | | | | | | | | | (i) | | Financial Statements (Item 8): | | | ITEM 15. | EXHIBITS, FINANCIAL STATEMENT SCHEDULES |
| | (a) | The following documents are filed as a part of this report: |
(1) Exelon
| | | | (i) | | Financial Statements (Item 8): | | | | | Report of Independent Registered Public Accounting Firm dated February 11, 202025, 2022 of PricewaterhouseCoopers LLP (PCAOB ID 238) | | | | | Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2019, 20182021, 2020, and 20172019 | | | | | | Consolidated Statements of Cash Flows for the Years Ended December 31, 2019, 20182021, 2020, and 20172019 | | | | | | Consolidated Balance Sheets at December 31, 20192021 and 20182020 | | | | | | Consolidated Statements of Changes in Equity for the Years Ended December 31, 2018, 20172021, 2020, and 20162019 | | | | | | Notes to Consolidated Financial Statements | | | | (ii) | | Financial Statement Schedules: | | | | | | Schedule I—Condensed Financial Information of Parent (Exelon Corporate) at December 31, 20192021 and 20182020 and for the Years Ended December 31, 2019, 20182021, 2020, and 20172019 | | | | | | Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2019, 20182021, 2020, and 2017
2019 | | | | | | Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto. |
Exelon Corporation and Subsidiary Companies Schedule I – Condensed Financial Information of Parent (Exelon Corporate) Condensed Statements of Operations and Other Comprehensive Income | | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | (In millions) | 2021 | | 2020 | | 2019 | Operating expenses | | | | | | Operating and maintenance | $ | (9) | | | $ | (2) | | | $ | 33 | | Operating and maintenance from affiliates | 38 | | | 10 | | | 9 | | Other | 2 | | | 2 | | | 1 | | Total operating expenses | 31 | | | 10 | | | 43 | | Operating loss | (31) | | | (10) | | | (43) | | Other income and (deductions) | | | | | | Interest expense, net | (333) | | | (378) | | | (321) | | Equity in earnings of investments | 1,996 | | | 2,313 | | | 3,254 | | Interest income from affiliates, net | 16 | | | 30 | | | 39 | | Other, net | — | | | 15 | | | 14 | | Total other income | 1,679 | | | 1,980 | | | 2,986 | | Income before income taxes | 1,648 | | | 1,970 | | | 2,943 | | Income taxes | (58) | | | 7 | | | 7 | | Net income | $ | 1,706 | | | $ | 1,963 | | | $ | 2,936 | | Other comprehensive income (loss), net of income taxes | | | | | | Pension and non-pension postretirement benefit plans: | | | | | | Prior service benefit reclassified to periodic costs | $ | (4) | | | $ | (40) | | | $ | (64) | | Actuarial loss reclassified to periodic cost | 223 | | | 190 | | | 148 | | Pension and non-pension postretirement benefit plan valuation adjustment | 431 | | | (357) | | | (289) | | Unrealized (loss) gain on cash flow hedges | — | | | (1) | | | 1 | | Other comprehensive income (loss) | 650 | | | (208) | | | (204) | | Comprehensive income | $ | 2,356 | | | $ | 1,755 | | | $ | 2,732 | |
| | | | | | | | | | | | | | For the Years Ended December 31, | (In millions) | 2019 | | 2018 | | 2017 | Operating expenses | | | | | | Operating and maintenance | $ | 33 |
| | $ | (5 | ) | | $ | 10 |
| Operating and maintenance from affiliates | 9 |
| | 9 |
| | 25 |
| Other | 1 |
| | 4 |
| | 4 |
| Total operating expenses | 43 |
| | 8 |
| | 39 |
| Operating loss | (43 | ) | | (8 | ) | | (39 | ) | Other income and (deductions) | | | | | | Interest expense, net | (321 | ) | | (312 | ) | | (315 | ) | Equity in earnings of investments | 3,254 |
| | 2,183 |
| | 4,407 |
| Interest income from affiliates, net | 39 |
| | 42 |
| | 40 |
| Other, net | 14 |
| | 3 |
| | 1 |
| Total other income | 2,986 |
| | 1,916 |
| | 4,133 |
| Income before income taxes | 2,943 |
| | 1,908 |
| | 4,094 |
| Income taxes | 7 |
| | (97 | ) | | 315 |
| Net income | $ | 2,936 |
| | $ | 2,005 |
| | $ | 3,779 |
| Other comprehensive income (loss) | | | | | | Pension and non-pension postretirement benefit plans: | | | | | | Prior service benefit reclassified to periodic costs | $ | (64 | ) | | $ | (66 | ) | | $ | (56 | ) | Actuarial loss reclassified to periodic cost | 148 |
| | 247 |
| | 197 |
| Pension and non-pension postretirement benefit plan valuation adjustment | (289 | ) | | (143 | ) | | 10 |
| Unrealized gain on cash flow hedges | 1 |
| | 12 |
| | 3 |
| Unrealized gain on marketable securities | — |
| | — |
| | 6 |
| Unrealized gain on equity investments | — |
| | 1 |
| | 6 |
| Unrealized (loss) gain on foreign currency translation | — |
| | (10 | ) | | 7 |
| Other comprehensive income (loss) | (204 | ) |
| 41 |
|
| 173 |
| Comprehensive income | $ | 2,732 |
| | $ | 2,046 |
| | $ | 3,952 |
|
See the Notes to Financial Statements
377344
Exelon Corporation and Subsidiary Companies Schedule I – Condensed Financial Information of Parent (Exelon Corporate) Condensed Statements of Cash Flows | | | | | | | | | | | | | | For the Years Ended December 31, | (In millions) | 2019 | | 2018 | | 2017 | Net cash flows provided by operating activities | $ | 1,948 |
| | $ | 2,576 |
| | $ | 1,914 |
| Cash flows from investing activities | | | | | | Changes in Exelon intercompany money pool | 95 |
| | 1 |
| | (129 | ) | Investment in affiliates | (1,071 | ) | | (1,231 | ) | | (1,710 | ) | Other investing activities | — |
| | — |
| | (5 | ) | Net cash flows used in investing activities | (976 | ) |
| (1,230 | ) |
| (1,844 | ) | Cash flows from financing activities | | | | | | Changes in short-term borrowings | 136 |
| | — |
| | — |
| Proceeds from short-term borrowings with maturities greater than 90 days | — |
| | — |
| | 500 |
| Retirement of long-term debt | — |
| | — |
| | (569 | ) | Common stock issued from treasury stock | — |
| | — |
| | 1,150 |
| Dividends paid on common stock | (1,408 | ) | | (1,332 | ) | | (1,236 | ) | Proceeds from employee stock plans | 112 |
| | 105 |
| | 150 |
| Other financing activities | — |
| | (4 | ) | | (9 | ) | Net cash flows used in financing activities | (1,160 | ) | | (1,231 | ) | | (14 | ) | (Decrease) Increase in cash, cash equivalents and restricted cash | (188 | ) | | 115 |
| | 56 |
| Cash, cash equivalents and restricted cash at beginning of period | 189 |
| | 74 |
| | 18 |
| Cash, cash equivalents and restricted cash at end of period | $ | 1 |
| | $ | 189 |
| | $ | 74 |
|
| | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | (In millions) | 2021 | | 2020 | | 2019 | Net cash flows provided by operating activities | $ | 3,629 | | | $ | 3,018 | | | $ | 1,948 | | Cash flows from investing activities | | | | | | Changes in Exelon intercompany money pool | 381 | | | (477) | | | 95 | | Notes receivable from affiliates | — | | | 550 | | | — | | | | | | | | Investment in affiliates | (2,231) | | | (1,969) | | | (1,071) | | | | | | | | Other investing activities | 1 | | | — | | | — | | Net cash flows used in investing activities | (1,849) | | | (1,896) | | | (976) | | Cash flows from financing activities | | | | | | | | | | | | Changes in short-term borrowings | — | | | (136) | | | 136 | | Proceeds from short-term borrowings with maturities greater than 90 days | 500 | | | — | | | — | | Repayments on short-term borrowings with maturities greater than 90 days | (350) | | | — | | | — | | Issuance of long-term debt | — | | | 2,000 | | | — | | | | | | | | Retirement of long-term debt | (300) | | | (1,450) | | | — | | | | | | | | | | | | | | Dividends paid on common stock | (1,497) | | | (1,492) | | | (1,408) | | Proceeds from employee stock plans | 80 | | | 45 | | | 112 | | Other financing activities | 19 | | | (27) | | | — | | Net cash flows used in financing activities | (1,548) | | | (1,060) | | | (1,160) | | Increase (Decrease) in cash, restricted cash, and cash equivalents | 232 | | | 62 | | | (188) | | Cash, restricted cash, and cash equivalents at beginning of period | 63 | | | 1 | | | 189 | | Cash, restricted cash, and cash equivalents at end of period | $ | 295 | | | $ | 63 | | | $ | 1 | |
See the Notes to Financial Statements
378345
Exelon Corporation and Subsidiary Companies Schedule I – Condensed Financial Information of Parent (Exelon Corporate) Condensed Balance Sheets | | | | | | | | | | | | | December 31, | (In millions) | 2021 | | 2020 | ASSETS | | | | Current assets | | | | Cash and cash equivalents | $ | 295 | | | $ | 63 | | | | | | | | | | Accounts receivable, net | | | | Other accounts receivable | 318 | | | 354 | | Accounts receivable from affiliates | 35 | | | 11 | | Notes receivable from affiliates | 217 | | | 598 | | Regulatory assets | 266 | | | 315 | | Other | 6 | | | 4 | | Total current assets | 1,137 | | | 1,345 | | Property, plant, and equipment, net | 45 | | | 46 | | Deferred debits and other assets | | | | Regulatory assets | 3,164 | | | 3,816 | | Investments in affiliates | 44,495 | | | 43,149 | | Deferred income taxes | 1,513 | | | 1,625 | | | | | | Notes receivable from affiliates | 319 | | | 324 | | Other | 42 | | | 312 | | Total deferred debits and other assets | 49,533 | | | 49,226 | | Total assets | $ | 50,715 | | | $ | 50,617 | |
| | | | | | | | | | December 31, | (In millions) | 2019 | | 2018 | ASSETS | | | | Current assets | | | | Cash and cash equivalents | $ | 1 |
| | $ | 189 |
| Accounts receivable, net | | | | Other accounts receivable | 168 |
| | 48 |
| Accounts receivable from affiliates | 41 |
| | 44 |
| Mark-to-market derivative assets
| 3 |
| | — |
| Notes receivable from affiliates | 679 |
| | 216 |
| Regulatory assets | 253 |
| | 182 |
| Other | 4 |
| | 4 |
| Total current assets | 1,149 |
| | 683 |
| Property, plant and equipment, net | 47 |
| | 48 |
| Deferred debits and other assets | | | | Regulatory assets | 3,772 |
| | 3,742 |
| Investments in affiliates | 42,245 |
| | 40,425 |
| Deferred income taxes | 1,524 |
| | 1,455 |
| Notes receivable from affiliates | 329 |
| | 898 |
| Other | 308 |
| | 235 |
| Total deferred debits and other assets | 48,178 |
| | 46,755 |
| Total assets | $ | 49,374 |
| | $ | 47,486 |
|
See the Notes to Financial Statements
379346
Exelon Corporation and Subsidiary Companies Schedule I – Condensed Financial Information of Parent (Exelon Corporate) Condensed Balance Sheets | | | | | | | | | | | | | December 31, | (In millions) | 2021 | | 2020 | LIABILITIES AND SHAREHOLDERS’ EQUITY | | | | Current liabilities | | | | Short-term borrowings | $ | 650 | | | $ | 500 | | Long-term debt due within one year | 1,150 | | | 300 | | Accounts payable | — | | | 1 | | | | | | Accrued expenses | 79 | | | 76 | | | | | | Payables to affiliates | 360 | | | 457 | | Regulatory liabilities | 3 | | | 4 | | Pension obligations | 75 | | | 92 | | Other | 7 | | | 4 | | Total current liabilities | 2,324 | | | 1,434 | | Long-term debt | 6,265 | | | 7,418 | | | | | | Deferred credits and other liabilities | | | | Regulatory liabilities | 63 | | | 32 | | Pension obligations | 7,038 | | | 8,351 | | Non-pension postretirement benefit obligations | 116 | | | 387 | | | | | | Deferred income taxes | 404 | | | 348 | | Other | 112 | | | 62 | | Total deferred credits and other liabilities | 7,733 | | | 9,180 | | Total liabilities | 16,322 | | | 18,032 | | Commitments and contingencies | 0 | | 0 | Shareholders’ equity | | | | Common stock (No par value, 2,000 shares authorized, 979 shares and 976 shares outstanding as of December 31, 2021 and 2020, respectively) | 20,324 | | | 19,373 | | Treasury stock, at cost (2 shares as of December 31, 2021 and 2020) | (123) | | | (123) | | Retained earnings | 16,942 | | | 16,735 | | Accumulated other comprehensive loss, net | (2,750) | | | (3,400) | | Total shareholders’ equity | 34,393 | | | 32,585 | | | | | | Total liabilities and shareholders’ equity | $ | 50,715 | | | $ | 50,617 | |
| | | | | | | | | | December 31, | (In millions) | 2019 | | 2018 | LIABILITIES AND SHAREHOLDERS’ EQUITY | | | | Current liabilities | | | | Short-term borrowings | $ | 636 |
| | $ | 500 |
| Long-term debt due within one year | 1,458 |
| | — |
| Accounts payable | 1 |
| | 1 |
| Accrued expenses | 131 |
| | 184 |
| Payables to affiliates | 363 |
| | 360 |
| Regulatory liabilities | 13 |
| | 15 |
| Pension obligations | 77 |
| | 63 |
| Other | 10 |
| | 14 |
| Total current liabilities | 2,689 |
| | 1,137 |
| Long-term debt | 5,717 |
| | 7,147 |
| Deferred credits and other liabilities | | | | Regulatory liabilities | 31 |
| | 32 |
| Pension obligations | 7,960 |
| | 7,795 |
| Non-pension postretirement benefit obligations | 403 |
| | 199 |
| Deferred income taxes | 263 |
| | 233 |
| Other | 87 |
| | 202 |
| Total deferred credits and other liabilities | 8,744 |
| | 8,461 |
| Total liabilities | 17,150 |
| | 16,745 |
| Commitments and contingencies |
| |
| Shareholders’ equity | | | | Common stock (No par value, 2,000 shares authorized, 973 shares and 968 shares outstanding at December 31, 2019 and 2018, respectively) | 19,274 |
| | 19,116 |
| Treasury stock, at cost (2 shares at December 31, 2019 and 2018) | (123 | ) | | (123 | ) | Retained earnings | 16,267 |
| | 14,743 |
| Accumulated other comprehensive loss, net | (3,194 | ) | | (2,995 | ) | Total shareholders’ equity | 32,224 |
| | 30,741 |
| Total liabilities and shareholders’ equity | $ | 49,374 |
| | $ | 47,486 |
|
See the Notes to Financial Statements
380347
Exelon Corporation and Subsidiary Companies Schedule I – Condensed Financial Information of Parent (Exelon Corporate) Notes to Financial Statements
1. Basis of Presentation Exelon Corporate is a holding company that conducts substantially all of its business operations through its subsidiaries. These condensed financial statements and related footnotes have been prepared in accordance with Rule 12-04, Schedule I of Regulation S-X. These statements should be read in conjunction with the consolidated financial statements and notes thereto of Exelon Corporation. As of December 31, 2021 and 2020, Exelon Corporate ownsowned 100% of all of its significant subsidiaries, either directly or indirectly, except for Commonwealth Edison Company (ComEd), of which Exelon Corporate owns more than 99%, and Baltimore Gas and Electric Company (BGE), of which Exelon owns 100%. As a February 1, 2022, as a result of the common stock but nonecompletion of BGE’s preferred stock.the separation, Exelon Corporate no longer owns any interest in Exelon Generation Company, LLC. See Note 26 — Separation of the Combined Notes to Consolidated Financial Statements for additional information. 2. Debt and Credit Agreements Short-Term Borrowings Exelon Corporate meets its short-term liquidity requirements primarily through the issuance of commercial paper. Exelon Corporate had $136 million of outstanding commercial paper borrowings at December 31, 2019 and no outstanding commercial paper borrowings atas of December 31, 2018.2021 and 2020. Short-Term Loan Agreements On March 23, 2017, Exelon Corporate entered into a $500 million term loan agreement which was renewed on March 22, 2018 with an expiration of March 21, 2019.for $500 million. The loan agreement was renewed on March 20, 201917, 2021 and will expire on March 19, 2020.16, 2022. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.95%0.65% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Exelon’sShort-term borrowings in Exelon's Consolidated Balance Sheet within Short-Term borrowings.Sheet. On March 24, 2021, Exelon Corporate entered into a 9-month term loan agreement for $200 million. 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. Exelon Corporate repaid the term loan on December 22, 2021. On March 31, 2021, Exelon Corporate entered into a 9-month and 364-day term loan agreement for $150 million each with variable interest rates of LIBOR plus 0.65% and expiration dates of December 31, 2021 and March 30, 2022, respectively. The 364-day loan agreement is reflected in Short-term borrowings in Exelon's Consolidated Balance Sheet. Exelon Corporate repaid the 9-month term loan on December 29, 2021. In connection with the separation, on January 24, 2022, Exelon Corporate entered into a 364-day term loan agreement for $1.15 billion. The loan 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% and all indebtedness thereunder is unsecured. Revolving Credit Agreements On May 26, 2016, Exelon Corporate amended its syndicated revolving credit facility with aggregate bank commitments of $600 million through May 26, 2021. On May 26, 2018, Exelon Corporate had its maturity date extended to May 26, 2023. As of December 31, 2019,2021, Exelon Corporation had a $600 million aggregate bank commitment under its existing syndicated revolving facility in which $594 million was available capacity under those commitmentsto support additional commercial paper as of $458 million.December 31, 2021. See Note 16—17—Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information regarding Exelon Corporation’s credit agreement.
On February 1, 2022, Exelon Corporate entered into a new 5-year revolving credit facility with an aggregate bank commitment of $900 million at a variable interest rate of SOFR plus 1.275% which replaced its existing $600 million syndicated revolving credit facility.
Exelon Corporation and Subsidiary Companies Schedule I – Condensed Financial Information of Parent (Exelon Corporate) Notes to Financial Statements Long-Term Debt The following tables present the outstanding long-term debt for Exelon Corporate as of December 31, 20192021 and December 31, 2018:2020: | | | | | | | | | | | | | | | | | Maturity Date | | December 31, | | | | | | Maturity Date | | December 31, | | Rates | | 2021 | | 2020 | Long-term debt(a) | | Long-term debt(a) | | | | | | | | Junior subordinated notes | | Junior subordinated notes | | 3.50 | % | | 2022 | | $ | 1,150 | | | $ | 1,150 | | | Rates | | Maturity Date | | 2019 | | 2018 | | Long-term debt | | | | | | | | | Junior subordinated notes | | | 3.50 | % | | 2022 | | $ | 1,150 |
| | $ | 1,150 |
| | Senior unsecured notes(a)(b) | 2.45 | % | - | 7.60 | % | | 2020 - 2046 | | 5,889 |
| | 5,889 |
| 3.40 | % | - | 7.60 | % | | 2025 - 2050 | | 6,139 | | | 6,439 | | Total long-term debt | | | | | 7,039 |
| | 7,039 |
| Total long-term debt | | 7,289 | | | 7,589 | | Unamortized debt discount and premium, net | | | | | (7 | ) | | (7 | ) | Unamortized debt discount and premium, net | | (10) | | | (10) | | Unamortized debt issuance costs | | | | | (39 | ) | | (47 | ) | Unamortized debt issuance costs | | (39) | | | (47) | | Fair value adjustment | | | | | 182 |
| | 162 |
| Fair value adjustment | | 175 | | | 186 | | Long-term debt due within one year | | | | | (1,458 | ) | | — |
| Long-term debt due within one year | | (1,150) | | | (300) | | Long-term debt | | | | | $ | 5,717 |
|
| $ | 7,147 |
| Long-term debt | | $ | 6,265 | | | $ | 7,418 | |
__________ | | (a) | Senior unsecured notes include mirror debt that is held on both Generation and Exelon Corporation's balance sheets. |
(a)In connection with the separation, Exelon Corporate entered into three 18-month term loan agreements. On January 21, 2022, two of the loan agreements were issued for $300 million each with an expiration date of July 21, 2023. On January 24, 2022, the third loan agreement was issued for $250 million with an expiration date of July 24, 2023. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to SOFR plus 0.65%. (b)Senior unsecured notes include mirror debt that is held on Exelon Corporation's balance sheet. In connection with the separation, on January 31, 2022, Exelon Corporate received cash from Generation of $258 million to settle the intercompany loan. See Note 17 — Debt and Credit Agreements for additional information on the merger debt. The debt maturities for Exelon Corporate for the periods 2020, 2021, 2022, 2023, 2024, 2025, 2026, and thereafter are as follows: | | | | | | 2022 | $ | 1,150 | | 2023 | — | | 2024 | — | | 2025 | 807 | | 2026 | 750 | | Thereafter | 4,582 | | Total long-term debt | $ | 7,289 | |
3. Commitments and Contingencies See Note 19—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for Exelon Corporate’s commitments and contingencies related to environmental matters and fund transfer restrictions.
Exelon Corporation and Subsidiary Companies Schedule I – Condensed Financial Information of Parent (Exelon Corporate) Notes to Financial Statements
| | | | | 2020 | $ | 1,458 |
| 2021 | 300 |
| 2022 | 1,150 |
| 2023 | — |
| 2024 | — |
| Remaining years | 4,131 |
| Total long-term debt | $ | 7,039 |
|
3. Commitments and Contingencies
See Note 18—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for Exelon Corporate’s commitments and contingencies related to environmental matters and fund transfer restrictions.
4. Related Party Transactions The financial statements of Exelon Corporate include related party transactions as presented in the tables below: | | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | (In millions) | 2021 | | 2020 | | 2019 | Operating and maintenance from affiliates: | | | | | | BSC(a) | $ | 38 | | | $ | 10 | | | $ | 9 | | | | | | | | Total operating and maintenance from affiliates: | $ | 38 | | | $ | 10 | | | $ | 9 | | Interest income from affiliates, net: | | | | | | Generation | $ | 16 | | | $ | 29 | | | $ | 36 | | BSC | — | | | 1 | | | 3 | | | | | | | | Total interest income from affiliates, net: | $ | 16 | | | $ | 30 | | | $ | 39 | | Equity in earnings (losses) of investments: | | | | | | EEDC(b) | $ | 2,215 | | | $ | 1,729 | | | $ | 2,054 | | Generation | (206) | | | 589 | | | 1,125 | | UII | — | | | — | | | 97 | | PCI | (1) | | | — | | | 1 | | | | | | | | Exelon Enterprises | — | | | — | | | (16) | | Exelon INQB8R | (13) | | | (6) | | | (8) | | Exelon Transmission Company | — | | | — | | | (2) | | Other | 1 | | | 1 | | | 3 | | Total equity in earnings of investments: | $ | 1,996 | | | $ | 2,313 | | | $ | 3,254 | | | | | | | | Cash contributions received from affiliates | $ | 3,674 | | | $ | 3,372 | | | $ | 2,514 | |
| | | | | | | | | | | | | | For the Years Ended December 31, | (In millions) | 2019 | | 2018 | | 2017 | Operating and maintenance from affiliates: | | | | | | BSC(a) | $ | 9 |
| | $ | 11 |
| | $ | 23 |
| Other | — |
| | (2 | ) | | 2 |
| Total operating and maintenance from affiliates: | $ | 9 |
| | $ | 9 |
| | $ | 25 |
| Interest income from affiliates, net: | | | | | | Generation | $ | 36 |
| | $ | 36 |
| | $ | 37 |
| BSC | 3 |
| | 4 |
| | 3 |
| Exelon Energy Delivery Company, LLC(b) | — |
| | 2 |
| | — |
| Total interest income from affiliates, net: | $ | 39 |
| | $ | 42 |
| | $ | 40 |
| Equity in earnings (losses) of investments: | | | | | | Exelon Energy Delivery Company, LLC(b) | $ | 2,054 |
| | $ | 1,830 |
| | $ | 1,663 |
| Generation | 1,125 |
| | 369 |
| | 2,710 |
| UII, LLC | 97 |
| | — |
| | 41 |
| PCI | 1 |
| | (17 | ) | | 1 |
| BSC | — |
| | — |
| | 1 |
| Exelon Enterprises | (16 | ) | | — |
| | 1 |
| Exelon INQB8R | (8 | ) | | — |
| | — |
| Exelon Transmission Company, LLC | (2 | ) | | 1 |
| | (10 | ) | Other | 3 |
| | — |
| | — |
| Total equity in earnings of investments: | $ | 3,254 |
| | $ | 2,183 |
| | $ | 4,407 |
| | | | | | | Cash contributions received from affiliates | $ | 2,514 |
| | $ | 2,302 |
| | $ | 1,879 |
|
Exelon Corporation and Subsidiary Companies Schedule I – Condensed Financial Information of Parent (Exelon Corporate) Notes to Financial Statements
| | | December 31, | | As of December 31, | (in millions) | 2019 | | 2018 | (in millions) | 2021 | | 2020 | Accounts receivable from affiliates (current): | | | | Accounts receivable from affiliates (current): | | | | BSC(a) | $ | 11 |
| | $ | 13 |
| BSC(a) | $ | 4 | | | $ | — | | Generation | 13 |
| | 17 |
| Generation | 13 | | | 3 | | ComEd | 2 |
| | 4 |
| ComEd | 5 | | | — | | PECO | 2 |
| | 2 |
| PECO | 4 | | | 1 | | BGE | 1 |
| | 2 |
| BGE | 2 | | | — | | PHISCO | 7 |
| | 6 |
| PHISCO | 6 | | | 6 | | Exelon VTI, LLC | 5 |
| | — |
| | Exelon Enterprises | | Exelon Enterprises | 1 | | | 1 | | | Total accounts receivable from affiliates (current): | $ | 41 |
| | $ | 44 |
| Total accounts receivable from affiliates (current): | $ | 35 | | | $ | 11 | | Notes receivable from affiliates (current): | | | | Notes receivable from affiliates (current): | | | | BSC(a) | $ | 109 |
| | $ | 116 |
| BSC(a) | $ | 210 | | | $ | 252 | | Generation(c) | 558 |
| | 100 |
| Generation(c) | — | | | 285 | | PECO | | PECO | — | | | 40 | | PHI | 12 |
| | — |
| PHI | 7 | | | 21 | | Total notes receivable from affiliates (current): | $ | 679 |
| | $ | 216 |
| Total notes receivable from affiliates (current): | $ | 217 | | | $ | 598 | | Investments in affiliates: | | | | Investments in affiliates: | | | | BSC(a) | $ | 197 |
| | $ | 197 |
| BSC(a) | $ | 195 | | | $ | 196 | | Exelon Energy Delivery Company, LLC(b) | 28,147 |
| | 26,679 |
| | EEDC(b) | | EEDC(b) | 32,621 | | | 30,103 | | Generation | 13,484 |
| | 13,204 |
| Generation | 11,219 | | | 12,400 | | PCI | 62 |
| | 61 |
| PCI | 62 | | | 62 | | UII, LLC | 365 |
| | 268 |
| | Exelon Transmission Company, LLC | — |
| | 1 |
| | UII | | UII | 365 | | | 365 | | Voluntary Employee Beneficiary Association trust | (4 | ) | | (1 | ) | Voluntary Employee Beneficiary Association trust | 3 | | | — | | Exelon Enterprises | 6 |
| | 22 |
| Exelon Enterprises | 3 | | | 3 | | Exelon INQB8R, LLC | (8 | ) | | — |
| Exelon INQB8R, LLC | 29 | | | 23 | | Other | (4 | ) | | (6 | ) | Other | (2) | | | (3) | | Total investments in affiliates: | $ | 42,245 |
| | $ | 40,425 |
| Total investments in affiliates: | $ | 44,495 | | | $ | 43,149 | | Notes receivable from affiliates (non-current): | | | | Notes receivable from affiliates (non-current): | | | | Generation(c) | $ | 329 |
| | $ | 898 |
| Generation(c) | $ | 319 | | | $ | 324 | | | Accounts payable to affiliates (current): | | | | Accounts payable to affiliates (current): | | UII, LLC | $ | 360 |
| | $ | 360 |
| | Exelon Enterprises | 3 |
| | — |
| | | UII | | UII | $ | 360 | | | $ | 360 | | BSC | | BSC | — | | | 91 | | EEDC(b) | | EEDC(b) | — | | | 4 | | Generation(c) | | Generation(c) | — | | | 2 | | | Total accounts payable to affiliates (current): | $ | 363 |
| | $ | 360 |
| Total accounts payable to affiliates (current): | $ | 360 | | | $ | 457 | |
__________ | | (a) | Exelon Corporate receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. |
| | (b) | Exelon Energy Delivery Company, LLC consists of ComEd, PECO, BGE, PHI, Pepco, DPL and ACE. |
| | (c) | 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, which are eliminated in consolidation in Exelon’s Consolidated Balance Sheets. |
(a)Exelon Corporate receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology, and supply management services. All services are provided at cost, including applicable overhead. (b)EEDC consists of ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE. (c)In connection with the debt obligations assumed by Exelon as part of the Constellation merger, Exelon and subsidiaries of Generation (former Constellation subsidiaries) entered into intercompany loan agreements that mirror the terms and amounts of the third-party debt obligations of Exelon, resulting in intercompany notes receivable at Exelon Corporate from Generation. In connection with the separation, on January 31, 2022, Exelon Corporate received cash from Generation of $258 million to settle the intercompany loan. See Schedule 1 - 2. Debit and Credit agreements for additional information on the merger debt.
Exelon Corporation and Subsidiary Companies Schedule II – Valuation and Qualifying Accounts | | Column A | | Column B | | Column C | | Column D | | Column E | Column A | Column B | | Column C | | Column D | | Column E | | | | | Additions and adjustments | | | | | | | Additions and adjustments | | | | | Description | | Balance at Beginning of Period | | Charged to Costs and Expenses | | Charged to Other Accounts | | Deductions | | Balance at End of Period | Description | Balance at Beginning of Period | | Charged to Costs and Expenses | | Charged to Other Accounts | | Deductions | | Balance at End of Period | | | (in millions) | | For the year ended December 31, 2019 | | | | | | | | | | | | Allowance for uncollectible accounts(a) | | $ | 319 |
|
| $ | 119 |
|
| $ | 26 |
| (c) | $ | 170 |
| (e) | $ | 294 |
| | (In millions) | | (In millions) | | | | | | | | | | For the year ended December 31, 2021 | | For the year ended December 31, 2021 | | Allowance for credit losses(a) | | Allowance for credit losses(a) | $ | 437 | |
| $ | 141 | | (b) | $ | — | | | $ | 127 | | (c) | $ | 451 | | Deferred tax valuation allowance | | 35 |
|
| — |
|
| (9 | ) |
| — |
| | 26 |
| Deferred tax valuation allowance | 27 | |
| — | |
| 32 | | (d) | — | | | 59 | | Reserve for obsolete materials | | 156 |
|
| 6 |
|
| — |
| (d) | 7 |
| | 155 |
| Reserve for obsolete materials | 276 | |
| (1) | | | (2) | | | 10 | | | 263 | | For the year ended December 31, 2018 | |
|
|
|
|
|
|
| |
|
| | Allowance for uncollectible accounts(a) | | $ | 322 |
|
| $ | 159 |
|
| $ | 35 |
| (c) | $ | 197 |
| (e) | $ | 319 |
| | For the year ended December 31, 2020 | | For the year ended December 31, 2020 | |
| |
| |
| | Allowance for credit losses(a) | | Allowance for credit losses(a) | $ | 294 | |
| $ | 240 | | (b) | $ | (18) | | (e) | $ | 79 | | (c) | $ | 437 | | Deferred tax valuation allowance | | 37 |
|
| — |
|
| 5 |
|
| 7 |
| | 35 |
| Deferred tax valuation allowance | 26 | |
| — | |
| 1 | |
| — | | | 27 | | Reserve for obsolete materials | | 174 |
|
| 25 |
|
| (31 | ) |
| 12 |
| | 156 |
| Reserve for obsolete materials | 155 | |
| 128 | | (f) | (1) | | | 6 | | | 276 | | For the year ended December 31, 2017 | |
|
|
|
|
|
|
| |
|
| | Allowance for uncollectible accounts(a) | | $ | 334 |
|
| $ | 126 |
|
| $ | 27 |
| (b)(c) | $ | 165 |
| (e) | $ | 322 |
| | For the year ended December 31, 2019 | | For the year ended December 31, 2019 | |
| |
| |
| | Allowance for credit losses(a) | | Allowance for credit losses(a) | $ | 319 | |
| $ | 119 | | (b) | $ | 26 | | | $ | 170 | | (c) | $ | 294 | | Deferred tax valuation allowance | | 20 |
|
| — |
|
| 17 |
| (b) | — |
| | 37 |
| Deferred tax valuation allowance | 35 | |
| — | |
| (9) | | | — | | | 26 | | Reserve for obsolete materials | | 113 |
|
| 56 |
|
| 10 |
| (b) | 5 |
| | 174 |
| Reserve for obsolete materials | 156 | |
| 6 | |
| — | | | 7 | | | 155 | |
__________ | | (a) | Excludes the non-current allowance for uncollectible accounts related to PECO’s installment plan receivables of $9 million, $13 million, and $15 million for the years ended December 31, 2019, 2018 and 2017, respectively. |
| | (b) | Primarily represents the addition of PHI's results as of March 23, 2016, the date of the merger. |
| | (c) | Includes charges for late payments and non-service receivables. |
| | (d) | Primarily reflects the reclassification of assets as held for sale. |
| | (e) | Write-off of individual accounts receivable. |
(a)Excludes the non-current allowance for credit losses related to PECO’s installment plan receivables of $14 million, $5 million, and $9 million for the years ended December 31, 2021, 2020, and 2019, respectively.
(b)The amount charged to costs and expenses includes the amount that was reclassified to regulatory assets/liabilities under different mechanisms applicable to the different jurisdictions the Utility Registrants operate in. (c)Primarily reflects write-offs, net of recoveries of individual accounts receivable. (d)DPL recorded a full valuation allowance against Delaware net operating losses carryforwards due to a change in Delaware tax law. See Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information on the valuation allowance. (e)Includes a decrease related to the sale of customer accounts receivable at Generation in the second quarter of 2020. See Note 6—Accounts Receivable of the Combined Notes to Consolidated Financial Statements for additional information. (f)Primarily reflects expense resulting from materials and supplies inventory reserve adjustments as a result of the decision to early retire Byron, Dresden, and Mystic 8 and 9. See Note 7—Early Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information.
Commonwealth Edison Company LLC and Subsidiary Companies (2) Generation | | | | | | | | | (i) | | Financial Statements (Item 8): | | | | | | (i) | | Financial Statements (Item 8): | | | | | Report of Independent Registered Public Accounting Firm dated February 11, 202025, 2022 of PricewaterhouseCoopers LLP (PCAOB ID 238) | | | | | Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2019, 20182021, 2020, and 20172019 | | | | | Consolidated Statements of Cash Flows for the Years Ended December 31, 2019, 20182021, 2020, and 20172019 | | | | | Consolidated Balance Sheets at December 31, 20192021 and 20182020 | | | | | Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2019, 20182021, 2020, and 20172019 | | | | | Notes to Consolidated Financial Statements | | | (ii) | | Financial Statement Schedule: | | | | | Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2019, 20182021, 2020, and 2017
2019 | | | | | Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto |
Exelon GenerationCommonwealth Edison Company LLC and Subsidiary Companies
Schedule II – Valuation and Qualifying Accounts | | | | | | | | | | | | | | | | | | | | | | Column A | | Column B | | Column C | | Column D | | Column E | | | | | Additions and adjustments | | | | | Description | | Balance at Beginning of Period | | Charged to Costs and Expenses | | Charged to Other Accounts | | Deductions | | Balance at End of Period | | | (in millions) | For the year ended December 31, 2019 | | | | | | | | | | | Allowance for uncollectible accounts | | $ | 104 |
|
| $ | 27 |
|
| $ | (11 | ) |
| $ | 39 |
| | $ | 81 |
| Deferred tax valuation allowance | | 26 |
|
| — |
|
| (2 | ) | | — |
| | 24 |
| Reserve for obsolete materials | | 145 |
|
| — |
|
| — |
|
| 2 |
| | 143 |
| For the year ended December 31, 2018 | |
|
|
|
|
|
|
| |
|
| Allowance for uncollectible accounts | | $ | 114 |
|
| $ | 44 |
|
| $ | 4 |
| | $ | 58 |
| | $ | 104 |
| Deferred tax valuation allowance | | 23 |
|
| — |
|
| 3 |
| | — |
| | 26 |
| Reserve for obsolete materials | | 166 |
|
| 20 |
|
| (32 | ) | (a) | 9 |
| | 145 |
| For the year ended December 31, 2017 | |
|
|
|
|
|
|
| |
|
| Allowance for uncollectible accounts | | $ | 91 |
|
| $ | 34 |
|
| $ | — |
|
| $ | 11 |
| | $ | 114 |
| Deferred tax valuation allowance | | 9 |
| | — |
| | 14 |
| | — |
| | 23 |
| Reserve for obsolete materials | | 106 |
|
| 51 |
|
| 9 |
|
| — |
| | 166 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Column A | | Column B | | Column C | | Column D | | Column E | | | | | Additions and adjustments | | | | | Description | | Balance at Beginning of Period | | Charged to Costs and Expenses | | Charged to Other Accounts | | Deductions | | Balance at End of Period | (In millions) | | | | | | | | | | | For the year ended December 31, 2021 | | | | | | | | | | | Allowance for credit losses | | $ | 118 | | | $ | 18 | | (a) | $ | 1 | | | $ | 47 | | (b) | $ | 90 | | Reserve for obsolete materials | | 6 | | | 3 | | | — | |
| 2 | | | 7 | | For the year ended December 31, 2020 | | | | | | |
| | | | Allowance for credit losses | | $ | 79 | | | $ | 54 | | (a) | $ | 13 | | | $ | 28 | | (b) | $ | 118 | | Reserve for obsolete materials | | 7 | | | 3 | | | — | |
| 4 | | | 6 | | For the year ended December 31, 2019 | | | | | | |
| | | | Allowance for credit losses | | $ | 81 | | | $ | 35 | | (a) | $ | 20 | | | $ | 57 | | (b) | $ | 79 | | Reserve for obsolete materials | | 6 | | | 6 | |
| — | |
| 5 | | | 7 | |
__________ | | (a) | Primarily reflects the reclassification of assets as held for sale. |
(a)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 amount charged to costs and expenses includes the amount that was reclassified to regulatory assets/liabilities under such mechanism. See Note 3 – Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
(b)Write-offs, net of recoveries of individual accounts receivable.
PECO Energy Company and Subsidiary Companies (3) ComEd | | | | | | | | | (i) | | Financial Statements (Item 8): | | | | | | (i) | | Financial Statements (Item 8): | | | | | Report of Independent Registered Public Accounting Firm dated February 11, 202025, 2022 of PricewaterhouseCoopers LLP (PCAOB ID 238) | | | | | Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2019, 20182021, 2020, and 20172019 | | | | | Consolidated Statements of Cash Flows for the Years Ended December 31, 2019, 20182021, 2020, and 20172019 | | | | | Consolidated Balance Sheets at December 31, 20192021 and 20182020 | | | | | Consolidated Statements of Changes in Shareholders’Shareholder's Equity for the Years Ended December 31, 2019, 20182021, 2020, and 20172019 | | | | | Notes to Consolidated Financial Statements | | | (ii) | | Financial Statement Schedule: | | | | | Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2019, 20182021, 2020, and 2017
2019 | | | | | Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto |
Commonwealth EdisonPECO Energy Company and Subsidiary Companies
Schedule II – Valuation and Qualifying Accounts | | Column A | | Column B | | Column C | | Column D | | Column E | Column A | | Column B | | Column C | | Column D | | Column E | | | | | Additions and adjustments | | | | | | | | | Additions and adjustments | | | | | Description | | Balance at Beginning of Period | | Charged to Costs and Expenses | | Charged to Other Accounts | | Deductions | | Balance at End of Period | Description | | Balance at Beginning of Period | | Charged to Costs and Expenses | | Charged to Other Accounts | | Deductions | | Balance at End of Period | | | (in millions) | | (In millions) | | (In millions) | | | | | | | | | | | For the year ended December 31, 2021 | | For the year ended December 31, 2021 | | Allowance for credit losses(a) | | Allowance for credit losses(a) | | $ | 124 | |
| $ | 32 | | (b) | $ | (6) | | | $ | 38 | | (c) | $ | 112 | | Deferred tax valuation allowance | | Deferred tax valuation allowance | | 1 | | | — | | | 2 | | | — | | | $ | 3 | | Reserve for obsolete materials | | Reserve for obsolete materials | | 2 | |
| 1 | | | — | | | 1 | | | 2 | | For the year ended December 31, 2020 | | For the year ended December 31, 2020 | |
| | Allowance for credit losses(a) | | Allowance for credit losses(a) | | $ | 62 | |
| $ | 76 | | (b) | $ | 6 | | | $ | 20 | | (c) | $ | 124 | | Deferred tax valuation allowance | | Deferred tax valuation allowance | | — | | | — | | | 1 | | | — | | | 1 | | Reserve for obsolete materials | | Reserve for obsolete materials | | 2 | |
| 1 | | | — | | | 1 | | | 2 | | For the year ended December 31, 2019 | | | | | | | | | | | For the year ended December 31, 2019 | |
| | Allowance for uncollectible accounts | | $ | 81 |
|
| $ | 35 |
|
| $ | 20 |
| (a) | $ | 57 |
| (b) | $ | 79 |
| | Allowance for credit losses(a) | | Allowance for credit losses(a) | | $ | 61 | |
| $ | 31 | | | $ | 3 | | | $ | 33 | | (c) | $ | 62 | | Reserve for obsolete materials | | 6 |
|
| 6 |
|
| — |
|
| 5 |
| | 7 |
| Reserve for obsolete materials | | 2 | |
| — | |
| — | |
| — | | | 2 | | For the year ended December 31, 2018 | |
|
|
|
|
|
|
| |
|
| | Allowance for uncollectible accounts | | $ | 73 |
|
| $ | 44 |
|
| $ | 23 |
| (a) | $ | 59 |
| (b) | $ | 81 |
| | Reserve for obsolete materials | | 5 |
|
| 3 |
|
| 1 |
|
| 3 |
| | 6 |
| | For the year ended December 31, 2017 | |
|
|
|
|
|
|
| |
|
| | Allowance for uncollectible accounts | | $ | 70 |
|
| $ | 39 |
|
| $ | 20 |
| (a) | $ | 56 |
| (b) | $ | 73 |
| | Reserve for obsolete materials | | 4 |
|
| 3 |
|
| 1 |
|
| 3 |
| | 5 |
| |
__________ (a)Excludes the non-current allowance for credit losses related to PECO’s installment plan receivables of $14 million, $5 million, and $9 million for the years ended December 31, 2021, 2020, and 2019, respectively. (b)The amount charged to costs and expenses includes the amount that was reclassified to the COVID-19 regulatory asset. See Note 3 – Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. (c)Write-offs, net of recoveries of individual accounts receivable.
Baltimore Gas and Electric Company (4) BGE | | | | | | | | | (a)(i) | Primarily charges for late payments and non-service receivables. |
| Financial Statements (Item 8): | (b) | Write-off of individual accounts receivable. |
PECO Energy Company and Subsidiary Companies
(4) PECO
| | | | (i) | | Financial Statements (Item 8): | | | | | Report of Independent Registered Public Accounting Firm dated February 11, 202025, 2022 of PricewaterhouseCoopers LLP (PCAOB ID 238) | | | | | Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2019, 20182021, 2020 and 20172019 | | | | | Consolidated Statements of Cash Flows for the Years Ended December 31, 2019, 20182021, 2020 and 20172019 | | | | | Consolidated Balance Sheets at December 31, 20192021 and 20182020 | | | | | Consolidated Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2019, 20182021, 2020 and 20172019 | | | | | Notes to Consolidated Financial Statements | | | (ii) | | Financial Statement Schedule: | | | | | Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2019, 20182021, 2020, and 2017
2019 | | | | | Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto |
PECO EnergyBaltimore Gas and Electric Company and Subsidiary Companies
Schedule II – Valuation and Qualifying Accounts | | Column A | | Column B | | Column C | | Column D | | Column E | Column A | | Column B | | Column C | | Column D | | Column E | | | | | Additions and adjustments | | | | | | | | | Additions and adjustments | | | | | Description | | Balance at Beginning of Period | | Charged to Costs and Expenses | | Charged to Other Accounts | | Deductions | | Balance at End of Period | Description | | Balance at Beginning of Period | | Charged to Costs and Expenses | | Charged to Other Accounts | | Deductions | | Balance at End of Period | (In millions) | | (In millions) | | | | | | | | | | | For the year ended December 31, 2021 | | For the year ended December 31, 2021 | | Allowance for credit losses | | Allowance for credit losses | | $ | 44 | |
| $ | 16 | | (a) | $ | 3 | |
| $ | 16 | | (b) | $ | 47 | | | | (in millions) | | Reserve for obsolete materials | | Reserve for obsolete materials | | 1 | |
| — | | | — | |
| — | | | 1 | | For the year ended December 31, 2020 | | For the year ended December 31, 2020 | |
| |
| | Allowance for credit losses | | Allowance for credit losses | | $ | 17 | |
| $ | 31 | | (a) | $ | 6 | |
| $ | 10 | | (b) | $ | 44 | | Deferred tax valuation allowance | | Deferred tax valuation allowance | | 1 | |
| — | | | (1) | |
| — | | | — | | Reserve for obsolete materials | | Reserve for obsolete materials | | 1 | |
| — | | | — | |
| — | | | 1 | | For the year ended December 31, 2019 | | | | | | | | | | | For the year ended December 31, 2019 | |
| |
| | Allowance for uncollectible accounts(a) | | $ | 61 |
|
| $ | 31 |
|
| $ | 3 |
| (b) | $ | 33 |
| (c) | $ | 62 |
| | Allowance for credit losses | | Allowance for credit losses | | $ | 20 | |
| $ | 8 | | (a) | $ | 7 | |
| $ | 18 | | (b) | $ | 17 | | Deferred tax valuation allowance | | Deferred tax valuation allowance | | 1 | | | — | | | — | | | — | | | 1 | | Reserve for obsolete materials | | 2 |
|
| — |
|
| — |
|
| — |
| | 2 |
| Reserve for obsolete materials | | 1 | | | — | | | — | | | — | | | 1 | | For the year ended December 31, 2018 | |
|
|
|
|
|
|
| |
|
| | Allowance for uncollectible accounts(a) | | $ | 56 |
|
| $ | 33 |
|
| $ | 3 |
| (b) | $ | 31 |
| (c) | $ | 61 |
| | Reserve for obsolete materials | | 2 |
|
| — |
|
| — |
|
| — |
| | 2 |
| | For the year ended December 31, 2017 | |
|
|
|
|
|
|
| |
|
| | Allowance for uncollectible accounts(a) | | $ | 61 |
|
| $ | 26 |
|
| $ | 4 |
| (b) | $ | 35 |
| (c) | $ | 56 |
| | Reserve for obsolete materials | | 2 |
|
| — |
|
| — |
|
| — |
| | 2 |
| |
__________ | | (a) | Excludes the non-current allowance for uncollectible accounts related to PECO’s installment plan receivables of $9 million, $13 million, and $15 million for the years ended December 31, 2019, 2018, and 2017, respectively. |
| | (b) | Primarily charges for late payments. |
| | (c) | Write-off of individual accounts receivable. |
(a)The amount charged to costs and expenses includes the amount that was reclassified to regulatory assets/liabilities under different mechanisms as approved by the MDPSC.
(b)Write-offs, net of recoveries of individual accounts receivable.
Baltimore Gas and Electric Company
Pepco Holdings LLC and Subsidiary Companies (5) BGE | | | | | | | | | (i) | | Financial Statements (Item 8): | | | | | | (i) | | Financial Statements (Item 8): | | | | | Report of Independent Registered Public Accounting Firm dated February 11, 202025, 2022 of PricewaterhouseCoopers LLP (PCAOB ID 238) | | | | | Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2019, 20182021, 2020, and 20172019 | | | | | Consolidated Statements of Cash Flows for the Years Ended December 31, 2019, 20182021, 2020, and 20172019 | | | | | Consolidated Balance Sheets at December 31, 20192021 and 20182020 | | | | | Consolidated Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2019, 20182021, 2020, and 20172019 | | | | | Notes to Consolidated Financial Statements | | | | (ii) | | Financial Statement Schedule: | | | | | Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2019, 20182021, 2020, and 2017
2019 | | | | | | Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto |
Baltimore Gas and Electric CompanyPepco Holdings LLC and Subsidiary Companies
Schedule II – Valuation and Qualifying Accounts | | Column A | | Column B | | Column C | | Column D | | Column E | Column A | | Column B | | Column C | | Column D | | Column E | | | | | Additions and adjustments | | | | | | | | | Additions and adjustments | | | | | Description | | Balance at Beginning of Period | | Charged to Costs and Expenses | | Charged to Other Accounts | | Deductions | | Balance at End of Period | Description | | Balance at Beginning of Period | | Charged to Costs and Expenses | | Charged to Other Accounts | | Deductions | | Balance at End of Period | | | (in millions) | | For the year ended December 31, 2019 | | | | | | | | | | | | Allowance for uncollectible accounts | | $ | 20 |
|
| $ | 8 |
|
| $ | 7 |
|
| $ | 18 |
| (a) | $ | 17 |
| | (In millions) | | (In millions) | | | | | | | | | | | For the year ended December 31, 2021 | | For the year ended December 31, 2021 | | Allowance for credit losses | | Allowance for credit losses | | $ | 119 | | | $ | 41 | | (a) | $ | 2 | | | $ | 19 | | (b) | $ | 143 | | Deferred tax valuation allowance | | 1 |
|
| — |
|
| — |
|
| — |
| | 1 |
| Deferred tax valuation allowance | | — | | | — | | | 31 | | (c) | — | | | 31 | | Reserve for obsolete materials | | 1 |
|
| — |
|
| — |
|
| — |
| | 1 |
| Reserve for obsolete materials | | 2 | | | 1 | | | — | | | — | | | 3 | | For the year ended December 31, 2018 | |
|
|
|
|
|
|
| |
|
| | Allowance for uncollectible accounts | | $ | 24 |
|
| $ | 10 |
|
| $ | (2 | ) |
| $ | 12 |
| (a) | $ | 20 |
| | For the year ended December 31, 2020 | | For the year ended December 31, 2020 | | Allowance for credit losses | | Allowance for credit losses | | $ | 53 | | | $ | 69 | | (a) | $ | 13 | | | $ | 16 | | (b) | $ | 119 | | | Reserve for obsolete materials | | Reserve for obsolete materials | | 3 | | | — | | | — | | | 1 | | | 2 | | For the year ended December 31, 2019 | | For the year ended December 31, 2019 | | Allowance for credit losses | | Allowance for credit losses | | $ | 53 | | | $ | 17 | | (a) | $ | 7 | | | $ | 24 | | (d) | $ | 53 | | Deferred tax valuation allowance | | 1 |
|
| — |
|
| — |
|
| — |
| | 1 |
| Deferred tax valuation allowance | | 8 | | | — | | | (8) | | | — | | | — | | Reserve for obsolete materials | | — |
|
| 1 |
|
| — |
|
| — |
| | 1 |
| Reserve for obsolete materials | | 2 | | | 1 | | | — | | | — | | | 3 | | For the year ended December 31, 2017 | |
|
|
|
|
|
|
| |
|
| | Allowance for uncollectible accounts | | $ | 32 |
|
| $ | 8 |
|
| $ | (3 | ) |
| $ | 13 |
| (a) | $ | 24 |
| | Deferred tax valuation allowance | | 1 |
| | — |
| | — |
| | — |
| | 1 |
| | Reserve for obsolete materials | | — |
| | — |
| | — |
| | — |
| | — |
| |
__________ (a)The amount charged to costs and expenses includes the amount that was reclassified to regulatory assets/liabilities under different mechanisms applicable to the different jurisdictions Pepco, DPL, and ACE operate in. (b)Write-offs, net of recoveries of individual accounts receivable. (c)DPL recorded a full valuation allowance against Delaware net operating losses carryforwards due to a change in Delaware tax law. See Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information on the valuation allowance. (d)Write-offs of individual accounts receivable.
Potomac Electric Power Company (6) Pepco | | | | | | | | | (a)(i) | Write-off of individual accounts receivable. | Financial Statements (Item 8): |
Pepco Holdings LLC and Subsidiary Companies
(6) PHI
| | | | | (i) | | Financial Statements (Item 8): | | | | | Report of Independent Registered Public Accounting Firm dated February 11, 202025, 2022 of PricewaterhouseCoopers LLP (PCAOB ID 238) | | | | | Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2019, 20182021, 2020 and 20172019 | | | | | Consolidated Statements of Cash Flows for the Years Ended December 31, 2019, 20182021, 2020 and 20172019 | | | | | Consolidated Balance Sheets at December 31, 20192021 and 20182020 | | | | | Consolidated Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2019, 20182021, 2020 and 20172019 | | | | | Notes to Consolidated Financial Statements | | | | (ii) | | Financial Statement Schedule: | | | | | Schedule II – II—Valuation and Qualifying Accounts for the Years Ended December 31, 2019, 20182021, 2020, and 20172019 | | | | | | Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto |
Pepco Holdings LLC and Subsidiary CompaniesPotomac Electric Power Company
Schedule II – Valuation and Qualifying Accounts | | | | | | | | | | | | | | | | | | | | | | Column A | | Column B | | Column C | | Column D | | Column E | | | | | Additions and adjustments | | | | | Description | | Balance at Beginning of Period | | Charged to Costs and Expenses | | Charged to Other Accounts | | Deductions | | Balance at End of Period | | | (in millions) | For the Year Ended December 31, 2019 | | | | | | | | | | | Allowance for uncollectible accounts | | $ | 53 |
| | $ | 17 |
| | $ | 7 |
| (a) | $ | 24 |
| (b) | $ | 53 |
| Deferred tax valuation allowance | | 8 |
| | — |
| | (8 | ) | | — |
| | — |
| Reserve for obsolete materials | | 2 |
| | 1 |
| | — |
| | — |
| | 3 |
| For the Year Ended December 31, 2018 | | | | | | | | | | | Allowance for uncollectible accounts | | $ | 55 |
| | $ | 28 |
| | $ | 7 |
| (a) | $ | 37 |
| (b) | $ | 53 |
| Deferred tax valuation allowance | | 13 |
| | — |
| | 2 |
| | 7 |
| | 8 |
| Reserve for obsolete materials | | 2 |
| | — |
| | — |
| | — |
| | 2 |
| For the Year Ended December 31, 2017 | | | | | | | | | | | Allowance for uncollectible accounts | | $ | 80 |
| | $ | 19 |
| | $ | 6 |
| (a) | $ | 50 |
| (b) | $ | 55 |
| Deferred tax valuation allowance | | 10 |
| | — |
| | 3 |
| | — |
| | 13 |
| Reserve for obsolete materials | | 2 |
| | 2 |
| | — |
| | 2 |
| | 2 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Column A | | Column B | | Column C | | Column D | | Column E | | | | | Additions and adjustments | | | | | Description | | Balance at Beginning of Period | | Charged to Costs and Expenses | | Charged to Other Accounts | | Deductions | | Balance at End of Period | (In millions) | | | | | | | | | | | For the year ended December 31, 2021 | | | | | | | | | | | Allowance for credit losses | | $ | 45 | | | $ | 14 | | (a) | $ | 2 | | | $ | 8 | | (b) | $ | 53 | | | | | | | | | | | | | Reserve for obsolete materials | | 1 | | | — | | | — | | | — | | | 1 | | For the year ended December 31, 2020 | | | | | | | | | | | Allowance for credit losses | | $ | 20 | | | $ | 25 | | (a) | $ | 5 | | | $ | 5 | | (b) | $ | 45 | | | | | | | | | | | | | Reserve for obsolete materials | | 1 | | | — | | | — | | | — | | | 1 | | For the year ended December 31, 2019 | | | | | | | | | | | Allowance for credit losses | | $ | 21 | | | $ | 7 | | (a) | $ | 2 | | | $ | 10 | | (c) | $ | 20 | | | | | | | | | | | | | Reserve for obsolete materials | | 1 | | | — | | | — | | | — | | | 1 | |
__________ (a)The amount charged to costs and expenses includes the amount that was reclassified to regulatory assets/liabilities under different mechanisms as approved by the DCPSC and MDPSC. (b)Write-offs, net of recoveries of individual accounts receivable. (c)Write-off of individual accounts receivable.
Delmarva Power & Light Company (7) DPL | | | | | | | | | (a)(i) | Primarily charges for late payments. |
| Financial Statements (Item 8): | (b) | Write-off of individual accounts receivable. |
Potomac Electric Power Company
(7) Pepco
| | | | (i) | | Financial Statements (Item 8): | | | | | Report of Independent Registered Public Accounting Firm dated February 11, 202025, 2022 of PricewaterhouseCoopers LLP (PCAOB ID 238) | | | | | Statements of Operations and Comprehensive Income for the Years Ended December 31, 2019, 20182021, 2020 and 20172019 | | | | | Statements of Cash Flows for the Years Ended December 31, 2019, 20182021, 2020 and 20172019 | | | | | Balance Sheets at December 31, 20192021 and 20182020 | | | | | Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2019, 20182021, 2020 and 20172019 | | | | | Notes to Financial Statements | | | (ii) | | Financial Statement Schedule: | | | | | Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2019, 20182021, 2020, and 2017
2019 | | | | | Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto |
Potomac ElectricDelmarva Power & Light Company
Schedule II – Valuation and Qualifying Accounts | | | | | | | | | | | | | | | | | | | | | | Column A | | Column B | | Column C | | Column D | | Column E | | | | | Additions and adjustments | | | | | Description | | Balance at Beginning of Period | | Charged to Costs and Expenses | | Charged to Other Accounts | | Deductions | | Balance at End of Period | | | (in millions) | For the year ended December 31, 2019 | | | | | | | | | | | Allowance for uncollectible accounts | | $ | 21 |
| | $ | 7 |
| | $ | 2 |
| (a) | $ | 10 |
| (b) | $ | 20 |
| Reserve for obsolete materials | | 1 |
| | — |
| | — |
| | — |
| | 1 |
| For the year ended December 31, 2018 | | | | | | | | | | | Allowance for uncollectible accounts | | $ | 21 |
| | $ | 11 |
| | $ | 3 |
| (a) | $ | 14 |
| (b) | $ | 21 |
| Reserve for obsolete materials | | 1 |
| | — |
| | — |
| | — |
| | 1 |
| For the year ended December 31, 2017 | | | | | | | | | | | Allowance for uncollectible accounts | | $ | 29 |
| | $ | 8 |
| | $ | 2 |
| (a) | $ | 18 |
| (b) | $ | 21 |
| Reserve for obsolete materials | | 1 |
| | 1 |
| | — |
| | 1 |
| | 1 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Column A | | Column B | | Column C | | Column D | | Column E | | | | | Additions and adjustments | | | | | Description | | Balance at Beginning of Period | | Charged to Costs and Expenses | | Charged to Other Accounts | | Deductions | | Balance at End of Period | (In millions) | | | | | | | | | | | For the year ended December 31, 2021 | | | | | | | | | | | Allowance for credit losses | | $ | 31 | | | $ | 6 | | (a) | $ | (1) | | | $ | 10 | | (b) | $ | 26 | | Deferred tax valuation allowance | | — | | | — | | | 31 | | (c) | — | | | 31 | | | | | | | | | | | | | For the year ended December 31, 2020 | | | | | | | | | | | Allowance for credit losses | | $ | 15 | | | $ | 16 | | (a) | $ | 4 | | | $ | 4 | | (b) | $ | 31 | | | | | | | | | | | | | | | | | | | | | | | | For the year ended December 31, 2019 | | | | | | | | | | | Allowance for credit losses | | $ | 13 | | | $ | 4 | | (a) | $ | 3 | | | $ | 5 | | (d) | $ | 15 | | | | | | | | | | | | | | | | | | | | | | | |
__________ (a)The amount charged to costs and expenses includes the amount that was reclassified to regulatory assets/liabilities under different mechanisms as approved by the DEPSC and MDPSC. (b)Write-offs, net of recoveries of individual accounts receivable. (c)DPL recorded a full valuation allowance against Delaware net operating losses carryforwards due to a change in Delaware tax law. See Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information on the valuation allowance. (d)Write-off of individual accounts receivable.
Atlantic City Electric Company and Subsidiary Company (8) ACE | | | | | | | | | (a)(i) | Primarily charges for late payments. |
| Financial Statements (Item 8): | (b) | Write-off of individual accounts receivable. |
Delmarva Power & Light Company
(8) DPL
| | | | (i) | | Financial Statements (Item 8): | | | | | Report of Independent Registered Public Accounting Firm dated February 11, 202025, 2022 of PricewaterhouseCoopers LLP (PCAOB ID 238) | | | | | Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2019, 20182021, 2020, and 20172019 | | | | | Consolidated Statements of Cash Flows for the Years Ended December 31, 2019, 20182021, 2020, and 20172019 | | | | | Consolidated Balance Sheets at December 31, 20192021 and 20182020 | | | | | Consolidated Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2019, 20182021, 2020, and 20172019 | | | | | Notes to Consolidated Financial Statements | | | (ii) | | Financial Statement Schedule: | | | | | Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2019, 20182021, 2020, and 2017
2019 | | | | | Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto |
Delmarva Power & Light Company
Schedule II – Valuation and Qualifying Accounts
| | | | | | | | | | | | | | | | | | | | | | Column A | | Column B | | Column C | | Column D | | Column E | | | | | Additions and adjustments | | | | | Description | | Balance at Beginning of Period | | Charged to Costs and Expenses | | Charged to Other Accounts | | Deductions | | Balance at End of Period | | | (in millions) | For the year ended December 31, 2019 | | | | | | | | | | | Allowance for uncollectible accounts | | $ | 13 |
| | $ | 4 |
| | $ | 3 |
| (a) | $ | 5 |
| (b) | $ | 15 |
| Reserve for obsolete materials | | — |
| | — |
| | — |
| | — |
| | — |
| For the year ended December 31, 2018 | | | | | | | | | | | Allowance for uncollectible accounts | | $ | 16 |
| | $ | 6 |
| | $ | 2 |
| (a) | $ | 11 |
| (b) | $ | 13 |
| Reserve for obsolete materials | | — |
| | — |
| | — |
| | — |
| | — |
| For the year ended December 31, 2017 | | | | | | | | | | | Allowance for uncollectible accounts | | $ | 24 |
| | $ | 3 |
| | $ | 2 |
| (a) | $ | 13 |
| (b) | $ | 16 |
| Reserve for obsolete materials | | — |
| | 1 |
| | — |
| | 1 |
| | — |
|
__________
| | (a) | Primarily charges for late payments. |
| | (b) | Write-off of individual accounts receivable. |
Atlantic City Electric Company and Subsidiary Company
(9) ACE
| | | | (i) | | Financial Statements (Item 8): | | | | | Report of Independent Registered Public Accounting Firm dated February 11, 2020 of PricewaterhouseCoopers LLP | | | | | Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2019, 2018 and 2017 | | | | | Consolidated Statements of Cash Flows for the Years Ended December 31, 2019, 2018 and 2017 | | | | | Consolidated Balance Sheets at December 31, 2019 and 2018 | | | | | Consolidated Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2019, 2018 and 2017 | | | | | Notes to Consolidated Financial Statements | | | (ii) | | Financial Statement Schedule: | | | | | Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2019, 2018 and 2017
| | | | | Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto |
Atlantic City Electric Company and Subsidiary Company Schedule II – Valuation and Qualifying Accounts | | Column A | | Column B | | Column C | | Column D | | Column E | Column A | | Column B | | Column C | | Column D | | Column E | | | | | Additions and adjustments | | | | | | | | | Additions and adjustments | | | | | Description | | Balance at Beginning of Period | | Charged to Costs and Expenses | | Charged to Other Accounts | | Deductions | | Balance at End of Period | Description | | Balance at Beginning of Period | | Charged to Costs and Expenses | | Charged to Other Accounts | | Deductions | | Balance at End of Period | (In millions) | | (In millions) | | | | | | | | | | | For the year ended December 31, 2021 | | For the year ended December 31, 2021 | | Allowance for credit losses | | Allowance for credit losses | | $ | 43 | | | $ | 21 | | (a) | $ | 1 | | | $ | 1 | | (b) | $ | 64 | | | | (in millions) | | Reserve for obsolete materials | | Reserve for obsolete materials | | — | | | 1 | | | — | | | — | | | 1 | | For the year ended December 31, 2020 | | For the year ended December 31, 2020 | | Allowance for credit losses | | Allowance for credit losses | | $ | 18 | | | $ | 28 | | (a) | $ | 4 | | | $ | 7 | | (b) | $ | 43 | | | Reserve for obsolete materials | | Reserve for obsolete materials | | 1 | | | — | | | — | | | 1 | | | — | | For the year ended December 31, 2019 | | | | | | | | | | | For the year ended December 31, 2019 | | Allowance for uncollectible accounts | | $ | 19 |
| | $ | 5 |
| | $ | 2 |
| (a) | $ | 8 |
| (b) | $ | 18 |
| | Allowance for credit losses | | Allowance for credit losses | | $ | 19 | | | $ | 5 | | (a) | $ | 2 | | | $ | 8 | | (c) | $ | 18 | | | Reserve for obsolete materials | | 1 |
| | — |
| | — |
| | — |
| | 1 |
| Reserve for obsolete materials | | 1 | | | — | | | — | | | — | | | 1 | | For the year ended December 31, 2018 | | | | | | | | | | | | Allowance for uncollectible accounts | | $ | 18 |
| | $ | 11 |
| | $ | 2 |
| (a) | $ | 12 |
| (b) | $ | 19 |
| | Reserve for obsolete materials | | 1 |
| | — |
| | — |
| | — |
| | 1 |
| | For the year ended December 31, 2017 | | | | | | | | | | | | Allowance for uncollectible accounts | | $ | 27 |
| | $ | 8 |
| | $ | 2 |
| (a) | $ | 19 |
| (b) | $ | 18 |
| | Reserve for obsolete materials | | 1 |
| | — |
| | — |
| | — |
| | 1 |
| |
__________ | | (a) | Primarily charges for late payments. |
| | (b) | Write-off of individual accounts receivable. |
(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 amount charged to costs and expenses includes the amount that was reclassified to regulatory assets/liabilities under such mechanism. See Note 3 – Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
(b)Write-offs, net of recoveries of individual accounts receivable. (c)Write-off of individual accounts receivable.
Exhibits required by Item 601 of Regulation S-K: 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. | | | | | | | | | | | | | | | | | | Exhibit No. | Description | | | | | | | | | | | | | Exhibit No. | Description | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Put Termination Agreement dated as of November 3, 2010, by and among EDF Inc. (formerly known as EDF Development, Inc.), E.D.F. International S.A., Constellation Nuclear, LLC, and Constellation Energy Nuclear Group, LLC. (Designated as Exhibit No. 2.1 to the Current Report on Form 8-K dated November 8, 2010, filed by Constellation Energy Group, Inc., File No. 1-12869). | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | Exhibit No. | Description | | | | | 4-1 | First and Refunding Mortgage dated May 1, 1923 between The Counties Gas and Electric Company (predecessor to PECO Energy Company) and Fidelity Trust Company, Trustee (U.S. Bank National Association, as current successor trustee), (Registration No. 2-2281, Exhibit B-1).(a) | | | | | | | 4-1-1 | Supplemental Indentures to PECO Energy Company’s First and Refunding Mortgage: |
| | | | | | | | Dated as of | | File Reference | | Exhibit No. | | December 1, 1941 | | 2-4863(a) | | B-1(h) | | | | | | April 15, 2004 | | | | | | | | | | September 15, 2006 | | | | | | | | | | March 1, 2007 | | | | | | | | | | September 1, 2012 | | | | | | | | | | September 15, 2013 | | | | | | | | | | September 1, 2014 | |
| | | | | | | | | | September 15, 2015 | |
| | | | | | | | | | September 1, 2016 | | | | | | | | | | | | September 1, 2017 | | | | | | | | February 1, 2018 | |
| | | | | | | | | | September 1, 2018 | | | | | | | | August 15, 2019 | | | | |
| | | | | | | Exhibit No. | DescriptionSeptember 15, 2015 | | | | | | | | | | | | September 1, 2017 | | | | | | | | February 1, 2018 | | | | | | | | | | | | September 1, 2018 | | | | | | | | August 15, 2019 | | | | | | | | | | | | June 1, 2020 | | | | | | | | | | | | February 15, 2021 | | | | | | | | | | | | September 1, 2021 | | | | |
| | | | | | | | | | | | | | | | | | Exhibit No. | Description | | | | | 4-3 | Mortgage of Commonwealth Edison Company to Illinois Merchants Trust Company, Trustee (BNY Mellon Trust Company of Illinois, as current successor Trustee), dated July 1, 1923, as supplemented and amended by Supplemental Indenture thereto dated August 1, 1944. (Registration No. 2-60201, Form S-7, Exhibit 2-1).(a) |
| | | | | | | | | | | | | | | | | | Exhibit No. | Description | 4-3-1 | Supplemental Indentures to Commonwealth Edison Company Mortgage. | | | | | | | Exhibit No. | Description | 4-3-1 | Supplemental Indentures to Commonwealth Edison Company Mortgage. | | | | | | | | Dated as of | | File Reference | | Exhibit No. | | January 13, 2003 | | | | | | | | | | February 22, 2006 | | | | | | | | | | August 1, 2006 | | | | | | | | | | September 15, 2006 | | | | | | | | | | March 1, 2007 | | | | | | | | | | August 30, 2007 | | | | | | | | | | December 20, 2007 | | | | | | | | | | March 10, 2008 | | | | | | | | | | | | July 12, 2010 | | | | | | | | | | August 22, 2011 | | | | | | | | | | September 17, 2012 | | | | | | | | | | August 1, 2013 | | | | | | | | | | January 2, 2014 | | | | | | | | | | | | October 28, 2014 | | | | | | | | | | | | February 18, 2015 | | | | | | | | | | | | November 4, 2015 | | | | | | | | | | | | June 15, 2016 | | | | | | | | | | | | August 9, 2017 | | | | |
| | | | | | | | Dated as ofOctober 28, 2014 | | File Reference | | | | | | | | | | February 18, 2015 | | | | | | | | | | | | November 4, 2015 | | | | | | | | | | | | June 15, 2016 | | | | | | | | | | | | August 9, 2017 | | | | | | | | | | | | February 6, 2018 | | | | | | | | | | | | July 26, 2018 | | | | | | | | | | | | February 7, 2019 | | | | | | | | | | | | October 29, 2019 | | | | | | | | | | | | February 10, 2020 | | | | | | | | | | | | February 16, 2021 | | | | | | | | | | | | August 2, 2021 | | | | |
| | | | | | Exhibit No. | Description | | Instrument of Resignation, Appointment and Acceptance dated as of February 20, 2002, under the provisions of the Mortgage of Commonwealth Edison Company dated July 1, 1923, and Indentures Supplemental thereto, regarding corporate trustee (File No. 1-1839, 2001001-01839, Form 10-K dated April 1, 2002, Exhibit 4-4-2)4.4.2). | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | PECO Energy Capital Trust IV Amended and Restated Declaration of Trust among PECO Energy Company, as Sponsor, U.S. Bank Trust National Association, as Delaware Trustee and Property Trustee, and J. Barry Mitchell, George R. Shicora and Charles S. Walls as Administrative Trustees dated as of June 24, 2003 (File No. 000-16844, JuneForm 10-Q dated July 30, 2003, Form 10-Q, Exhibit 4.3). | | | | | | | | | | |
| | | Exhibit No. | Description | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Indenture, dated as of September 30, 2013, among Continental Wind, LLC, the guarantors party thereto and Wilmington Trust, National Association, as trustee (File No. 333-85496, Form 8-K dated September 30, 2013, Exhibit No. 4.1). | | | 4-26 | Indenture dated July 1, 1985, between Baltimore Gas and Electric Company and The Bank of New York (Successor to Mercantile-Safe Deposit and Trust Company), Trustee. (Designated as Exhibit 4(a) to the Registration Statement on Form S-3, File No. 2-98443); as supplemented by Supplemental Indentures dated as of October 1, 1987 (Designated as Exhibit 4(a) to the Current Report on Form 8-K, dated November 13, 1987, File No. 1-1910) and as of January 26, 1993 (Designated as Exhibit 4(b) to the Current Report on Form 8-K, dated January 29, 1993, filed by Baltimore Gas and Electric Company, File No. 1-1910).(a)
| | | | | | | | | | |
| | | Exhibit No. | Description | | | | | | | | | | | | Officers’ Certificate, dated December 14, 2010, establishing the 5.15% Notes due December 1, 2020 of Constellation Energy Group, Inc., with the form of Notes attached thereto. (Designated as Exhibit No. 4 (b) to the Current Report on Form 8-K dated December 14, 2010, filed by Constellation Energy Group, Inc., File No. 1-12869). | | | | | | | | | | | | | | | | | | | | Purchase Contract and Pledge Agreement,April 3, 2017, between Exelon Corporation and The Bank of New York Mellon Trust Company, N.A., as Purchase Contract Agent, Collateral Agent, Custodial Agent and Securities Intermediary.trustee, to that certain Indenture (For Unsecured Subordinated Debt Securities), dated June 17, 2014 (File No. 001-16169, Form 8-K dated June 23, 2014,April 4, 2017, Exhibit 4.4)4.3). | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | Exhibit No. | Description | | | | | | | | | | | | | 4-39 | | | | | | | | 4-17 | Mortgage and Deed of Trust, dated July 1, 1936, of Potomac Electric Power Company to The Bank of New York Mellon as successor trustee, securing First Mortgage Bonds of Potomac Electric Power Company, and Supplemental Indenture dated July 1, 1936 (File No. 2-2232, Registration Statement dated June 19, 1936, Exhibit B-4).(a) | | | 4-39-14-17-1 | Supplemental Indentures to Potomac Electric Power Company Mortgage. |
| | | | | | | | | | | | | | | | | | | Dated as of | | File Reference | | Exhibit No. | | December 10, 1939 | | Form 8-K dated January 3, 1940(a) | | B | | | | | | | | Dated as of | | File Reference | | Exhibit No. | | | | | | | | December 10, 1939 | | Form 8-K, 1/3/40(a)
| | B | | | | | | | | March 16, 2004 | | | | | | | | | | | | May 24, 2005 | | | | | | | | | | | | November 13, 2007 | | | | | | | | | | | | March 24, 2008 | | | | | | | | | | | | December 3, 2008 | | | | | | | | | | | | March 28, 2012 | | | | | | | | | | | | March 11, 2013 | | | | | | | | | | | | November 14, 2013 | | | | | | | | | | | | March 11, 2014 | | | | | | | | | | | | March 9, 2015 | | | | | | | | | | | | May 15, 2017 | | | | | | | | | | | | June 1, 2018 | | | |
| | | | | | | | May 2, 2019 | | | |
|
| | | | | | | Exhibit No. | DescriptionMay 24, 2005 | | | | | 4-40 | | | | | | | November 13, 2007 | | | | | | | | | | | | March 24, 2008 | | | | | | | | | | | | December 3, 2008 | | | | | | | | | | | | March 28, 2012 | | | | | | | | | | | | March 11, 2013 | | | | | | | | | | | | November 14, 2013 | | | | | | | | | | | | March 11, 2014 | | | | | | | | | | | | March 9, 2015 | | | | | | | | | | | | May 15, 2017 | | | | | | | | | | | | June 1, 2018 | | | | | | | | | | | | 4-41May 2, 2019 | | | | | | | | | | | | 4-41-1February 12, 2020 | | | | | | | | | | | 4-42 | February 15, 2021 | | | | |
| | | | | | | | | | | | | | | | | | Exhibit No. | Description | 4-18 | Mortgage and Deed of Trust of Delaware Power & Light Company to The Bank of New York Mellon (ultimate successor to the New York Trust Company), as trustee, dated as of October 1, 1943, and copies of the First through Sixty-Eighth Supplemental Indentures thereto (File No. 33-1763, Registration Statement dated November 27, 1985, Exhibit 4-A)(a) | | | 4-42-14-18-1 | Supplemental Indentures to Delmarva Power & Light Company Mortgage. | | | | | | | | Dated as of | | File Reference | | Exhibit No. | | | | | | | | October 1, 1993 | | 33-53855, Registration Statement 1/30/95dated January 30, 1995(a) | | 4-L | | | | | | | | October 1, 1994 | | 33-53855, Registration Statement 1/30/95dated January 30, 1995(a) | | 4-N | | | | | | | | January 1, 1997 | | | | | | | | | | | | November 7, 2013 | | | | | | | | | | | | June 2, 2014 | | | | | | | | | | | | May 4, 2015 | | | | | | | | | | | | December 5, 2016 | | | | | | | | | | | | April 5, 2017June 1, 2018 | | | | | | | | | | | | May 2, 2019 | | | | | | | | | | | | March 18, 2020 | | | | | | April 3, 2018 | | | | | | | | | | | | June 1, 20182020 | | | | | | | | | | | | April 3, 2019 | | | | | | | | | | | | May 2, 2019 | | | | | | | | | | | | 4.2February 15, 2021 | | | | | | | | | | | | February 15, 2022 | | | | |
| | | | | | | | | | | | | | | | | | Exhibit No. | Description | | 4-43 | Indenture between Delmarva Power & Light Company and The Bank of New York Mellon Trust Company, N.A. (ultimate successor to Manufacturers Hanover Trust Company), as trustee, dated as of November 1, 1988 (File No. 33-46892, Registration Statement dated April 1, 1992, Exhibit 4-G)4-19(a)
| | | | | | | | 4-44 | Mortgage and Deed of Trust, dated January 15, 1937, between Atlantic City Electric Company and The Bank of New York Mellon (formerly Irving Trust Company), as trustee (File No. 2-66280, Registration Statement dated December 21, 1979, Exhibit 2(a)).(a) | | | | | | | | 4-44-14-19-1 | Supplemental Indentures to Atlantic City Electric Company Mortgage. | | | | | | | | | Dated as of | | File Reference | | Exhibit No. | | | | | | | | | | June 1, 1949 | | 2-66280, Registration Statement 12/21/79dated December 21, 1979(a) | | 2(b) | | | | | | | | | | March 1, 1991 | | Form 10-K 3/28/91dated March 28, 1991(a) | | 4(d)(1) | | | | | | | | | | April 1, 2004 | | | | | | | | | | | | | | March 8, 2006 | | | | | | | | | | | | | | March 29, 2011 | | | | | | | | | | | | | | August 18, 2014 | | | | | | | | | | | | | | December 1, 2015 | | | | | | | | | | | | | | October 9, 2018 | | | | | | | | | | | | | | May 2, 2019 | | | | | |
| | | Exhibit No. | Description | | | | | | | | | | | | | | | | | | March 8, 2006 | | | | | | | | | | | | Indenture,March 29, 2011 | | | | | | | | | | | | August 18, 2014 | | | | | | | | | | | | December 19, 2002 between Atlantic City Electric Transition Funding LLC and The Bank of New York Mellon, as trustee (File No. 333-59558,1, 2015 | | | | | | | | | | | | 4-48October 9, 2018 | | | | | | | | | | | | 4-49May 2, 2019 | | | | | | | | | | |
| | | June 1, 2020 | | | | | | | | | | | | February 15, 2021 | | | | | | | | | | | | November 1, 2021 | | | | | | | | | | | | February 15, 2022 | | | | |
| | | | | | Exhibit No. | Description | | | | | | | | | | | | | | | | | | | | | | | | | | Second Supplemental Indenture, dated April 3, 2017, between Exelon and The Bank of New York Mellon Trust Company, N.A., as trustee, to that certain Indenture (For Unsecured Subordinated Debt Securities), dated June 17, 2014 (File No. 001-16169, Form 8-K dated April 4, 2017, Exhibit 4.3) | | | | | | | | | | |
| | | Exhibit No. | Description | | | | | | | | | | | | | | | | | | | | Amendment No. 3 to Credit Agreement dated as of March 23, 2011 among Exelon Corporation, as Borrower, the various financial institutions named therein, as Lenders, and JPMorgan Chase Bank, N.A., as Administrative Agent (File No. 001-16169, Form 8-K dated August 10, 2013, Exhibit No. 99-1). | | | | | | | | Amendment No. 1 to Credit Agreement, dated as of December 21, 2011, to the Credit Agreement dated as of March 23, 2011, among Exelon Generation Company, LLC, the lenders party thereto and JPMorgan Chase Bank, N.A., as Administrative Agent (File No. 001-16169, Form 8-K dated March 14, 2012, Exhibit No. 4-6). | | | | | | | | | | | | | | | | | | | | |
| | | Exhibit No. | Description | | | | | | | | | | Second Amended and Restated Operating Agreement, dated as of November 6, 2009, by and among Constellation Energy Nuclear Group, LLC, Constellation Nuclear, LLC, CE Nuclear, LLC, EDF Development Inc., and for certain limited purposes, E.D.F. International S.A. and Constellation Energy Group, Inc. (Designated as Exhibit No. 10.1 to the Current Report on Form 8-K dated November 12, 2009, filed by Constellation Energy Group, Inc., File No. 1-12869). | | | | Amendment No. 1 to the Second Amended and Restated Operating Agreement of Constellation Energy Nuclear Group, LLC, by and among Constellation Nuclear, LLC, CE Nuclear, LLC, EDF Inc. (formerly known as EDF Development, Inc.), and E.D.F. International S.A. (Designated as Exhibit No. 10(s) to the Annual Report on Form 10-K for the year ended December 31, 2010, filed by Constellation Energy Group, Inc., File Nos. 1-12869 and 1-1910). | | | | Amendment No. 2 to the Second Amended and Restated Operating Agreement of Constellation Energy Nuclear Group, LLC, by and among Constellation Nuclear, LLC, CE Nuclear, LLC, EDF Inc. (formerly known as EDF Development, Inc.), and E.D.F. International S.A. (Designated as Exhibit No. 10(t) to the Annual Report on Form 10-K for the year ended December 31, 2010, filed by Constellation Energy Group, Inc., File Nos. 1-12869 and 1-1910). | | | | Amendment No. 3 to the Second Amended and Restated Operating Agreement of Constellation Energy Nuclear Group, LLC, by and among Constellation Nuclear, LLC, CE Nuclear, LLC, EDF Inc. (formerly known as EDF Development, Inc.), and E.D.F. International S.A. (Designated as Exhibit No. 10.1 to the Current Report on Form 8-K dated November 3, 2010, filed by Constellation Energy Group, Inc., File No. 1-12869). | | | | Termination Agreement dated as of November 3, 2010, by and among EDF Inc. (formerly known as EDF Development, Inc.), E.D.F. International S.A., and Constellation Energy Group, Inc. (Designated as Exhibit No. 10.2 to the Current Report on Form 8-K dated November 3, 2010, filed by Constellation Energy Group, Inc., File No. 1-12869). | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Exhibit No. | Description | | | | | | Purchase Agreement, dated as of April 20, 2010, by and among Pepco Holdings, Inc., Conectiv, LLC, Conectiv Energy Holding Company, LLC and New Development Holdings, LLC (File No. 001-31403, Form 8-K dated July 8, 2010, Exhibit 2.1) | | | | Purchase Agreement, dated March 9, 2015, among Potomac Electric Power Company and BNY Mellon Capital Markets, LLC, Morgan Stanley & Co. LLC, and RBS Securities Inc., as representatives of the several underwriters named therein (File No. 001-01072, Form 8-K dated March 10, 2015, Exhibit 1.1) | | | | Purchase Agreement, May 4, 2015, among Delmarva Power & Light Company and J.P. Morgan Securities LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated, and Scotia Capital (USA) Inc., as representatives of the several underwriters named therein (File No. 001-01405, Form 8-K dated May 5, 2015, Exhibit 1.1) | | | | | | | | $300,000,000 Term Loan Agreement by and among PHI, The Bank of Nova Scotia, as Administrative Agent, and the lenders party thereto, dated July 30, 2015 (File No. 001-31403, Form 8-K dated July 30, 2015, Exhibit 10) | | | | | | | | $500,000,000 Term Loan Agreement by and among PHI, The Bank of Nova Scotia, as Administrative Agent, and the lenders party thereto, dated January 13, 2016 (File No. 001-31403, Form 8-K dated January 14, 2016, Exhibit 10) | | Second Amended and Restated Credit Agreement, dated as of August 1, 2011, by and among Pepco Holdings, Inc., Potomac Electric Power Company, Delmarva Power & Light Company and Atlantic City Electric Company, the lenders party thereto, Wells Fargo Bank, National Association, as agent, issuer and swingline lender, Bank of America, N.A., as syndication agent and issuer, The Royal Bank of Scotland plc and Citicorp USA, Inc., as co-documentation agents, Wells Fargo Securities, LLC and Merrill Lynch, Pierce, Fenner and Smith Incorporated, as active joint lead arrangers and joint book runners, and Citigroup Global Markets Inc. and RBS Securities, Inc. as passive joint lead arrangers and joint book runners (File No. 001-31403, Form 10-Q dated August 3, 2011, Exhibit 10.1) | | | | First Amendment, dated as of August 2, 2012, to Second Amended and Restated Credit Agreement, dated as of August 1, 2011, by and among Pepco Holdings, Inc., Potomac Electric Power Company, Delmarva Power & Light Company and Atlantic City Electric Company, the various financial institutions party thereto, Wells Fargo Bank, National Association, as agent, issuer of letters of credit and swingline lender, Bank of America, N.A., as syndication agent and issuer of letters of credit, and The Royal Bank of Scotland plc and Citibank, N.A., as co-documentation agents (File No. 001-31403, Form 10-K dated March 1, 2013, Exhibit 10.25.1) | | | | Amendment and Consent to Second Amended and Restated Credit Agreement, dated as of May 20, 2014, by and among Pepco Holdings, Inc., Potomac Electric Power Company, Delmarva Power & Light Company and Atlantic City Electric Company, the various financial institutions from time to time party thereto, Bank of America, N.A. and Wells Fargo Bank, National Association (File No. 001-31403, Form 8-K dated May 20, 2014, Exhibit 10.1) | | | | Third Amendment to Second Amended and Restated Credit Agreement, dated as of May 1, 2015, by and among Pepco Holdings, Inc., Potomac Electric Power Company, Delmarva Power & Light Company and Atlantic City Electric Company, the various financial institutions from time to time party thereto, Bank of America, N.A. and Wells Fargo Bank, National Association (File No. 001-31403, Form 8-K dated May 1, 2015, Exhibit 10.1) | | | | Consent, dated as of October 29, 2015, by and among Pepco Holdings, Inc., Potomac Electric Power Company, Delmarva Power & Light Company and Atlantic City Electric Company, the various financial institutions from time to time party thereto, Bank of America, N.A. and Wells Fargo Bank, National Association (File No. 001-31403, Form 8-K dated October 29, 2015, Exhibit 10.1) |
| | | | | | Exhibit No. | Description | | | | | | | | | | | | | | | | | | | | Amendment No. 7 to Credit Agreement, dated as of March 23, 2011, among Exelon Corporation, as Borrower, the various financial institutions named therein, as Lenders, and JPMorgan Chase Bank, N.A., as Administrative Agent (File No. 001-16169, Form 8-K dated May 27, 2016, Exhibit 99.1) | | | | Amendment No. 7 to Credit Agreement, dated as of March 23, 2011, among Exelon Generation Company, LLC, as Borrower, the various financial institutions named therein, as Lenders, and JPMorgan Chase Bank, N.A., as Administrative Agent (File No. 333-85496, Form 8-K dated May 27, 2016, Exhibit 99.2) | | | | Amendment No. 4 to Credit Agreement, dated as of March 23, 2011, among Commonwealth Edison Company, as Borrower, the various financial institutions named therein, as Lenders, and JPMorgan Chase Bank, N.A., as Administrative Agent (File No. 333-85496, Form 8-K dated May 27, 2016, Exhibit 99.3) | | | | Amendment No. 6 to Credit Agreement, dated as of March 23, 2011, among PECO Energy Company, as Borrower, the various financial institutions named therein, as Lenders, and JPMorgan Chase Bank, N.A., as Administrative Agent (File No. 000-16844, Form 8-K dated May 27, 2016, Exhibit 99.4) | | | | Amendment No. 5 to Credit Agreement, dated as of March 23, 2011, among Baltimore Gas and Electric Company, as Borrower, the various financial institutions named therein, as Lenders, and JPMorgan Chase Bank, N.A., as Administrative Agent (File No. 001-01910, Form 8-K dated May 27, 2016, Exhibit 99.5) | | | | Fourth Amendment to Second Amended and Restated Credit Agreement, dated as of August 1, 2011, among Pepco Holdings LLC, Potomac Electric Power Company, Delmarva Power & Light Company and Atlantic City Electric Company, as Borrowers, the various financial institutions named therein, as Lenders, and Wells Fargo Bank, National Association, as Administrative Agent (File No. 001-31403, Form 8-K dated May 27, 2016, Exhibit 99.6) | | | | | | | | | | | | | | | | Credit Agreement, dated as of November 28, 2017, as thereafter amended and conformed among ExGen Renewables IV, LLC, ExGen Renewables IV Holding, LLC, Morgan Stanley Senior Funding, Inc. as administrative agent, Wilmington Trust, National Association, as depository bank and collateral agent, and the lenders and other agents party thereto. (Certain portions of this exhibit have been omitted by redacting a portion of text, as indicated by asterisks in the text. This exhibit has been filed separately with the U.S. Securities and Exchange Commission pursuant to a request for confidential treatment.) | | |
| | | | | | Exhibit No. | Description | | | | | | Subsidiaries | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Consent of Independent Registered Public Accountants | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Power of Attorney (Exelon Corporation) | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Exhibit No. | Description | | | | | | | | | | | | | | | | | | | | | | | | | | | | Power of Attorney (Exelon Corporation) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 24-11 | Reserved. | | | | | | | | | | | | | | | | | | | | Power of Attorney (Commonwealth Edison Company) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | Exhibit No. | Description | | | | | | | | | | | | | | | | Power of Attorney (PECO Energy Company) | | | | | | | | | | | 24-26 | Reserved. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Power of Attorney (Baltimore Gas and Electric Company) | | | | | | | | | | | | | | |
| | | Exhibit No. | Description | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Power of Attorney (Pepco Holdings LLC) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Power of Attorney (Potomac Electric Power Company) | | | | | | | | | | | | | | |
| | | | | | Exhibit No. | Description | | | | | | | | | | | | | | | | | | | | | | Power of Attorney (Delmarva Power & Light Company) | | | | | | | | | | | | | | Power of Attorney (Atlantic City Electric Company) | | | | | | |
| | | | | | Certifications Pursuant to Rule 13a-14(a) and 15d-14(a) of the Securities and Exchange Act of 1934 as to the Annual Report on Form 10-K for the year ended December 31, 20182021 filed by the following officers for the following registrants: | | | Exhibit No. | Description | | | | | | | | | | | | | | | | |
| | | Exhibit No. | Description | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Certifications Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code as to the Annual Report on Form 10-K for the year ended December 31, 20182021 filed by the following officers for the following registrants: | | | Exhibit No. | Description | | | | | | | | | | | | | | | | | | | | | | |
| | | 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. | | | 101.SCH | Inline XBRL Taxonomy Extension Schema Document. | | | 101.CAL | Inline XBRL Taxonomy Extension Calculation Linkbase Document. | | | 101.DEF | Inline XBRL Taxonomy Extension Definition Linkbase Document. | | | 101.LAB | Inline XBRL Taxonomy Extension Labels Linkbase Document. | | | 101.PRE | Inline XBRL Taxonomy Extension Presentation Linkbase Document. | | | 104 | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) |
__________ * Compensatory plan or arrangements in which directors or officers of the applicable registrant participate and which are not available to all employees. ** Filed herewith. (a)These filings are not available electronically on the SEC website as they were filed in paper previous to the electronic system that is currently in place.
| | | | | | (a) | These filings are not available electronically on the SEC website as they were filed in paper previous to the electronic system that is currently in place. |
| | | ITEM 16. | FORM 10-K SUMMARY |
All Registrants Registrants may voluntarily include a summary of information required by Form 10-K under this Item 16. The Registrants have elected not to include such summary information.
SIGNATURES Pursuant to the requirements of Section 13 or 15(d) 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, in the City of Chicago and State of Illinois on the 11th25th day of February, 2020.2022.
| | | | | | | | | | | | EXELON CORPORATION | | | | | By: | | /s/ CHRISTOPHER M. CRANE | | Name: | | Christopher M. Crane | | Title: | | President and Chief Executive Officer | |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities indicated on the 11th25th day of February, 2020.2022. | | | | | | | | | Signature | | Title | | | /s/ CHRISTOPHER M. CRANE | | President, Chief Executive Officer (Principal Executive Officer) and Director | Christopher M. Crane | | | | /s/ JOSEPH NIGRO | | Senior Executive Vice President and Chief Financial Officer (Principal Financial Officer) | Joseph Nigro | | | | /s/ FABIAN E. SOUZA | | Senior Vice President and Corporate Controller (Principal Accounting Officer) | Fabian E. Souza | |
This annual report has also been signed below by Thomas S. O'Neill,Gayle E. Littleton, Attorney-in-Fact, on behalf of the following Directors on the date indicated: | | | | | | Anthony K. Anderson
Ann C. Berzin
Laurie Brlas
Yves C. de Balmann
Nicholas DeBenedictis
Linda P. Jojo
Paul L. Joskow
| | Robert J. Lawless
Richard W. Mies
John M. Richardson
Mayo A. Shattuck III
Stephen D. Steinour
John F. Young
| | | | | |
| | | | | | By:Anthony K. Anderson | | /s/ THOMAS S. O'NEILL | | February 11, 2020Linda P. Jojo | Name:Ann C. Berzin | Paul Joskow | W. Paul Bowers | Thomas S. O'NeillMayo A. Shattuck III | Marjorie Rodgers Cheshire | John F. Young | Carlos Gutierrez | | | |
| | | | | | | | | | | | | | | By: | | /s/ GAYLE E. LITTLETON | | February 25, 2022 | Name: | | Gayle E. Littleton | | |
SIGNATURES Pursuant to the requirements of Section 13 or 15(d) 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, in the City of Chicago and State of Illinois on the 11th25th day of February, 2020.2022. | | | | | | | | | | | | EXELON GENERATIONCOMMONWEALTH EDISON COMPANY LLC | | | | | By: | | /s/ KENNETH W. CORNEWGIL C. QUINIONES | | Name: | | Kenneth W. CornewGil C. Quiniones | | Title: | | President and Chief Executive Officer | |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities indicated on the 11th25th day of February, 2020.2022. | | | | Signature | | Title | | | /s/ KENNETH W. CORNEW | | President and Chief Executive Officer (Principal Executive Officer) | Kenneth W. Cornew | | | | /s/ BRYAN P. WRIGHT | | Senior Vice President and Chief Financial Officer (Principal Financial Officer) | Bryan P. Wright | | | | /s/ MATTHEW N. BAUER | | Vice President and Controller (Principal Accounting Officer) | Matthew N. Bauer
| |
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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, in the City of Chicago and State of Illinois on the 11th day of February, 2020.
| | | | | COMMONWEALTH EDISON COMPANYSignature | | | | | By: | | /s/ JOSEPH DOMINGUEZ | | Name: | | Joseph Dominguez | | Title: | | Chief Executive Officer | |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities indicated on the 11th day of February, 2020.
Title | | | | Signature | | Title | | | /s/ JOSEPH DOMINGUEZGIL C. QUINIONES | | Chief Executive Officer (Principal Executive Officer) and Director | Joseph DominguezGil C. Quiniones | | | | /s/ JEANNE M. JONESJOSEPH R. TRPIK | | Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer) | Jeanne M. JonesJoseph R. Trpik | | | | /s/ GERALDSTEVEN J. KOZELCICHOCKI | | Vice President and ControllerDirector, Accounting (Principal Accounting Officer) | GeraldSteven J. KozelCichocki | |
This annual report has also been signed below by Joseph Dominguez,Gil C. Quiniones, Attorney-in-Fact, on behalf of the following Directors on the date indicated: | | | | Calvin G. Butler
James W. Compton
Christopher M. Crane
A. Steven Crown
| | Nicholas DeBenedictis
Peter V. Fazio, Jr.
Michael H. Moskow
Juan Ochoa
|
| | | | | | By:Calvin G. Butler, Jr. | | /s/ JOSEPH DOMINGUEZ | | February 11, 2020Ricardo Estrada | Name:Christopher M. Crane | Zaldwaynaka Scott | Nicholas DeBenedictis | Joseph DominguezSmita Shah | | | |
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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, in the City of Chicago and State of Illinois on the 11th day of February, 2020.
| | | | | PECO ENERGY COMPANY | | | | | By: | | /s/ MICHAEL A. INNOCENZO | | Name: | | Michael A. Innocenzo | | Title: | | President and Chief Executive Officer | |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities indicated on the 11th day of February, 2020.
| | | | Signature | | Title | | | /s/ MICHAEL A. INNOCENZO | | President, Chief Executive Officer (Principal Executive Officer) and Director | Michael A. Innocenzo | | | | /s/ ROBERT J. STEFANI | | Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer) | Robert J. Stefani | | | | /s/ SCOTT A. BAILEY | | Vice President and Controller (Principal Accounting Officer) | Scott A. Bailey | |
This annual report has also been signed below by Michael A. Innocenzo, Attorney-in-Fact, on behalf of the following Directors on the date indicated:
| | | | Calvin G. Butler | | John S. Grady | Christopher M. Crane | | Rosemarie B. Greco | Nicholas DeBenedictis | | Charisse R. Lillie | Nelson A. Diaz | | |
| | | | | | By: | | /s/ MICHAEL A. INNOCENZOGIL C. QUINIONES | | February 11, 202025, 2022 | Name: | | Michael A. InnocenzoGil C. Quiniones | | |
SIGNATURES Pursuant to the requirements of Section 13 or 15(d) 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, in the City of Chicago and State of Illinois on the 11th25th day of February, 2020.2022. | | | | | | | | | | | | BALTIMORE GAS AND ELECTRICPECO ENERGY COMPANY | | | | | By: | | /s/ CARIM V. KHOUZAMIMICHAEL A. INNOCENZO | | Name: | | Carim V. KhouzamiMichael A. Innocenzo | | Title: | | President and Chief Executive Officer | |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities indicated on the 11th25th day of February, 2020.2022. | | | | | | | | | Signature | | Title | | | /s/ CARIM V. KHOUZAMIMICHAEL A. INNOCENZO | | President, Chief Executive Officer (Principal Executive Officer) and Director | Carim V. KhouzamiMichael A. Innocenzo | | | | /s/ DAVID M. VAHOSROBERT J. STEFANI | | Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer) | David M. VahosRobert J. Stefani | | | | /s/ ANDREW W. HOLMESCAROLINE FULGINITI | | Vice President and ControllerDirector, Accounting (Principal Accounting Officer) | Andrew W. HolmesCaroline Fulginiti | |
This annual report has also been signed below by Carim V. Khouzami,Michael A. Innocenzo, Attorney-in-Fact, on behalf of the following Directors on the date indicated: | | | | Ann C. Berzin | | James R. Curtiss | Calvin G. Butler | | Joseph Haskins, Jr. | Christopher M. Crane | | Michael D. Sullivan | Michael E. Cryor | | Maria Harris Tildon |
| | | | | | By:Calvin G. Butler, Jr. | | /s/ CARIM V. KHOUZAMI | | February 11, 2020John S. Grady | Name:Christopher M. Crane | Rosemarie B. Greco | Nicholas DeBenedictis | Carim V. KhouzamiCharisse R. Lillie | Nelson A. Diaz | | | |
| | | | | | | | | | | | | | | By: | | /s/ MICHAEL A. INNOCENZO | | February 25, 2022 | Name: | | Michael A. Innocenzo | | |
SIGNATURES Pursuant to the requirements of Section 13 or 15(d) 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, in the City of Chicago and State of Illinois on the 11th25th day of February, 2020.2022. | | | | | | | | | | | | PEPCO HOLDINGS LLCBALTIMORE GAS AND ELECTRIC COMPANY | | | | | By: | | /s/ DAVID M. VELAZQUEZCARIM V. KHOUZAMI | | Name: | | David M. VelazquezCarim V. Khouzami | | Title: | | President and Chief Executive Officer | |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities indicated on the 11th25th day of February, 2020.2022. | | | | | | | | | Signature | | Title | | | /s/ DAVID M. VELAZQUEZCARIM V. KHOUZAMI | | President, Chief Executive Officer (Principal Executive Officer), and Director | David M. VelazquezCarim V. Khouzami | | | | /s/ PHILLIP S. BARNETTDAVID M. VAHOS | | Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)
| Phillip S. BarnettDavid M. Vahos | | | | /s/ ROBERT M. AIKENJASON T. JONES | | Vice President and ControllerDirector, Accounting (Principal Accounting Officer) | Robert M. AikenJason T. Jones | |
This annual report has also been signed below by David M. Velazquez,Carim V. Khouzami, Attorney-in-Fact, on behalf of the following Directors on the date indicated: | | | | Calvin. G. Butler | | Michael E. Cryor | Christopher M. Crane | | Ernest Dianastasis | Linda W. Cropp | | Debra P. DiLorenzo |
| | | | | | By:Ann C. Berzin | | /s/ DAVID M. VELAZQUEZ | | February 11, 2020James R. Curtiss | Name:Calvin G. Butler, Jr. | Joseph Haskins, Jr. | Christopher M. Crane | David M. VelazquezAmy Seto | Michael E. Cryor | Maria Harris Tildon | | |
| | | | | | | | | | | | | | | By: | | /s/ CARIM V. KHOUZAMI | | February 25, 2022 | Name: | | Carim V. Khouzami | | |
SIGNATURES Pursuant to the requirements of Section 13 or 15(d) 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, in the City of Chicago and State of Illinois on the 11th25th day of February, 2020.2022. | | | | | | | | | | | | POTOMAC ELECTRIC POWER COMPANYPEPCO HOLDINGS LLC | | | | | By: | | /s/ DAVID M. VELAZQUEZJ. TYLER ANTHONY | | Name: | | David M. VelazquezJ. Tyler Anthony | | Title: | | President and Chief Executive Officer | |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities indicated on the 11th25th day of February, 2020.2022. | | | | | | | | | Signature | | Title | | | /s/ DAVID M. VELAZQUEZJ. TYLER ANTHONY | | President, Chief Executive Officer (Principal Executive Officer), and Director | David M. VelazquezJ. Tyler Anthony | | | | /s/ PHILLIP S. BARNETT | | Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)
| Phillip S. Barnett | | | | /s/ ROBERT M. AIKENJULIE E. GIESE | | Vice President and ControllerDirector, Accounting (Principal Accounting Officer) | Robert M. AikenJulie E. Giese | |
This annual report has also been signed below by David M. Velazquez,J. Tyler Anthony, Attorney-in-Fact, on behalf of the following Directors on the date indicated: | | | | J. Tyler Anthony | | Christopher M. Crane | Phillip S. Barnett | | Melissa A. Lavinson | Calvin G. Butler | | Kevin M. McGowan |
| | | | | | By:Antoine Allen | | /s/ DAVID M. VELAZQUEZ | | February 11, 2020Linda W. Cropp | Name:Calvin G. Butler, Jr. | Michael E. Cryor | Christopher M. Crane | David M. VelazquezDebra P. DiLorenzo | | | |
| | | | | | | | | | | | | | | By: | | /s/ J. TYLER ANTHONY | | February 25, 2022 | Name: | | J. Tyler Anthony | | |
SIGNATURES Pursuant to the requirements of Section 13 or 15(d) 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, in the City of Chicago and State of Illinois on the 11th25th day of February, 2020.2022. | | | | | | | | | | | | DELMARVAPOTOMAC ELECTRIC POWER & LIGHT COMPANY | | | | | By: | | /s/ DAVID M. VELAZQUEZJ. TYLER ANTHONY | | Name: | | David M. VelazquezJ. Tyler Anthony | | Title: | | President and Chief Executive Officer | |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities indicated on the 11th25th day of February, 2020.2022. | | | | | | | | | Signature | | Title | | | /s/ DAVID M. VELAZQUEZJ. TYLER ANTHONY | | President, Chief Executive Officer (Principal Executive Officer), and Director | David M. VelazquezJ. Tyler Anthony | | | | /s/ PHILLIP S. BARNETT | | Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)
| Phillip S. Barnett | | | | /s/ ROBERT M. AIKENJULIE E. GIESE | | Vice President and ControllerDirector, Accounting (Principal Accounting Officer) | Robert M. AikenJulie E. Giese | |
This annual report has also been signed below by David M. Velazquez,J. Tyler Anthony, Attorney-in-Fact, on behalf of the following Directors on the date indicated: | | | | | | By:Phillip S. Barnett | | /s/ DAVID M. VELAZQUEZ | | February 11, 2020Rodney Oddoye | Name:Calvin G. Butler, Jr. | Elizabeth O'Donnell | Christopher M. Crane | David M. VelazquezTamla Olivier | | | |
| | | | | | | | | | | | | | | By: | | /s/ J. TYLER ANTHONY | | February 25, 2022 | Name: | | J. Tyler Anthony | | |
SIGNATURES Pursuant to the requirements of Section 13 or 15(d) 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, in the City of Chicago and State of Illinois on the 11th25th day of February, 2020.2022. | | | | | | | | | | | | ATLANTIC CITY ELECTRICDELMARVA POWER & LIGHT COMPANY | | | | | By: | | /s/ DAVID M. VELAZQUEZJ. TYLER ANTHONY | | Name: | | David M. VelazquezJ. Tyler Anthony | | Title: | | President and Chief Executive Officer | |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities indicated on the 11th25th day of February, 2020.2022. | | | | | | | | | Signature | | Title | | | /s/ DAVID M. VELAZQUEZJ. TYLER ANTHONY | | President, Chief Executive Officer (Principal Executive Officer), and Director | David M. VelazquezJ. Tyler Anthony | | | | /s/ PHILLIP S. BARNETT | | Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)
| Phillip S. Barnett | | | | /s/ ROBERT M. AIKENJULIE E. GIESE | | Vice President and ControllerDirector, Accounting (Principal Accounting Officer) | Robert M. AikenJulie E. Giese | |
This annual report has also been signed below by J. Tyler Anthony, Attorney-in-Fact, on behalf of the following Directors on the date indicated:
| | | | | | | | | | | | | | | By: | | /s/ J. TYLER ANTHONY | | February 25, 2022 | Name: | | J. Tyler Anthony | | |
SIGNATURES Pursuant to the requirements of Section 13 or 15(d) 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, in the City of Chicago and State of Illinois on the 25th day of February, 2022. | | | | | | | | | | | | ATLANTIC CITY ELECTRIC COMPANY | | | | | By: | | /s/ J. TYLER ANTHONY | | Name: | | J. Tyler Anthony | | Title: | | President and Chief Executive Officer | |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities indicated on the 25th day of February, 2022. | | | | | | | | | Signature | | Title | | | /s/ J. TYLER ANTHONY | | President, Chief Executive Officer (Principal Executive Officer) and Director | J. Tyler Anthony | | | | /s/ PHILLIP S. BARNETT | | Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer) | Phillip S. Barnett | | | | /s/ JULIE E. GIESE | | Director, Accounting (Principal Accounting Officer) | Julie E. Giese | |
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