| | | | | | | | | GLOSSARY OF TERMS AND ABBREVIATIONS | Exelon Corporation and Related Entities | Exelon | | Exelon Corporation | | ComEd | | | | | | PECO | | PECO Energy Company | | BGE | | Baltimore Gas and Electric Company | | | | | | | | | | | | | |
| | | | GLOSSARY OF TERMS AND ABBREVIATIONS | Exelon Corporation and Related Entities | Exelon | | Exelon Corporation | Generation | | Exelon Generation Company, LLC | ComEd | | Commonwealth Edison Company | PECO | | PECO Energy Company | BGE | | Baltimore Gas and Electric Company | Pepco Holdings or PHI | | Pepco Holdings LLC (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 ATFBSC | | Atlantic City Electric Transition Funding LLC | Antelope Valley | | Antelope Valley Solar Ranch One | BondCo | | RSB BondCo LLC | BSC | | Exelon Business Services Company, LLC | CENGEEDC | | Constellation Energy Nuclear Group, LLC | Constellation | | Constellation Energy Group, Inc. | 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 CompanyEnterprises | | Exelon TransmissionEnterprises Company, LLC | Exelon WindFoundation | | Exelon Wind, LLC and Exelon Generation Acquisition Company, LLCIndependent, non-profit philanthropic organization | FitzPatrickExelon InQB8R | | James A. FitzPatrick nuclear generating stationExelon InQB8R, LLC | GinnaPCI | | R. E. Ginna nuclear generating station | 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 | RPGUII | | Renewable Power Generation | SolGen | | SolGen, LLC | TMI | | Three Mile Island nuclear facility | UII | | Unicom Investments, Inc. |
| | | Former Related Entities | Constellation | | Constellation Energy Corporation | Generation or CEG | | 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) | | | | | | | CENG | | Constellation Energy Nuclear Group, LLC | | | | | | | FitzPatrick | | James A. FitzPatrick nuclear generating station | EDF | | Electricite de France SA and its subsidiaries | | | | | | | | | | | | | | | |
| | | | | | | | | GLOSSARY OF TERMS AND ABBREVIATIONS | Other Terms and Abbreviations | | | AEC2021 Form 10-K | | The Registrants' Annual Report on Form 10-K for the year ended December 31, 2021 filed with the SEC on February 25, 2022 | 2021 Recast Form 10-K | | The Registrants' Current Report on Form 8-K filed with the SEC on June 30, 2022 to recast Exelon's consolidated financial statements and certain other financial information originally included in the 2021 Form 10-K | Note - of the 2021 Recast Form 10-K | | Reference to specific Combined Note to Consolidated Financial Statements in the 2021 Recast Form 10-K | ABO | | Accumulated Benefit Obligation | AECs | | Alternative Energy CreditCredits that isare issued for each megawatt hour of generation from a qualified alternative energy source | AESOAFUDC | | 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) | ARCARO | | Asset Retirement Cost | ARO | | Asset Retirement Obligation | ARP | | Alternative Revenue Program | ASA | | Asset Sale Agreement | BGS | | Basic Generation Service | CAISOBSA | | California ISOBill Stabilization Adjustment | CAPCBAs | | Customer Assistance ProgramCollective Bargaining Agreements | CCGTsCEJA (formerly Clean Energy Law in the Exelon 2021 Form 10-K) | | Combined-Cycle gas turbinesClimate and Equitable Jobs Act; Illinois Public Act 102-0662 signed into law on September 15, 2021 | CERCLA | | Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended | CESCIP | | Clean Energy StandardConservation Incentive Program | 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 | CODMs | | Chief Operating Decision MakerMakers | 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 | | United States Department of EnergyDelaware Public Service Commission | DOEE | | | DOEE | | Department of Energy & Environment | DOJ | | United States Department of Justice | DPSCDPA | | Delaware Public Service CommissionDeferred Prosecution Agreement | DSPDPP | | Deferred Purchase Price | | | | DSIC | | Distribution System Improvement Charge | DSP | | Default Service Provider | DSP Program | | Default Service Provider Program | EDFEIMA | | Electricite de France SA and its subsidiaries | 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 | ETAC | | Energy Transition Assistance Charge | | | | FEJA | | Illinois Public Act 99-0906 or Future Energy Jobs Act | FERC | | Federal Energy Regulatory Commission | FRCC | | Florida Reliability Coordinating Council | FRRGAAP | | Fixed Resource Requirement | GAAP | | Generally Accepted Accounting Principles in the United States | GCR | | Gas Cost Rate |
| | | | | | | | | GHG | | Greenhouse GasGLOSSARY OF TERMS AND ABBREVIATIONS | GSAOther Terms and Abbreviations | | | GHG | | Greenhouse Gas | GSA | | Generation Supply Adjustment | GWhGWhs | | Gigawatt hourhours | IBEWICC | | International Brotherhood of Electrical Workers | 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 | ISOISOs | | Independent System OperatorOperators | ISO-NE | | ISO New England Inc. | NYISO | | New York ISO | kV | | Kilovolt | kW | | Kilowatt | kWh | | 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 ABBREVIATIONSLIBOR | | London Interbank Offered Rate | Other Terms and AbbreviationsLNG | | Liquefied Natural Gas | mmcf | | | LTIP | | Long-Term Incentive Plan | LTRRPP | | Long-Term Renewable Resources Procurement Plan | | | | MDPSC | | Maryland Public Service Commission | MGP | | Manufactured Gas Plant | mmcf | | Million Cubic Feet | Moody’sMRP | | Moody’s Investor ServiceMulti-Year Rate Plan | MOPRMRV | | Minimum Offer Price RuleMarket-Related Value | MRVMW | | Market-Related ValueMegawatt | MWMWh | | Megawatt hour | MWhN/A | | Megawatt hourNot applicable | n.m.NAV | | not meaningful | NAAQS | | National Ambient Air Quality Standards | NAV | | Net Asset Value | NDT | | Nuclear Decommissioning Trust | NEILNERC | | Nuclear Electric Insurance Limited | NERC | | North American Electric Reliability Corporation | NGSNJBPU | | Natural Gas Supplier | NJBPU | | New Jersey Board of Public Utilities | NJDEP | | New Jersey Department of Environmental Protection | NLRB | | 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 | OCI | | Other Comprehensive Income | OIESO | | Ontario Independent Electricity System Operator | OPC | | 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 | POR | | Purchase of Receivables | PPA | | Power Purchase Agreement | 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 |
| | | | GLOSSARY OF TERMS AND ABBREVIATIONSNPDES | | National Pollutant Discharge Elimination System | Other Terms and AbbreviationsNPNS | | Normal Purchase Normal Sale scope exception | PRPNPS | | National Park Service | NRD | | Natural Resources Damages | OCI | | Other Comprehensive Income | OPEB | | Other Postretirement Employee Benefits | | | | PAPUC | | Pennsylvania Public Utility Commission | PCBs | | Polychlorinated Biphenyls | PGC | | Purchased Gas Cost Clause | PJM | | PJM Interconnection, LLC | PJM Tariff | | PJM Open Access Transmission Tariff | POLR | | Provider of Last Resort | PPA | | Purchase Power Agreement | PP&E | | Property, Plant, and Equipment | PRPs | | Potentially Responsible Parties | PSEG | | Public Service Enterprise Group Incorporated | PV | | 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 accountingagreements with the ICC and PAPUC |
| | | | | | | | | RESGLOSSARY OF TERMS AND ABBREVIATIONS | Other Terms and Abbreviations | | | RES | | Retail Electric Suppliers | RFP | | Request for Proposal | Rider | | Reconcilable Surcharge Recovery Mechanism | RGGI | | Regional Greenhouse Gas Initiative | RMC | | Risk Management Committee | RNFROE | | 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 | SERCSOA | | SERC Reliability Corporation (formerly Southeast Electric Reliability Council)Society of Actuaries | SGIGSOFR | | Smart Grid Investment Grant from DOESecured Overnight Financing Rate | SILOSOS | | Sale-In, Lease-Out | SNF | | Spent Nuclear Fuel | SOS | | Standard Offer Service | SPFPASSA | | Social Security Police and Fire Professionals of AmericaAdministration | SPPSTRIDE | | Southwest Power PoolMaryland 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 | Transition Bonds | | Transition Bonds issued by ACEAtlantic City Electric Transition Funding LLC | 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 | VIEZEC | | 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,” "should," 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, Commitments and Contingencies;Contingencies, and (d) other factors discussed in filings with the SEC by the Registrants. Readers Investors are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this Report. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this Report. WHERE TO FIND MORE INFORMATION The SEC maintains an Internet site at www.sec.gov that contains reports, proxy and information statements, and other information that the Registrants file electronically with the SEC. These documents are also available to the public from commercial document retrieval services and the Registrants’ website at www.exeloncorp.com. Information contained on the Registrants’ website shall not be deemed incorporated into, or to be a part of, this Report.
PART I General Corporate Structure and Business and Other Information Exelon is a utility services holding company engaged in the generation, delivery and marketing of energy through Generation and the energy distribution and transmission businesses through ComEd, PECO, BGE, Pepco, DPL, and ACE. On February 21, 2021, Exelon’s Board of Directors approved a plan to separate the Utility Registrants and Generation. The separation was completed on February 1, 2022, creating two publicly traded companies, Exelon and Constellation. See Note 2 – Discontinued Operations of the Combined Notes to Consolidated Financial Statements for additional information. | | | | | | | | | | | | | | | Name of Registrant | | State/Jurisdiction andBusiness | | Business | | Service Territories | Year of Incorporation | Territories | Exelon Generation
Company, LLC
| | 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 segmentssegments: 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,finance, 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
Utility Registrants Utility Operations Service Territories and Franchise Agreements The following table presents the merger contemplated by the Merger Agreement among Exelon, Purple Acquisition Corp., a wholly owned subsidiarysize of Exelon (Merger Sub) and PHI. As a resultservice territories, populations 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 Generationeach service territory, and the transfernumber of PHI, Pepco, DPL and ACE tocustomers within each service territory for the Utility Registrants as of December 31, 2022: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE | Service Territories (in square miles) | Electric | | 11,450 | | | 1,900 | | | 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 | | | 4.1 | | | 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 | | | 4.1 | | | 3.2 | | | 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 special purpose subsidiary of EEDC. Generation
Generation, one of the largest competitivesquare mile that includes both 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,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 competitive energy marketsa 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 both wholesaleperform their current business of providing regulated electric and retail customers. Generation leverages its energy generation portfolionatural 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 ensure deliveryextend or replace the authorizations prior to their expirations.
Utility Regulations State utility commissions regulate the Utility Registrants' electric and retail customers under long-termgas distribution rates and short-term contracts,service, issuances of certain securities, and in wholesale power markets. Generation operates in well-developed energy markets and employs an integrated hedging strategy to manage commodity price volatility. Generation's fleet also provides geographic and supply source diversity. Generation’s customers include distributioncertain 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 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 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 functionrelated 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 Texas to2021 that performed by RTOs in markets regulated by FERC.
Specific operations of Generationregulate cyber risks for certain gas distribution operators. Additionally, the Utility Registrants 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’snation's bulk power system against potential disruptions from cyber and physical security breaches.
AcquisitionsSeasonality Impacts on Delivery Volumes
The Utility Registrants' electric distribution volumes are generally higher during the summer and Dispositionswinter 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. DispositionComEd, 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 Oyster Creek.On July 1, 2019, Generation completed the sale with Holtec International (Holtec)weather 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 operationscustomer usage patterns on September 17, 2018.
Disposition of EGTPelectric distribution 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.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 CEJA, which contains requirements for ComEd to transition away from the performance-based rate formula by the end of 2022 and would allow for the bankruptcy filing, EGTP’s assetssubmission of either a general rate or multi-year rate plan. On February 3, 2022, the ICC approved a tariff that establishes the process under which ComEd will reconcile its 2022 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 conjunction2023 rate year revenue requirements with actual costs. ComEd filed a petition with the EGTP Chapter 11ICC seeking approval of a multi-year rate plan (MRP) for 2024-2027 on January 17, 2023. PECO's and DPL's electric and gas distribution costs and ACE's electric distribution costs have generally been recovered through rate case proceedings, forwith PECO utilizing a total purchase price of $62 million.
Acquisition of FitzPatrick. On March 31, 2017, Generation acquiredfully projected future test year while DPL and ACE utilize a historical test year. BGE’s electric and gas distribution costs and Pepco’s and DPL Maryland's electric distribution costs are currently recovered through multi-year rate case proceedings, as 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.
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 servicesMDPSC and energy efficiency businesses of ConEdison were excluded from the transaction.
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. See Note 23 — Mergers, Acquisitions and Dispositions and Note 11 — Asset ImpairmentsRegulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on acquisitionsinformation. ComEd, Pepco, DPL and dispositions. Generating Resources
At December 31, 2019,ACE customers have the generating resources of Generation consisted ofchoice to purchase electricity, and PECO and BGE customers have the following:
| | | | Type of Capacity | MW | Owned generation assets(a)(b)
| | Nuclear | 18,872 |
| Fossil (primarily natural gas and oil) | 9,665 |
| Renewable(c)
| 3,057 |
| Owned generation assets | 31,594 |
| Contracted generation(d)
| 4,765 |
| Total generating resources | 36,359 |
|
__________
| | (a) | See “Fuel” for sources of fuels used in electric generation. |
| | (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. |
Generation has five reportable segments, as described in the table below, representing the different geographical areas in which Generation’s generating resources are locatedchoice to purchase electricity and Generation's customer-facing activities are conducted.
| | | | | | | 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 |
Nuclear Facilities
Generation has ownership interests in thirteen nuclear generating stations currently in service, consisting of 23 units with an aggregate of 18,872 MW of capacity. Generation wholly owns all of its nuclear generating stations, except for undivided ownership interests in three jointly-owned nuclear stations: Quad Cities (75% ownership), Peach Bottom (50% ownership),natural gas from competitive electric generation and Salem (42.59% ownership), which are consolidated in Exelon’s and Generation's financial statements relative to its proportionate ownership interest in each unit, and 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 an option to sell its 49.99% equity interest in CENG to Generation. The put option became exercisable on January 1, 2016 and may be exercised any time until June 30, 2022. On November 20, 2019, Generation received notice of EDF’s intention to exercise the put option and sell its ownership share in CENG to Generation. 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 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.
See ITEM 2. PROPERTIES for additional information on Generation's nuclear facilities and Note 22 — 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,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 two units at Salem, whichdistribution service providers for all customers and are operated by PSEG Nuclear, LLC (PSEG Nuclear), an indirect, wholly owned subsidiaryobligated 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 PSEG. In 2019, 2018customers in their respective service areas who do not choose a competitive electric generation supplier. PECO, BGE, and 2017DPL 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 supply (in GWh) generatedgeneration or natural gas from competitive suppliers, the nuclear generating facilities was 64%, 68%Utility Registrants act as the billing agent and 69%, respectively, of Generation’s totaltherefore 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 supply, which also includes fossil, hydroelectricgeneration or natural gas from a Utility Registrant, the Utility Registrants are permitted to recover the electricity and renewable generationnatural gas procurement costs from customers without mark-up or with a slight mark-up and electric supply purchased for resale. Generation’s wholesaletherefore record the amounts in Operating revenues and retailPurchased power marketing activities are,and fuel expense. As a result, fluctuations in part, supplied byelectricity or natural gas sales and procurement costs have no significant impact on the output from the nuclear generating stations. 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 Generation’sElectricity and Natural Gas Exelon does not generate the electricity it delivers. The Utility Registrants' electric supply sources.for its customers is primarily procured through contracts as directed by their respective state laws and regulatory commission actions. The Utility Registrants procure electricity supply from various approved bidders or from purchases on the PJM operated markets. Nuclear OperationsPECO's, BGE’s, and DPL's natural gas supplies are purchased from a number of suppliers for terms that currently do not exceed three years. PECO, BGE, and DPL each have annual firm transportation contracts of 443,000 mmcf, 268,000 mmcf, and 44,000 mmcf, respectively, for delivery of gas. To supplement gas transportation and 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:
Capacity | | | | | | | | | | | | | | | | | | | 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 27%, 42%, and 33% of PECO's, BGE’s, and DPL's 2022-2023 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, with limited exceptions, earns a return on its energy efficiency costs through a regulatory asset. BGE, Pepco Maryland, DPL Maryland, and ACE earn a return on most of their energy efficiency and demand response program costs through a regulatory asset. 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 2023 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 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. 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 Following the separation on February 1, 2022, Exelon is now a Distribution and Transmission company, focused on delivering electricity and natural gas service to our customers and communities. Exelon's businesses remain focused on maintaining industry leading operational excellence, meeting or exceeding their financial commitments, ensuring timely recovery on investments to enable customer benefits, supporting clean energy policies including those that advance our jurisdictions' clean energy targets, 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 jurisdictions in which Exelon has operations have set some of the nation's leading clean energy targets and our strategy is to enable that future for all our stakeholders. The Utility Registrants invest in rate base that supports service to our customers and the community, including investments that sustain and improve reliability and resiliency and that enhance the service experience of our customers. The Utility Registrants make these investments prudently at a 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.
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 $31 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 $18 billion by the end of 2026. These investments provide greater reliability, improved service for our customers, increased capacity to accommodate new technologies and support a cleaner grid, and a stable return for the company. In August 2021, Exelon announced a Path to Clean goal to collectively reduce its operations-driven GHG emissions 50% by 2030 against a 2015 baseline and to reach net zero operations-driven GHG emissions by 2050, while supporting customers and communities in achieving their GHG reduction goals (Path to Clean). Exelon's quantitative goals include its Scope 1 and 2 GHG emissions, with the exception of Scope 2 emissions associated with system losses of electric power delivered to customers ("line losses"), and build upon Exelon's long-standing commitment to reducing our GHG emissions. Exelon's Path to Clean efforts extend beyond these quantitative goals to include efforts such as customer energy efficiency programs, which support reductions in customers' direct emissions and have the potential to reduce Exelon's Scope 3 emissions and Scope 2 line losses as well. See ITEM 1. BUSINESS — Environmental Matters and Regulation — Climate Change for additional information. Various market, financial, regulatory, legislative, and operational factors whichcould 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 culture that promotes and embodies diversity, inclusion, innovation, and safety for their employees. In order to provide the services and products that their customers expect, the Registrants aspire to create teams that reflect the diversity of the communities that the Registrants serve. Therefore, the Registrants take steps to attract highly qualified and diverse talent and seek to create hiring and promotion practices that are equitable and neutralize any bias, including 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; mentorship programs; 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 typically conduct an employee engagement survey every other year to help identify organizational strengths and areas of opportunity for growth. 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, 2022. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Employees | | Exelon | | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Female(a)(b)(c) | | 5,300 | | | | | 1,535 | | | 752 | | | 786 | | | 1,270 | | | 329 | | | 139 | | | 109 | | People of Color(b)(c) | | 7,519 | | | | | 2,575 | | | 990 | | | 1,170 | | | 1,803 | | | 865 | | | 203 | | | 145 | | Aged <30 | | 2,026 | | | | | 721 | | | 361 | | | 286 | | | 424 | | | 169 | | | 85 | | | 61 | | Aged 30-50 | | 10,548 | | | | | 3,728 | | | 1,455 | | | 1,819 | | | 2,271 | | | 739 | | | 465 | | | 357 | | Aged >50 | | 6,489 | | | | | 1,907 | | | 1,070 | | | 1,061 | | | 1,466 | | | 442 | | | 341 | | | 203 | | Total Employees(d) | | 19,063 | | | | | 6,356 | | | 2,886 | | | 3,166 | | | 4,161 | | | 1,350 | | | 891 | | | 621 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Management(e) | | Exelon | | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Female(a)(b)(c) | | 961 | | | | | 235 | | | 139 | | | 122 | | | 206 | | | 51 | | | 13 | | | 21 | | People of Color(b)(c) | | 1,086 | | | | | 331 | | | 134 | | | 166 | | | 276 | | | 116 | | | 32 | | | 22 | | Aged <30 | | 29 | | | | | 7 | | | 9 | | | 4 | | | 6 | | | — | | | 2 | | | 2 | | Aged 30-50 | | 1,715 | | | | | 510 | | | 182 | | | 265 | | | 395 | | | 120 | | | 58 | | | 40 | | Aged >50 | | 1,286 | | | | | 363 | | | 190 | | | 163 | | | 276 | | | 61 | | | 57 | | | 40 | | Within 10 years of retirement eligibility | | 1,787 | | | | | 520 | | | 238 | | | 226 | | | 379 | | | 91 | | | 68 | | | 55 | | Total Employees in Management(d) | | 3,030 | | | | | 880 | | | 381 | | | 432 | | | 677 | | | 181 | | | 117 | | | 82 | |
__________ (a)The Registrants have a particular focus on creating an environment that attracts and retains women by enabling them to stay in the workforce, grow with the company, and move up the ranks. (b)To effectuate Exelon's pay equity goals, Exelon conducts analysis on gender and racial pay equity. (c)Information concerning women and people of color is based on self-disclosed information. (d)Total employees represents the sum of the aged categories. (e)Management is defined as executive/senior level officials and managers as well as all employees who have direct reports and/or 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 2020 to 2022. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exelon | | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Retirement Age | | 3.71 | % | | | | 4.09 | % | | 4.10 | % | | 3.48 | % | | 3.79 | % | | 3.74 | % | | 4.42 | % | | 3.88 | % | Voluntary | | 2.79 | % | | | | 2.22 | % | | 2.71 | % | | 1.76 | % | | 2.52 | % | | 2.81 | % | | 1.46 | % | | 1.84 | % | Non-Voluntary | | 0.81 | % | | | | 0.60 | % | | 1.10 | % | | 1.06 | % | | 1.02 | % | | 1.95 | % | | 0.47 | % | | 0.68 | % |
Collective Bargaining Agreements Approximately 44% of Exelon’s employees participate in CBAs. The following table presents employee information, including information about CBAs, as of December 31, 2022. | | | | | | | | | | | | | | | | | | | | | | | | | Total Employees Covered by CBAs | | Number of CBAs | | CBAs New and Renewed in 2022(a) | | Total Employees Under CBAs New and Renewed in 2022 | Exelon | 8,379 | | | 10 | | | 2 | | | 906 | | | | | | | | | | ComEd | 3,477 | | | 2 | | | — | | | — | | PECO | 1,368 | | | 2 | | | — | | | — | | BGE | 1,414 | | | 1 | | | — | | | — | | PHI | 2,113 | | | 5 | | | 2 | | | 906 | | Pepco | 890 | | | 1 | | | 1 | | | 890 | | DPL | 621 | | | 2 | | | — | | | — | | ACE | 401 | | | 2 | | | 1 | | | 16 | |
__________ (a)Does not include CBAs that were extended in 2022 while negotiations are ongoing for renewal.
Environmental Matters and Regulation 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 Audit and Risk Committee oversees compliance with environmental laws and regulations, including environmental risks related to Exelon's operations and facilities, as well as SEC disclosures related to environmental matters. Exelon's Corporate Governance Committee has the authority to oversee Exelon’s climate change and sustainability policies and programs, as discussed in further detail below. The respective Boards of the Utility Registrants oversee environmental issues related to these companies. The Exelon Board of Directors has general oversight responsibilities for ESG matters, including strategies and efforts to protect and improve the quality of the environment. 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 to the physical climate and environment, 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 climate legislation, Exelon supports the 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 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, as distributors of natural gas are regulated with respect to reporting of natural gas (methane) leakage on the natural gas systems and consumer use of such natural gas. Since its inception, Exelon has positioned itself as a leader in climate change mitigation. Exelon uses definitions and protocols provided by the World Resources Institute for its GHG inventory. In 2021, Exelon's Scope 1 and 2 GHG emissions, as revised following its separation from Constellation, were just over 5.7 million metric tons carbon dioxide equivalent using the World Resources Institute Corporate Standard Market-based accounting. Of these emissions, 0.5 million metric tons are considered to be operations-driven and in more direct control of our employees and processes. The majority of these operations-driven emissions are fugitive emissions from the gas delivery systems of Registrants PECO, BGE, and DPL. The remaining 5.2 million metric tons, approximately 91%, are the indirect emissions associated with the operation and use of the electric distribution and transmission system and primarily consists of losses resulting from the Utility Registrant's delivery of electricity to their customers (line losses). These emissions are driven primarily by customer demand for electricity and the mix of generation assets supplying energy to the electric grid. The Registrants do not own generation and must comply with applicable legal and regulatory requirements governing procurement of electricity for delivery to retail customers and use of the system to support other transmission transactions. However, the Registrants do engage in efforts that help to reduce these emissions, including customer programs to drive customer energy efficiency, help to manage peak demands, and enable distributed solar generation.
In August 2021, Exelon announced a Path to Clean goal to collectively reduce their operations-driven GHG emissions 50% by 2030 against a 2015 baseline, and to reach net zero operations-driven GHG emissions by 2050, while also supporting customers and communities to achieve their clean energy and emissions goals. Exelon’s quantitative goals include its Scope 1 and 2 GHG emissions, with the exception of Scope 2 line losses, and builds upon Exelon's long-standing commitment to reducing our GHG emissions. Exelon's activities in support of the Path to Clean goal will include efficiency and clean electricity for operations, vehicle fleet electrification, equipment and processes to reduce sulfur hexafluoride (SF6) leakage, investments in natural gas infrastructure to minimize methane leaks and increase safety and reliability, and investment and collaboration to develop new technologies. Beyond 2030, Exelon recognizes that technology advancement and continued policy support will be needed to ensure achievement of Net-Zero by 2050. Exelon is laying the groundwork by partnering with national labs, universities and research consortia to research, develop, and pilot clean technologies that will be needed, as well as working with our states, jurisdictions and policy makers to understand the scope and scale of energy transformation, and needed policies and incentives, that will be needed to reach local ambitions for GHG emissions reductions. The Utility Registrants are also supporting customers and communities to achieve their clean energy and emissions goals through significant energy efficiency programs. During 2023 - 2026, estimated customer program energy efficiency investments across the Utility Registrants total $3.5 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. As an energy delivery company, Exelon can play a key role in lowering GHG emissions across much of the economy in its service territories. In connecting end users of energy to electric and gas supply, Exelon can leverage its assets and customer interface to encourage efficient use of lower emitting resources as they become available. 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 have a goal to electrify 30% of their own vehicle fleet by 2025, increasing to 50% by 2030. Clean fuels and other emerging technologies can also support the transition, lessen the strain on electric system expansion, and support energy system resiliency. Exelon, and its registrants PECO, BGE, and DPL that own gas distribution assets, are also continuing to explore these other decarbonization opportunities, supporting pilots of emerging energy technologies and clean fuels to support both operational and customer-driven emissions reductions. The energy transition may present challenges for the Utility Registrants and their service territories. Exelon believes its market and business model could be 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.
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 operationtransition of the nuclear units. Generation also has extensive safety systemsenergy system, such as through an increased electric load and decreased demand for natural gas, potentially accompanied by changes in place to protecttechnology, customer expectations, and/or regulatory structures. See ITEM 1A. RISK FACTORS. The Registrants are potentially affected by emerging technologies that could over time affect or transform the plant, personnelenergy industry.
Climate Change Adaptation The Registrants' facilities and surrounding area in the unlikely event of an accident or other incident. Regulation of Nuclear Power Generation
Generation isoperations are subject to the jurisdictionimpacts of global 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 for additional information related to the Registrants' risks associated with climate change.
The Registrants' assets undergo seasonal readiness efforts to ensure they are ready for the weather projections of the NRC with respectsummer and winter months. The Registrants consider and review national climate assessments to inform their planning. Each of the Utility Registrants also has well established 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. International Climate Change Agreements. At the international level, the United States is a party to the operationUnited 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, but on January 20, 2021, President Biden
accepted the Agreement, which resulted in the United States’ formal re-entry on February 19, 2021. The United States has set an economy-wide target of reducing its nuclear generating stations, includingnet GHG emissions by 50-52% below 2005 levels by 2030. On November 11, 2022 at the licensing for operationUNFCCC Conference of each unit. The NRC subjects nuclear generating stationsthe Parties (COP 27), President Biden recommitted the U.S. to continuing reviewthese goals and regulation covering, among other things, operations, maintenance, emergency planning,detailed the significant domestic climate actions the U.S. had taken to spur a new era of clean American manufacturing, enhance energy security, and environmentaldrive down the costs of clean energy for consumers in the U.S. and radiological aspects of those stations. As part of its reactor oversight process,around the NRC continuously assesses unit performance indicatorsworld. Federal Climate Change Legislation and inspection resultsRegulation.On August 16, 2022, President Biden signed the Inflation Reduction Act (IRA), which aims to reduce U.S. carbon emissions and communicates its assessment on a semi-annual basis. All nuclear generating stations operated by Generation are categorizedpromote economic development through investments in clean and renewable energy projects. The consumer-facing clean energy tax credits created or expanded by the NRCIRA are intended to drive rapid adoption of energy efficiency, electric transportation, and solar energy which would require Exelon's utilities to expand and modernize infrastructure, systems and services to integrate and optimize these resources. 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 Licensee Response Column, which isU.S. Court of Appeals for the highest of five performance bands. The NRC may modify, suspend or revoke operating licenses and impose civil penalties for failure to comply withD.C. Circuit, challenging the Atomic Energy Act, the regulations
under such Act or the termsrescission of the operating licenses. ChangesClean Power Plan and enactment of the Affordable Clean Energy rule as unlawful. On January 19, 2021, the D.C. Circuit held the Affordable Clean Energy Rule (including its rescission of the Clean Power Plan) to be unlawful, vacated the rule, and remanded it to the EPA. The Supreme Court granted certiorari to examine the extent of the EPA's authority to regulate GHGs from power plants and, on June 30, 2022, reversed and remanded the D.C. Circuit's decision. The Supreme Court ruled that the EPA's use of generation shifting for development of standards in regulationsthe Clean Power Plan went beyond Congress' intended authority under the Clean Air Act. The EPA has indicated that 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 NRC may require a substantial increaseRegistrants. As of February 1, 2022, following its separation from Constellation, Exelon no longer owns electric generation plants.
State Climate Change Legislation and Regulation. A number of states in capital expenditures and/or operating costswhich 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 nuclear generating facilities.additional information on renewable and other portfolio standards. Licenses
Generation has original 40-year operating licenses fromCertain northeast and mid-Atlantic states (Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Pennsylvania, Rhode Island, Vermont, Virginia) currently participate in the NRCRGGI. The program requires most fossil fuel-fired power plant owners and operators in the region to hold allowances, purchased at auction, for each ton of its nuclear unitsCO2 emissions. Non-emitting resources do not have to purchase or hold these allowances. Pennsylvania joined RGGI in April 2022.
Broader state programs impact other sectors as well, such as the District of Columbia's Clean Energy DC Omnibus Act and has received 20-year operating license renewals from the NRCcross-sector GHG reduction plans, which resulted in recent requirements for all its nuclear units except Clinton. Additionally, PSEG has received 20-year operating license renewals for Salem Units 1 and 2. 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 | Braidwood | 1 |
| | 1988 | | 2046 | | 2 |
| | 1988 | | 2047 | Byron | 1 |
| | 1985 | | 2044 | | 2 |
| | 1987 | | 2046 | Calvert Cliffs | 1 |
| | 1975 | | 2034 | | 2 |
| | 1977 | | 2036 | Clinton(b) | 1 |
| | 1987 | | 2027 | Dresden | 2 |
| | 1970 | | 2029 | | 3 |
| | 1971 | | 2031 | FitzPatrick | 1 |
| | 1974 | | 2034 | LaSalle | 1 |
| | 1984 | | 2042 | | 2 |
| | 1984 | | 2043 | Limerick | 1 |
| | 1986 | | 2044 | | 2 |
| | 1990 | | 2049 | Nine Mile Point | 1 |
| | 1969 | | 2029 | | 2 |
| | 1988 | | 2046 | Peach Bottom(c) | 2 |
| | 1974 | | 2033 | | 3 |
| | 1974 | | 2034 | Quad Cities | 1 |
| | 1973 | | 2032 | | 2 |
| | 1973 | | 2032 | Ginna | 1 |
| | 1970 | | 2029 | Salem | 1 |
| | 1977 | | 2036 | | 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. |
The operating license renewal process takes approximately four to five years from the commencement of the renewal process, which includes approximately two years for GenerationPepco to develop 5-year and 30-year decarbonization programs and strategies. Maryland expects to meet and exceed the applicationmandate set in the Greenhouse Gas Emissions Reduction Act to reduce statewide GHG emissions 40% (from 2006 levels) by 2030, and approximately two yearsthe state’s Climate Solutions Now Act of 2022 further updates requirements with a proposal to reduce emissions 60% (from 2006 levels) by 2031. 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. Illinois’ climate bill, CEJA, establishes decarbonization requirements for the NRCstate 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 reflect the first renewal of the operating licenses for all of Generation’s operating nuclear generating stations except for Clintontransition to 100% clean energy by 2050 and Peach Bottom. Clinton depreciation provisions are based on an estimated useful life of 2027 which is the last year of the Illinois ZES. Peach Bottom depreciation provisions are based on estimated
useful life of 2053supports programs to improve energy efficiency, manage energy demand, attract clean energy investment and 2054 for Unit 2 and Unit 3, respectively, which reflects the anticipated second renewal of its operating licenses.accelerate job creation. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on FEJACEJA.
The Registrants cannot predict the nature of future regulations or how such regulations might impact future financial statements.
Renewable and Clean Energy Standards. Each of 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 acquiring sufficient bundled or unbundled credits such as RECs, CMCs, or ZECs, or 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 63 — Early Plant RetirementsRegulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on early retirements.information. NuclearOther 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 Storage and DisposalEnvironmental Remediation There are no facilitiesCERCLA 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 reprocessingsituation 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 permanentmay 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 SNF currently in operationsolid and hazardous wastes and cleanup of sites where such activities were conducted.
The Registrants’ operations have in the United States, nor haspast, and may in the NRC licensed any such facilities. Generation currently stores all SNFfuture, 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 its nuclear generating facilities on-sitethem. 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 storage poolscontamination by substances that are considered hazardous under environmental laws. The Registrants and their subsidiaries are, or could become in dry cask storage facilities. Since Generation’s SNF storage pools generallythe 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, which were operated by ComEd's and PECO's predecessor companies. 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 certain environmental remediation costs of the MGP sites through a provision within customer rates. BGE, Pepco, DPL, and ACE do not have sufficient storage capacitymaterial contingent liabilities relating to MGP sites. The amount to be
expended in 2023 for the lifecompliance with environmental remediation related to contamination at former MGP sites and other gas purification sites is estimated to be approximately $52 million which consists primarily of the respective plant, Generation has developed dry cask storage facilities to support operations.$44 million at ComEd. As of December 31, 2019, Generation had approximately 84,700 SNF assemblies (21,000 tons) stored on site in SNF pools or dry cask storage which includes SNF assemblies at Zion Station,2022, the Registrants have established appropriate contingent liabilities for which Generation retains ownership even thoughenvironmental remediation requirements. In addition, the responsibility for decommissioning 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. 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. 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 18 — 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 statesRegistrants 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.
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 2032 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 stationsmake significant additional expenditures not presently determinable for Class Bother environmental remediation costs.
See Note 3 — Regulatory Matters 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 18 — 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-insuredthe Registrants’ environmental matters, remediation efforts, and related impacts to the extentRegistrants’ Consolidated Financial Statements.
Information about our Executive Officers as of February 14, 2023 Exelon | | | | | | | | | | | | | | | | | | | | | Name | | Age | | Position | | Period | Butler, Calvin G. Jr. | | 53 | | | President and Chief Executive Officer, Exelon | | 2022 - Present | | | | | Chief Operating Officer, Exelon | | 2021 - 2022 | | | | | Senior Executive Vice President, Exelon | | 2019 - 2022 | | | | | Chief Executive Officer, Exelon Utilities | | 2019 - 2022 | | | | | Chief Executive Officer, BGE | | 2014 - 2019 | | | | | | | | | | | | | | | Jones, Jeanne | | 43 | | | Executive Vice President and Chief Financial Officer, Exelon | | 2022 - Present | | | | | Senior Vice President, Corporate Finance, Exelon | | 2021 - 2022 | | | | | Senior Vice President and Chief Financial Officer, ComEd | | 2018 - 2021 | | | | | | | | Glockner, David | | 62 | | | Executive Vice President, Compliance, Audit and Risk, Exelon | | 2020 - Present | | | | | Chief Compliance Officer, Citadel LLC | | 2017 - 2020 | | | | | | | | Littleton, Gayle E. | | 50 | | | Executive Vice President, General Counsel, Exelon | | 2020 - Present | | | | | Partner, Jenner & Block LLP | | 2015 - 2020 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Quiniones, Gil | | 56 | | | Chief Executive Officer, ComEd | | 2021 - Present | | | | | President and Chief Executive Officer, New York Power Authority | | 2011 - 2021 | | | | | | | | Innocenzo, Michael A. | | 57 | | | President and Chief Executive Officer, PECO | | 2018 - Present | | | | | | | | | | | | | | | Khouzami, Carim V. | | 48 | | | President, BGE | | 2021 - Present | | | | | Chief Executive Officer, BGE | | 2019 - Present | | | | | Senior Vice President & COO, Exelon Utilities | | 2018 - 2019 | | | | | | | | Anthony, J. Tyler | | 58 | | | President and Chief Executive Officer, PHI, Pepco, DPL, and ACE | | 2021 - Present | | | | | Senior Vice President and Chief Operating Officer, PHI, Pepco, DPL, and ACE | | 2016 - 2021 | | | | | | | | Trpik, Joseph R. | | 53 | | | Senior Vice President and Corporate Controller, Exelon | | 2022 - Present | | | | | Interim Senior Vice President & CFO, ComEd | | 2021 - 2022 | | | | | Senior Vice President & CFO, Exelon Utilities | | 2018 - 2021 | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
ComEd | | | | | | | | | | | | | | | | | | | | | Name | | Age | | Position | | Period | Quiniones, Gil | | 56 | | | Chief Executive Officer, ComEd | | 2021 - Present | | | | | President and Chief Executive Officer, New York Power Authority | | 2011 - 2021 | | | | | | | | Donnelly, Terence R. | | 62 | | | President and Chief Operating Officer, ComEd | | 2018 - Present | | | | | | | | | | | | | | | Graham, Elisabeth J. | | 44 | | | Senior Vice President, Chief Financial Officer & Treasurer, ComEd | | 2022 - Present | | | | | Treasurer, Exelon | | 2018 - 2022 | | | | | | | | | | | | | | | Rippie, E. Glenn | | 62 | | | Senior Vice President and General Counsel, ComEd | | 2022 - Present | | | | | Senior Vice President and Deputy General Counsel, Energy Regulation, Exelon | | 2022 - Present | | | | | Partner, Jenner & Block LLP | | 2019 - 2021 | | | | | Partner and Chief Financial Officer, Rooney, Rippie & Ratnaswamy, LLP | | 2010 - 2019 | | | | | | | | Washington, Melissa | | 53 | | | Senior Vice President, Customer Operations, 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 | | | | | | | | Binswanger, Lewis | | 63 | | | Senior Vice President, Governmental, Regulatory and External Affairs, ComEd | | 2022 - Present | | | | | Vice President, External Affairs, Nicor Gas | | 2013 - 2022 | | | | | | | | | | | | | | | | | | | | | |
PECO | | | | | | | | | | | | | | | | | | | | | Name | | Age | | Position | | Period | Innocenzo, Michael A. | | 57 | | | President and Chief Executive Officer, PECO | | 2018 - Present | | | | | | | | | | | | | | | Levine, Nicole | | 46 | | | Senior Vice President and Chief Operations Officer, PECO | | 2022 - Present | | | | | Vice President, Electrical Operations, PECO | | 2018 - 2022 | Humphrey, Marissa | | 43 | | | Senior Vice President, Chief Financial Officer and Treasurer, PECO | | 2022 - Present | | | | | Vice President, Regulatory Policy and Strategy (NJ/DE), PHI, DPL, and ACE | | 2021 - 2022 | | | | | Vice President, Finance, Exelon Utilities | | 2019 - 2020 | | | | | Vice President, Financial Planning and Analysis, PHI, Pepco, DPL, and ACE | | 2016 - 2019 | | | | | | | | Murphy, Elizabeth A. | | 63 | | | Senior Vice President, Governmental, Regulatory and External Affairs, PECO | | 2016 - Present | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Williamson, Olufunmilayo | | 44 | | | Senior Vice President, Customer Operations, PECO | | 2021 - Present | | | | | Senior Vice President, Chief Commercial Risk Officer, Exelon | | 2017 - 2020 | | | | | | | | | | | | | | | Gay, Anthony | | 57 | | | 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. | | 48 | | | President, BGE | | 2021 - Present | | | | | Chief Executive Officer, BGE | | 2019 - Present | | | | | Senior Vice President & COO, Exelon Utilities | | 2018 - 2019 | | | | | | | | Dickens, Derrick | | 58 | | | Senior Vice President and Chief Operating Officer, BGE | | 2021 - Present | | | | | Senior Vice President, Customer Operations, PHI, Pepco, DPL, and ACE | | 2020 - 2021 | | | | | Vice President, Technical Services, BGE | | 2016 - 2020 | | | | | | | | | | | | | | | Vahos, David M. | | 50 | | | Senior Vice President, Chief Financial Officer and Treasurer, BGE | | 2016 - Present | | | | | | | | | | | | | | | Núñez, Alexander G. | | 51 | | | Senior Vice President, Governmental, Regulatory and External Affairs, BGE | | 2021 - Present | | | | | Senior Vice President, Regulatory Affairs and Strategy, BGE | | 2020 - 2021 | | | | | Senior Vice President, Regulatory and External Affairs, BGE | | 2016 - 2020 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Galambos, Denise | | 60 | | | Senior Vice President, Customer Operations, BGE | | 2021 - Present | | | | | Vice President, Utility Oversight, Exelon Utilities | | 2020 - 2021 | | | | | Vice President, Human Resources, BGE | | 2018 - 2020 | | | | | | | | | | | | | | | Ralph, David | | 56 | | | Vice President and General Counsel, BGE | | 2021 - Present | | | | | Associate General Counsel, BGE | | 2019 - 2021 | | | | | Assistant General Counsel, Exelon | | 2017 - 2019 | | | | | | | |
PHI, Pepco, DPL, and ACE | | | | | | | | | | | | | | | | | | | | | Name | | Age | | Position | | Period | Anthony, J. Tyler | | 58 | | | President and Chief Executive Officer, PHI, Pepco, DPL, and ACE | | 2021 - Present | | | | | Senior Vice President and Chief Operating Officer, PHI, Pepco, DPL, and ACE | | 2016 - 2021 | | | | | | | | Olivier, Tamla | | 50 | | | 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. | | 59 | | | Senior Vice President, Chief Financial Officer and Treasurer, PHI, Pepco, DPL, and ACE | | 2018 - Present | | | | | | | | | | | | | | | | | | | | | | Oddoye, Rodney | | 46 | | | Senior Vice President, Governmental, Regulatory and 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 | | | | | | | | | | | | | | | Bancroft, Anne | | 56 | | | Vice President and General Counsel, PHI, Pepco, DPL, and ACE | | 2021 - Present | | | | | Associate General Counsel, Exelon | | 2017 - 2021 | | | | | | | | | | | | | | | Bell-Izzard, Morlon | | 57 | | | Senior Vice President, Customer Operations, PHI, Pepco, DPL, and ACE | | 2021 - Present | | | | | Vice President, Customer Operations, PHI, Pepco, DPL, and ACE | | 2019 - 2021 | | | | | Director, Utility Performance Assessment, Exelon | | 2016 - 2019 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Each of the Registrants operates in a complex market and regulatory environment that any lossesinvolves 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, financial condition or liquidity/cash flows due to public health crises, epidemics or pandemics, such as 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 Constellation under the transaction agreements, including indemnification responsibilities. There may exceedbe further risks and uncertainties that are not presently known or that are not currently believed to be material that could negatively affect the amountRegistrants' 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 insurance maintained or are within the policy deductible for its insured losses. Such lossescustomer 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 a material adverse effectsignificant effects on Exelon’scustomer behaviors and Generation’s future financial statements.their energy consumption.
Decommissioning
NRC regulations require that licenseesThese developments could affect levels of nuclear generatingcustomer-owned generation, customer expectations, and current business models and make portions of the Utility Registrants' transmission and/or distribution facilities demonstrate reasonable assurance that funds will be available in specified minimum amounts atuneconomic prior to the end of their useful lives. Increasing pressure from both the lifeprivate and public sectors to take actions to mitigate climate change could also push the speed and nature of this transition. 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 facilityinvestments held within Exelon’s employee benefit plan trusts. The asset values are subject to decommissionmarket fluctuations and will yield uncertain returns, which could fall below Exelon's projected return rates. A decline in the facility. The ultimate decommissioning obligation will be funded by the NDTs. At December 31, 2019 the fairmarket value of NDTs exceeds the balancepension 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 Nuclear AROs.obligations related to the pension and OPEB plans. 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 214 — 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 ObligationsBenefits of the Combined Notes to Consolidated Financial Statements for additional information.
The Registrants could be negatively affected by unstable capital and Renewable Facilities (including Hydroelectric)credit markets (All Registrants). Generation wholly owns allThe 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 its fossilcapital and renewable generating stations, withliquidity 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 exception of: (1) Wyman; (2) certain wind project entitiescapital and credit markets because 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 biomass project entity with minority interest owners;reduction in dividend payments or other discretionary uses of cash. In addition, the Registrants have exposure to worldwide financial markets, including Europe, Canada, and (3) EGRP which is owned 49% by another owner. See Note 22 — Variable Interest EntitiesAsia. 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, 2022, approximately 23%, 10%, and 16% of the Combined Notes to Consolidated Financial Statements for additional information regarding EGRP which is a VIE. Generation’s fossilRegistrants’ available credit facilities were with European, Canadian, and renewable generating stations are all operated by Generation, with the exception of Wyman, which is operated by a third party. In 2019, 2018 and 2017, electric supply (in GWh) generated from owned fossil and renewable generating facilities was 11%, 11% and 12%, respectively, of Generation’s total electric supply. The majority of this output was dispatched to support Generation’s wholesale and retail power marketing activities. For additional information regarding Generation’s electric generating facilities, see ITEM 2. PROPERTIES.
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. BasedAsian banks, respectively. Additionally, higher interest rates may put pressure 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. The stations are currently being depreciated over their estimated useful lives, which include actualRegistrants’ overall liquidity profile, financial health and anticipated license renewal periods. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
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.impact financial results. See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on financingthe 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 and Cash Requirements — 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. Public health crises, epidemics, or pandemics, such as COVID-19 could negatively impact the Registrants' results (All Registrants). COVID-19 disrupted economic activity in the Registrants’ respective markets and negatively affected the Registrants’ results of operations in 2020. However, the financial impacts were not material for the years ended December 31, 2021 and December 31, 2022, other than the 2022 impairment disclosure within Note 11 — Asset Impairments. 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 our vendors, competitors or customers and customer demand as well as 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 7 — Property, Plant, and Equipment, Note 11 — Asset Impairments, and Note 12 — 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 Constellation, Constellation 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 Constellation as part of the restructuring. If the third-party, Constellation, 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 Constellation'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 if 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 electric and gas revenue and earnings 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, transmission, 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' respective terms and conditions of service, including their respective rates, along with adoption of new rate structures and constructs, or establishment of new rate cases, 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, adoption of new rate structures and constructs or establishment of new rate cases. 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. Generation maintains both property damageThese settlements are subject to regulatory approval. The ultimate outcome and liability insurance. For property damagetiming 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 liabilityNERC 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. 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 way 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 Generationconducted by predecessor companies are one component of such costs. Also, the Registrants are currently involved in several 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' earnings, if timely recovery is not allowed. 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 to estimate their obligations to taxing authorities, which includes general tax positions taken and associated reserves established. Tax obligations include, but are not limited to: income, real estate, sales and use, and employment-related taxes and ongoing appeal issues related to these tax matters. All tax estimates could be subject to challenge by the tax authorities. Additionally, earnings may be impacted due to changes in federal or local/state tax laws, and the inherent difficulty of estimating potential tax effects of ongoing business decisions. See Note 1 — Significant Accounting Policies and Note 13 — 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 18 — 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, or disrupt 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 18 — 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 U.S. 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 18 — 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). The Registrants periodically perform analyses to better understand long-term projections of climate change and how those changes in the physical environments where they operate could affect their facilities and operations. The Registrants primarily operate in the Midwest and Mid-Atlantic 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 at greater risk of damage as changes in the global climate affect temperature and weather patterns, or be placed at greater risk of damage should climate changes result in more intense, frequent and extreme weather events, elevated levels of precipitation, sea level rise, increased surface water temperatures, and/or other effects. Over time, the Registrants are making 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 are making additional investments to adapt to changes in operational requirements to manage demand changes and customer expectations caused by climate change. Climate Change risks include changes to the energy systems due to 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 energy system transition pathways to reduce 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 ITEM 1.A. "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 several 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, including sophisticated nation-state actors, 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. Additionally, the U.S. government has warned that the Ukraine conflict may increase the risks of attacks targeting critical infrastructure in the United States. A security breach of the Registrants' physical assets or information systems or those of the Registrants competitors, vendors, business partners and interconnected entities in RTOs and ISOs, or regulators could materially impact Registrants by, among other things, impairing the availability of electricity and gas distributed by Registrants and/or the reliability of transmission and distribution systems, impairing the availability of vendor services and materials that the Registrants rely on to maintain their operations, or by leading to the theft or inappropriate release of certain types of information, including critical infrastructure information, sensitive customer, vendor, or employee data, or other confidential data. The risk of these 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 material 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 security 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 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 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. 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 or be impacted by lack of availability of critical parts, 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. Additionally, if critical parts are not available, it may impact the timing of execution of capital projects. The Registrants' consolidated financial statements could be negatively affected if they were unable to effectively manage their capital projects or raise the necessary capital, or if they are deemed liable for operational failure. 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 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 as well as areas where new technologies are pertinent. The Registrants’ performance could be negatively affected by poor performance of third-party contractors that perform periodic or ongoing work (All Registrants). All Registrants rely on third-party contractors to perform operations, maintenance, and construction work. Performance standards typically are included in all contractual obligations, but poor performance may impact the capital execution plan or operations, or have adverse financial or reputational consequences. 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 and broader beneficial electrification. 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 Constellation, 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 Constellation will indemnify each other for certain liabilities. If Exelon is required to pay under these indemnities to Constellation, Exelon's financial results could be negatively impacted. The Constellation indemnities may not be sufficient to hold Exelon harmless from the full amount of liabilities for which Constellation will be allocated responsibility, and Constellation may not be able to satisfy its indemnification obligations in the future. Pursuant to the separation agreement and certain other agreements between Exelon and Constellation, 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 Constellation 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 Constellation 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 Constellation for Exelon's benefit may not be
sufficient to protect Exelon against the full amount of such liabilities, and Constellation may not be able to fully satisfy its indemnification obligations. Moreover, even if Exelon ultimately succeeds in recovering from Constellation 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.
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, 2022 were as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Voltage | Circuit Miles | (Volts) | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE | 765,000 | 90 | | — | | — | | — | | — | | — | 500,000(a) | — | | 188 | | 216 | | 109 | | 15 | | — | 345,000 | 2,678 | | — | | — | | — | | — | | — | 230,000 | — | | 550 | | 352 | | 770 | | 472 | | 272 | 138,000 | 2,257 | | 135 | | 55 | | 61 | | 586 | | 214 | 115,000 | — | | — | | 700 | | 25 | | — | | — | 69,000 | — | | 177 | | — | | — | | 567 | | 662 |
___________ (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 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 | | 12,965 | | 9,155 | | 4,130 | | 6,007 | | 7,345 | Underground | 32,684 | | 9,590 | | 17,927 | | 7,207 | | 6,513 | | 3,007 |
Gas The following table presents PECO’s, BGE’s, and DPL’s natural gas pipeline miles at December 31, 2022: | | | | | | | | | | | | | | | | | | | PECO | | BGE | | DPL | Transmission(a) | 9 | | 152 | | 8 | Distribution | 6,990 | | 7,527 | | 2,198 | Service piping | 6,479 | | 6,761 | | 1,486 | Total | 13,478 | | 14,440 | | 3,692 |
___________ (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 16 — 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. SuchAny such losses could have a material adverse effect on Exelon’s and Generation’s futurein the consolidated financial conditions and theircondition or results of operations of the Utility Registrants.
Exelon Security Measures The Registrants have initiated and cash flows.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 property insurance,material lawsuits and proceedings, see ITEM 2. PROPERTIESNote 3 — Exelon Generation Company, LLC.Regulatory Matters and Note 18 — 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
Contracted GenerationPART II
In(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, 2023, there were 994,126,931 shares of common stock outstanding and approximately 80,780 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, compared with the S&P 500 Stock Index and the S&P Utility Index, for the period 2018 through 2022. Cumulative total returns account for the separation of Constellation, as spin-off dividend is assumed to be reinvested as received. This performance chart assumes: •$100 invested on December 31, 2017 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, | | 2017 | 2018 | 2019 | 2020 | 2021 | 2022 | Exelon Corporation | $100.00 | $118.33 | $123.39 | $118.59 | $167.70 | $181.67 | S&P 500 | $100.00 | $95.62 | $125.72 | $148.85 | $191.58 | $156.88 | S&P Utilities | $100.00 | $104.11 | $131.54 | $132.18 | $155.53 | $157.97 |
ComEd As of January 31, 2023, there were 127,021,394 outstanding shares of common stock, $12.50 par value, of ComEd, of which 127,002,904 shares were indirectly held by Exelon. As of January 31, 2023, in addition to energy producedExelon, there were 283 record holders of ComEd common stock. There is no established market for shares of the common stock of ComEd. PECO As of January 31, 2023, there were 170,478,507 outstanding shares of common stock, without par value, of PECO, all of which were indirectly held by owned generation assets, Generation sources electricityExelon. BGE As of January 31, 2023, 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, 2023, Exelon indirectly held the entire membership interest in PHI. Pepco As of January 31, 2023, 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, 2023, 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, 2023, 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 plantsretained, 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 doesexercises 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 owndeclare 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 long-term contracts.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 by the MDPSC and DCPSC that prohibit Pepco from paying a dividend on its common shares if (a) after the dividend payment, Pepco's equity ratio would be below 48% as calculated pursuant to the MDPSC's and DCPSC's ratemaking precedents, 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 by the DEPSC and MDPSC that prohibit DPL from paying a dividend on its common shares if (a) after the dividend payment, DPL's equity ratio would be below 48% as calculated pursuant to the DEPSC's and MDPSC's ratemaking precedents, or (b) DPL’s corporate issuer or senior unsecured credit rating, or its equivalent, is rated by any of the three major credit rating agencies below the generally accepted definition of investment grade. No such event has occurred. ACE is subject to certain dividend restrictions established by settlements approved by the NJBPU that prohibit ACE from paying a dividend on its common shares if (a) after the dividend payment, ACE's common equity ratio would be below 48% as calculated pursuant to the NJBPU's ratemaking precedents, or (b) ACE's senior corporate issuer or 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 notify and 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 2023. 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 as2023 quarterly dividend will be $0.36 per share. As of December 31, 2019: | | | | | | | | | | 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 |
|
Fuel2022, Exelon had retained earnings of $4,597 million, ComEd had retained earnings of $2,030 million, PECO had retained earnings of $1,861 million, BGE had retained earnings of $2,075 million, and PHI had undistributed losses of $352 million.
The following table shows sourcessets forth Exelon’s quarterly cash dividends per share paid during 2022 and 2021: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2022 | | 2021 | (per share) | Fourth Quarter | | Third Quarter | | Second Quarter | | First Quarter | | Fourth Quarter | | Third Quarter | | Second Quarter | | First Quarter | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exelon | $ | 0.3375 | | | $ | 0.3375 | | | $ | 0.3375 | | | $ | 0.3375 | | | $ | 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: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2022 | | 2021 | (in millions) | 4th Quarter | | 3rd Quarter | | 2nd Quarter | | 1st Quarter | | 4th Quarter | | 3rd Quarter | | 2nd Quarter | | 1st Quarter | ComEd | 144 | | | 145 | | | 145 | | | 144 | | | 127 | | | 127 | | | 126 | | | 127 | | PECO | 100 | | | 99 | | | 100 | | | 100 | | | 85 | | | 85 | | | 84 | | | 85 | | BGE | 74 | | | 75 | | | 75 | | | 76 | | | 73 | | | 73 | | | 72 | | | 74 | | PHI | 125 | | | 230 | | | 293 | | | 102 | | | 98 | | | 191 | | | 333 | | | 81 | | Pepco | 63 | | | 100 | | | 258 | | | 42 | | | 47 | | | 98 | | | 95 | | | 28 | | DPL | 48 | | | 39 | | | 15 | | | 41 | | | 41 | | | 43 | | | 23 | | | 40 | | ACE | 17 | | | 90 | | | 19 | | | 19 | | | 8 | | | 51 | | | 215 | | | 14 | |
First Quarter 2023 Dividend On February 14, 2023, Exelon's Board of Directors declared a regular quarterly dividend of $0.36 per share on Exelon’s common stock for 2019 and 2018: the first quarter of 2023. The dividend is payable on Friday, March 10, 2023, to shareholders of record of Exelon as of 5 p.m. Eastern time on Monday, February 27, 2023. | | | | | | | | 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 |
|
39
__________
| | | | | | (a)ITEM 6. | 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.[RESERVED] |
| | | | | | (b)Item 7. | Includes wind, hydroelectric, solar and biomass generating assets.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
The cycle(Dollars in millions except per share data, unless otherwise noted)
Exelon Executive Overview Exelon is a utility services holding company engaged in the energy distribution and transmission businesses through ComEd, PECO, BGE, Pepco, DPL, and ACE. Exelon has six reportable segments consisting of productionComEd, PECO, BGE, Pepco, DPL, and utilizationACE. See Note 1 — Significant Accounting Policies and Note 5 — Segment Information of nuclear fuelthe Combined Notes to Consolidated Financial Statements for additional information regarding Exelon's principal subsidiaries and reportable segments. Exelon’s consolidated financial information includes the miningresults of its seven separate operating subsidiary registrants, ComEd, PECO, BGE, PHI, Pepco, DPL, and millingACE, which, along with Exelon, are collectively referred to as the Registrants. The following combined Management’s Discussion and Analysis of uranium ore into uranium concentrates, the conversionFinancial Condition and Results of uranium concentrates to uranium hexafluoride, the enrichmentOperations is separately filed by Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE. However, none of the uranium hexafluoride andRegistrants makes any representation as to information related solely to any of the fabricationother Registrants. For discussion 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 servicesUtility Registrants' year ended December 31, 2021 compared 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 monthsyear ended December 31, 2020, refer 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 in the 2021 Recast Form 10-K, which was filed with the SEC on June 30, 2022.
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. There were no material impacts to Exelon from unfavorable economic conditions due to COVID-19 for the years ended December 31, 2022 and 2021, other than the 2022 impairment discussed below. The Registrants assessed long-lived assets, goodwill, and investments for recoverability. Exelon and BGE recorded a pre-tax impairment charge of $48 million in 2022 as a result of COVID-19 impacts on office use. See Note 12 — Asset Impairments for additional information related to this impairment assessment. None of the other Registrants recorded material impairment charges in 2022 as a result of COVID-19. Additionally, there were no material impairment charges recorded in 2021 as a result of COVID-19. 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 from continuing operations and the Utility Registrants' Net income for the year ended December 31, 2022 compared to the same period in 2021. For additional information regarding the financial results for the years ended December 31, 2022 and 2021 see the discussions of Results of Operations by Registrant. | | | | | | | | | | | | | | | | | | | 2022 | | 2021 | | Favorable (Unfavorable) Variance | Exelon | 2,054 | | | 1,616 | | | $ | 438 | | ComEd | 917 | | | 742 | | | 175 | | PECO | 576 | | | 504 | | | 72 | | BGE | 380 | | | 408 | | | (28) | | PHI | 608 | | | 561 | | | 47 | | Pepco | 305 | | | 296 | | | 9 | | DPL | 169 | | | 128 | | | 41 | | ACE | 148 | | | 146 | | | 2 | | Other(a) | (427) | | | (599) | | | 172 | |
__________ (a)Primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities, and other financing and investing activities. The separation of Constellation Energy Corporation, including Generation and its subsidiaries, meets the criteria for discontinued operations and as such, Generation's results of operations are presented as discontinued operations and have been excluded from Exelon's continuing operations for all periods presented. See Note 1 — Significant Accounting Policies and Note 2 — Discontinued Operations for additional information. Accounting rules require that certain BSC costs previously allocated to Generation be presented as part of Exelon’s continuing operations as these costs do not qualify as expenses of the discontinued operations. Such costs are included in Other in the table above and were $28 million and $429 million on a pre-tax basis, for the years ended December 31, 2022 and 2021, respectively. Year Ended December 31, 2022 Compared to Year Ended December 31, 2021. Net income attributable to common shareholders from continuing operationsincreased by $438 million and diluted earnings per average common share from continuing operations increased to $2.08 in 2022 from $1.65 in 2021 primarily due to: •Higher electric distribution earnings and energy efficiency earnings from higher rate base and higher allowed ROE due to an increase in treasury rates at ComEd; •The favorable impacts of rate increases at PECO, BGE, and PHI; •Favorable impacts of decreased storm costs at PECO and BGE; and •Lower BSC costs presented in Exelon’s continuing operations, which were previously allocated to Generation but do not qualify as expenses of the discontinued operation per the accounting rules. The increases were partially offset by: •An income tax expense recorded in connection with the separation primarily due to the long-term marginal state income tax rate change, the recognition of valuation allowances against the net deferred tax assets positions for certain standalone state filing jurisdictions, and nondeductible transaction costs partially offset by a one-time impact associated with a state tax benefit; •An adjustment at PECO to exclude one-time non-cash impacts associated with the remeasurement of deferred income taxes as a result of the reduction in Pennsylvania corporate income tax rate;
•Higher depreciation expense at PECO, BGE, and PHI; •Higher credit loss expense at PECO, BGE, and PHI; •Higher storm costs at PHI; and •Higher interest expense at PECO, BGE, PHI, and Exelon Corporate. Adjusted (non-GAAP) Operating Earnings. In addition to Net income, Exelon evaluates its operating performance using the measure of Adjusted (non-GAAP) operating earnings because management believes it represents earnings directly related to the ongoing operations of the business. Adjusted (non-GAAP) operating earnings exclude certain costs, expenses, gains and losses, and other specified items. This information is intended to enhance an investor’s overall understanding of year-to-year operating results and provide an indication of Exelon’s baseline operating performance excluding items that are considered by management to be not directly related to the ongoing operations of the business. In addition, this information is among the primary indicators management uses as a basis for evaluating performance, allocating resources, setting incentive compensation targets, and planning and forecasting of future periods. Adjusted (non-GAAP) operating earnings is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.
The following table provides a reconciliation between Net income attributable to common shareholders from continuing operations as determined in accordance with GAAP and Adjusted (non-GAAP) operating earnings for the year ended December 31, 2022 compared to 2021: | | | | | | | | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | | 2022 | | 2021 | (In millions, except per share data) | | | Earnings per Diluted Share | | | | Earnings per Diluted Share | Net Income Attributable to Common Shareholders from Continuing Operations | $ | 2,054 | | | $ | 2.08 | | | $ | 1,616 | | | $ | 1.65 | | Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $1 and $3, respectively) | 4 | | | — | | | 4 | | | — | | Asset Impairments (net of taxes of $10)(a) | 38 | | | 0.04 | | | — | | | — | | Cost Management Program (net of taxes of $1)(b) | — | | | — | | | 6 | | | 0.01 | | Asset Retirement Obligation (net of taxes of $2 and $1, respectively) | (4) | | | — | | | 2 | | | — | | COVID-19 Direct Costs (net of taxes of $6)(c) | — | | | — | | | 14 | | | 0.01 | | | | | | | | | | Acquisition Related Costs (net of taxes of $5)(d) | — | | | — | | | 15 | | | 0.02 | | ERP System Implementation Costs (net of taxes of $0 and $4, respectively)(e) | 1 | | | — | | | 13 | | | 0.01 | | Separation Costs (net of taxes of $10 and $21, respectively)(f) | 24 | | | 0.02 | | | 58 | | | 0.06 | | Income Tax-Related Adjustments (entire amount represents tax expense)(g) | 122 | | | 0.12 | | | 62 | | | 0.06 | | Adjusted (non-GAAP) Operating Earnings | $ | 2,239 | | | $ | 2.27 | | | $ | 1,791 | | | $ | 1.83 | |
__________ 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. The marginal statutory income tax rates for 2022 and 2021 ranged from 24.0% to 29.0%.
(a)Reflects costs related to the impairment of an office building at BGE, which are recorded in Operating and maintenance expense. (b)Primarily represents reorganization costs related to cost management programs. (c)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, which are recorded in Operating and maintenance expense. (d)Reflects certain BSC costs related to the acquisition of EDF's interest in CENG, which was completed in the third quarter of 2021, that were historically allocated to Generation but are presented as part of continuing operations in Exelon's results as these costs do not qualify as expenses of the discontinued operations per the accounting rules. (e)Reflects costs related to a multi-year ERP system implementation, which are recorded in Operating and maintenance expense. (f)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 separation, and employee-related severance costs, which are recorded in Operating and maintenance expense. (g)In 2021, for PHI, 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, for Corporate, reflects the adjustment to deferred income taxes due to changes in forecasted apportionment. In 2022, for PECO, primarily reflects an adjustment to exclude one-time non-cash impacts associated with the remeasurement of deferred income taxes as a result of the reduction in Pennsylvania corporate income tax rate. In 2022, for Corporate, in connection with the separation, Exelon recorded an income tax expense primarily due to the long-term marginal state income tax rate change, the recognition of valuation allowances against the deferred tax assets positions for certain standalone state filing jurisdictions, and nondeductible transaction costs partially offset by a one-time impact associated with a state tax benefit.
Significant 2022 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 (“the separation”). Exelon completed the separation on February 1, 2022. Constellation was newly formed and incorporated in Pennsylvania on June 15, 2021 for the purpose of separation and holds Generation. The separation represented a strategic shift that would have a major effect on Exelon’s operations and financial results. Accordingly, the separation meets the criteria for discontinued operations. See Note 2 — Discontinued Operations of the Combined Notes to Consolidated Financial Statements for additional information on the separation and discontinued operations. In connection with the separation, Exelon incurred separation costs impacting continuing operations of $34 million and $79 million on a pre-tax basis for the year ended December 31, 2022 and 2021, respectively, which are recorded in Operating and maintenance expense. These costs are excluded from Adjusted (non-GAAP) Operating Earnings. The separation 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. Equity Securities Offering On August 4, 2022, Exelon entered into an agreement with certain underwriters in connection with an underwritten public offering of 12.995 million shares of its common stock, no par value. The net proceeds were $563 million before expenses paid by Exelon. See Note 19 — Shareholders' Equity 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 2022. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on these and other regulatory proceedings.
Completed Distribution Base Rate Case Proceedings | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Registrant/Jurisdiction | | Filing Date | | Service | | Requested Revenue Requirement Increase | | Approved Revenue Requirement Increase | | Approved ROE | | Approval Date | | Rate Effective Date | ComEd - Illinois | | April 16, 2021 | | Electric | | $ | 51 | | | $ | 46 | | | 7.36 | % | | December 1, 2021 | | January 1, 2022 | | April 15, 2022 | | Electric | | 199 | | | 199 | | | 7.85 | % | | November 17, 2022 | | January 1, 2023 | PECO - Pennsylvania | | March 30, 2021 | | Electric | | 246 | | | 132 | | | N/A | | November 18, 2021 | | January 1, 2022 | | March 31, 2022 | | Natural Gas | | 82 | | | 55 | | | | October 27, 2022 | | January 1, 2023 | BGE - Maryland | | May 15, 2020 (amended September 11, 2020) | | Electric | | 203 | | | 140 | | | 9.50 | % | | December 16, 2020 | | January 1, 2021 | | | Natural Gas | | 108 | | | 74 | | | 9.65 | % | | | Pepco - District of Columbia | | May 30, 2019 (amended June 1, 2020) | | Electric | | 136 | | | 109 | | | 9.275 | % | | June 8, 2021 | | July 1, 2021 | Pepco - Maryland | | October 26, 2020 (amended March 31, 2021) | | Electric | | 104 | | | 52 | | | 9.55 | % | | June 28, 2021 | | June 28, 2021 | DPL - Maryland | | September 1, 2021 (amended December 23, 2021) | | Electric | | 27 | | | 13 | | | 9.60 | % | | March 2, 2022 | | March 2, 2022 | | May 19, 2022 | | Electric | | 38 | | | 29 | | | 9.60 | % | | December 14, 2022 | | January 1, 2023 | DPL - Delaware | | January 14, 2022 (amended August 15, 2022) | | Natural Gas | | 13 | | | 8 | | | 9.60 | % | | October 12, 2022 | | August 14, 2022 | ACE - New Jersey | | December 9, 2020 (amended February 26, 2021) | | Electric | | 67 | | | 41 | | | 9.60 | % | | July 14, 2021 | | January 1, 2022 |
Pending Distribution Base Rate Case Proceedings | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Registrant/Jurisdiction | | Filing Date | | Service | | Requested Revenue Requirement Increase | | Requested ROE | | Expected Approval Timing | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ComEd - Illinois | | January 17, 2023 | | Electric | | $ | 1,472 | | | 10.50% to 10.65% | | Fourth quarter of 2023 | DPL - Delaware | | December 15, 2022 | | Electric | | 60 | | | 10.50 | % | | Second quarter of 2024 | | | | | | | | | | | | | | | | | | | | | | |
Transmission Formula Rates The following total increases/(decreases) were included in the Utility Registrants' 2022 annual electric transmission formula rate updates. All rates are effective June 1, 2022 to May 31, 2023, subject to review by interested parties pursuant to review protocols of each Utility Registrants' tariff. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Registrant | | Initial Revenue Requirement Increase | | Annual Reconciliation (Decrease) Increase | | Total Revenue Requirement Increase | | Allowed Return on Rate Base | | Allowed ROE | ComEd | | $ | 24 | | | $ | (24) | | | $ | — | | | 8.11 | % | | 11.50 | % | PECO | | 23 | | | 16 | | | 39 | | | 7.30 | % | | 10.35 | % | BGE | | 25 | | | (4) | | | 16 | | | 7.30 | % | | 10.50 | % | Pepco | | 16 | | | 15 | | | 31 | | | 7.60 | % | | 10.50 | % | DPL | | 9 | | | 2 | | | 11 | | | 7.09 | % | | 10.50 | % | ACE | | 21 | | | 13 | | | 34 | | | 7.18 | % | | 10.50 | % |
Pennsylvania Corporate Income Tax Rate Change On July 8, 2022, Pennsylvania enacted House Bill 1342, which will permanently reduce the corporate income tax rate from 9.99% to 4.99%. The tax rate will be reduced to 8.99% for the 2023 tax year. Starting with the 2024 tax year, the rate is reduced by 0.50% annually until it reaches 4.99% in 2031. As a result of the rate change, in the third quarter of 2022, Exelon and PECO recorded a one-time decrease to deferred income taxes of $390 million with a corresponding decrease to the deferred income taxes regulatory asset of $428 million for the amounts that are expected to be settled through future customer rates and an increase to income tax expense of $38 million (net of federal taxes), which was excluded from Exelon's Adjusted (non-GAAP) Operating Earnings. The tax rate decrease is not expected to have a material ongoing impact to Exelon’s and PECO’s financial statements. See Note 13 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information. Inflation Reduction Act On August 16, 2022, the Inflation Reduction Act (IRA) was signed into law. The bill extends tax benefits for renewable technologies like solar and wind, and it creates new tax benefits for alternative clean energy sources like nuclear and hydrogen and it focuses on energy efficiency, electrification, and equity. However, the bill also implements a new 15.0% corporate minimum tax based on modified GAAP net income. Exelon estimates the IRA could result in an increase in cash taxes for Exelon of approximately $200 million per year starting in 2023. Exelon is continuing to assess the impacts of the IRA on the financial statements and will update estimates based on guidance to be issued by the U.S. Treasury in the future. Asset Impairment In the third quarter of 2022, a review of the impacts of COVID-19 on office use resulted in plans to cease the renovation and dispose of an office building at BGE before the asset was placed into service. BGE determined that the carrying value was not recoverable and that its fair value was less than carrying value. As a result, Exelon and BGE recorded a pre-tax impairment charge of $48 million in 2022, which was excluded from Exelon's Adjusted (non-GAAP) Operating Earnings. See Note 11 — Asset Impairments of the Combined Notes to Consolidated Financial Statements for additional information. ComEd's FERC Audit The Registrants are subject to periodic audits and investigations by FERC. FERC’s Division of Audits and Accounting initiated a nonpublic audit of ComEd in May 2021 evaluating ComEd’s compliance with (1) approved terms, rates and conditions of its transmission formula rate mechanism; (2) accounting requirements of the Uniform System of Accounts; (3) reporting requirements of the FERC Form 1; and (4) the requirements for record retention. The audit covered the period from January 1, 2017 through August 31, 2022. On January 17, 2023, ComEd was provided with information on a series of potential findings, including concerning ComEd's
methodology regarding the allocation of certain overhead costs to capital under FERC regulations. The final outcome and resolution of the findings or of the audit itself cannot be predicted and the results, while not reasonably estimable at this time, could be material to the Exelon and ComEd financial statements. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. 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 City of Chicago Franchise Agreement The current ComEd Franchise Agreement with the City of Chicago (the City) has been in force 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 become effective. 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. 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. However, the City did not proceed to issue an RFP. Since that time, ComEd and the City continued to negotiate and have arrived at a proposed Chicago Franchise Agreement (CFA) and an Energy and Equity Agreement (EEA). These agreements together are intended to grant ComEd the right to continue providing electric utility services using public ways within the City of Chicago, and to create a new non-profit entity to advance energy and energy-related equity projects. On February 1, 2023, the proposed CFA and EEA were introduced to the City Council. The proposed CFA and EEA remain subject to approval by the City Council and the Exelon Board. While Exelon and ComEd cannot predict the ultimate outcome of these processes, fundamental changes in the agreements 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. Infrastructure Investment and Jobs Act On November 15, 2021, President Biden signed the $1.2 trillion Infrastructure Investment and Jobs Act (IIJA) into law. IIJA provides for approximately $550 billion in new federal spending. Categories of funding include funding for a variety of infrastructure needs, including but not limited to: (1) power and grid reliability and resilience, (2) resilience for cybersecurity to address critical infrastructure needs, and (3) electric vehicle charging infrastructure for alternative fuel corridors. Federal agencies are developing guidelines to implement spending programs under IIJA. The time needed to develop these guidelines will vary with some limited program applications opened as early as the first quarter of 2022. The Registrants are continuing to analyze the legislation and considering possible opportunities to apply for funding, either directly or in potential collaborations with state and/or local
agencies and key stakeholders. The Registrants cannot predict the ultimate timing and success of securing funding from programs under IIJA. ComEd and BGE applied for the Middle Mile Grant (MMG), which establishes and funds construction, improvement, or acquisition of middle mile broadband infrastructure which creates high-speed internet services. The MMG addresses inequitable broadband access by expansion and extension of the middle mile infrastructure in underserved communities. ComEd and BGE cannot predict if their applications will be approved as filed or the timing of receiving any funds if they are awarded a grant. In December 2022, Exelon and the Utility Registrants submitted 14 concept papers in response to the Department of Energy's Grid Resilience and Innovation Partnership (GRIP) program. These concept papers are focused on delivering grid resilience and grid benefits to customers and communities across the Exelon footprint. Eleven of the fourteen opportunities received letters of encouragement to submit applications due in the first half of 2023. Exelon cannot predict if their applications will be approved as filed or the timing of receiving any funds if they are awarded a grant. Exelon and the Utility Registrants are supporting three different Regional Clean Hydrogen Hub opportunities, covering all five states that Exelon operates in plus Washington D.C., that have submitted concept papers to the Department of Energy. All three opportunities have received letters of encouragement from Department of Energy to submit applications due in April 2023. The program will create networks of hydrogen producers, consumers, and local connective infrastructure to accelerate the use of hydrogen as a clean energy carrier that can deliver or store energy. Exelon cannot predict if their applications will be approved as filed or the timing of receiving any funds if they are awarded a grant. 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. Goodwill (Exelon, ComEd, and PHI) As of December 31, 2022, Exelon’s $6.6 billion carrying amount of goodwill consists 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 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, 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 2022 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 12 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information. Unamortized Energy Contract Liabilities (Exelon and PHI) Unamortized energy contract liabilities represent the remaining unamortized balances of non-derivative electricity contracts that 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. Offsetting regulatory assets were also recorded for those energy contract costs that are probable of recovery through customer rates. The unamortized energy contract liabilities and the corresponding regulatory assets, 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 liabilities are recorded through purchased power and fuel expense. See Note 3 — Regulatory Matters and Note 12 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information. Depreciable Lives of Property, Plant, and Equipment (All Registrants) The Registrants have significant investments in electric and natural gas transmission and distribution assets. These assets are generally depreciated on a straight-line basis, using the group, or composite 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 regulatory action, or changes in retirement patterns indicate an update is necessary. Depreciation studies generally serve as the basis for amounts allowed in customer rates for recovery of depreciation costs. Generally, the 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. Changes in estimated useful lives 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. Retirement 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 2022 cost: | | | | | | | | | | | | Discount rate(a) | 3.24% | | 3.20% | | 0.5% | | $ | (16) | | | $ | (2) | | | $ | (18) | | | 3.24% | | 3.20% | | (0.5)% | | 31 | | | 7 | | | 38 | | EROA | 7.00% | | 6.44% | | 0.5% | | (54) | | | (7) | | | (61) | | | 7.00% | | 6.44% | | (0.5)% | | 54 | | | 7 | | | 61 | | Change in benefit obligation at December 31, 2022: | | | | | | | | | | | | Discount rate(a) | 5.53% | | 5.51% | | 0.5% | | (508) | | | (83) | | | (591) | | | 5.53% | | 5.51% | | (0.5)% | | 655 | | | 104 | | | 759 | |
__________ (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 14 — 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) as of December 31, 2022: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (In millions) | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Gain (loss) | $ | 2,461 | | | $ | 3,697 | | | $ | (387) | | | $ | 159 | | | $ | (978) | | | $ | (211) | | | $ | 142 | | | $ | (442) | | Charge against OCI(a) | (2,590) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
___________ (a)Exelon's charge against OCI (before taxes) consists of up to $1.9 billion, $347 million, $492 million, $279 million, $113 million, and $59 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 $115 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. Derivative Financial Instruments (All Registrants) The Registrants use derivative instruments to manage commodity price risk and interest rate risk related to ongoing business operations. See Note 15 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information. 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. All derivatives are recognized on the balance sheet at their fair value, except for certain derivatives that qualify for, and are elected under, NPNS. For derivatives that qualify and are designated as cash flow hedges, changes in fair value each period are initially recorded in AOCI and recognized in earnings when the hedged transaction
affects earnings. For derivatives intended to serve as economic hedges, which are not designated for hedge accounting, changes in fair value each period are recognized in earnings on the Consolidated Statement of Operations and Comprehensive Income or are recorded as a regulatory asset or liability when there is an ability to recover or return the associated costs or benefits in accordance with regulatory requirements. NPNS. Contracts that are designated as NPNS are not required to be recorded at fair value, but rather on an accrual basis of accounting. Determining whether a contract qualifies for NPNS requires judgment on whether the contract will physically deliver and requires that management ensure compliance with all the associated qualification and documentation requirements. For all NPNS derivative instruments, accounts payable is recorded when derivatives settle and expense is recognized in earnings as the underlying physical commodity is consumed. Contracts that qualify for 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 NPNS. Commodity Contracts. The Registrants make estimates and assumptions concerning future commodity prices, interest rates, and the timing of future transactions and their probable cash flows in deciding whether to enter derivative transactions, and in determining the initial accounting treatment for derivative transactions. The Registrants categorize these derivatives under a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. Derivative contracts can be 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. For derivatives that trade in liquid markets, 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 the assessment of nonperformance risk. The impacts of nonperformance and credit risk to date have generally not been material to the Registrants’ financial statements. Interest Rate Derivative Instruments. Exelon Corporate utilizes interest rate swaps to manage interest rate risk on existing and planned future debt issuances as well as potential fluctuations in Electric operating revenues at the corporate level in consolidation, which are directly correlated to yields on U.S. Treasury bonds under ComEd's distribution formula rate. The fair value of the swaps is calculated by discounting the future net cash flows to the present value based on the terms and conditions of the agreements and the forward interest rate curves. As these inputs are based on observable data and valuations of similar instruments, the interest rate derivatives are primarily categorized in Level 2 in the fair value hierarchy. 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 Statements for additional information regarding the Registrants’ derivative financial instruments. Power MarketingIncome Taxes (All Registrants)
Generation’s integrated business operations include physical deliverySignificant 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 marketingliabilities 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 power. Generation largely obtains physical power supply from its ownedtax benefit that is greater than 50% likely of being realized upon ultimate settlement. Management evaluates each position based solely on the technical merits and contracted generation in multiple geographic regions. Thefacts 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 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, 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. 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. Revenues (All Registrants) Sources of Revenue and Determination of Accounting Treatment. The Registrants earn revenues from the sale and delivery of power and natural gas in regulated markets. 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, and Alternative Revenue Program accounting guidance to recognize revenues 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 and natural gas are physically delivered to the customer. Transactions of the Registrants within the scope of Revenue from Contracts with Customers generally include sales to utility customers under regulated service tariffs.
The determination of the Registrants' 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 Registrant’s 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 risksrevenues 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. Alternative Revenue Program Accounting. Certain of the 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 Registrants’ formula rate mechanisms and revenue decoupling mechanisms, the 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 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) The 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 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. The Registrants' customer accounts are written off consistent with approved regulatory requirements. The 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 Results of Operations—ComEd | | | | | | | | | | | | | | | | | | | 2022 | | 2021 | | (Unfavorable) Favorable Variance | Operating revenues | $ | 5,761 | | | $ | 6,406 | | | $ | (645) | | | | | | | | | | | | | | Operating expenses | | | | | | Purchased power | 1,109 | | | 2,271 | | | 1,162 | | Operating and maintenance | 1,412 | | | 1,355 | | | (57) | | Depreciation and amortization | 1,323 | | | 1,205 | | | (118) | | Taxes other than income taxes | 374 | | | 320 | | | (54) | | Total operating expenses | 4,218 | | | 5,151 | | | 933 | | Gain on sales of assets | (2) | | | — | | | (2) | | Operating income | 1,541 | | | 1,255 | | | 286 | | Other income and (deductions) | | | | | | Interest expense, net | (414) | | | (389) | | | (25) | | Other, net | 54 | | | 48 | | | 6 | | Total other income and (deductions) | (360) | | | (341) | | | (19) | | Income before income taxes | 1,181 | | | 914 | | | 267 | | Income taxes | 264 | | | 172 | | | (92) | | Net income | $ | 917 | | | $ | 742 | | | $ | 175 | |
Year Ended December 31, 2022 Compared to Year Ended December 31, 2021.Net income increased by $175 million primarily due to increases in electric distribution and energy efficiency formula rate earnings (reflecting higher allowed ROE due to an increase in U.S. Treasury rates and the impacts of higher rate base). The changes in Operating revenues consisted of the following: | | | | | | | 2022 vs. 2021 | | Increase (Decrease) | Distribution | $ | 310 | | Transmission | 65 | | Energy efficiency | 65 | | Other | 12 | | 452 | | Regulatory required programs | (1,097) | | Total decrease | $ | (645) | |
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, 2022, compared to the same period in 2021, due to higher allowed ROE due to an increase in U.S. Treasury rates, the impact of a higher rate base, and higher fully recoverable costs.
Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered, and the highest daily peak load, which is updated annually in January based on the prior calendar year. Generally, increases/decreases in the highest daily peak load will result in higher/lower transmission revenue. Transmission revenues increased during the year ended December 31, 2022, compared to the same period in 2021, primarily due to the impact of a higher rate base and higher fully recoverable costs. Energy Efficiency Revenue. FEJA provides for a performance-based formula rate, which requires an annual reconciliation of the revenue requirement in effect to the actual costs that the ICC determines are prudently and reasonably incurred in a given year. 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, 2022, compared to the same period in 2021, primarily due to higher allowed ROE due to an increase in U.S. Treasury rates, the impact of a higher rate base, and increased regulatory asset amortization, which is fully recoverable. Other Revenue primarily includes assistance provided to other utilities through mutual assistance programs. Other revenue increased for the year ended December 31, 2022, compared to the same period in 2021, 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, ETAC, and costs related to electricity, ZEC, CMC, and REC procurement. See Note 3 - Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information regarding CMCs. ETAC is a retail customer surcharge collected by electric utilities operating in Illinois established by CEJA and remitted to an Illinois state agency for programs to support clean energy jobs and training. The riders are designed to provide full and current cost recovery. The costs of these programs are included in Purchased power expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries as ComEd remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation from competitive suppliers, ComEd either acts as the billing agent or the competitive supplier separately bills its own customers, and therefore does not record Operating revenues or Purchased power expense related to the electricity. For customers that choose to purchase electric generation from ComEd, ComEd is permitted to recover the electricity, ZEC, CMC, and REC procurement costs without mark-up and therefore records equal and offsetting amounts in Operating revenues and Purchased power expense related to the electricity, ZECs, CMCs, and RECs. See Note 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ComEd's revenue disaggregation. The decrease of $1,162 million for the year ended December 31, 2022, compared to the same period in 2021, in Purchased power expense is primarily due to the CMCs from the participating nuclear-powered generating facilities. This favorability is offset by a decrease in Operating revenues as part of regulatory required programs. See Note 3 - Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information regarding CMCs.
The changes in Operating and maintenance expense consisted of the following: | | | | | | | | | 2022 vs. 2021 | | | | Increase (Decrease) | | | Labor, other benefits, contracting, and materials | $ | 57 | | | | Storm-related costs | 13 | | | | BSC Costs | 13 | | | | Pension and non-pension postretirement benefits expense | (30) | | | | Other | 5 | | | | | 58 | | | | Regulatory required programs(a) | (1) | | | | Total increase | $ | 57 | | | | | | | | | | | | | | | | | | | |
__________ (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 changes in Depreciation and amortization expense consisted of the following: | | | | | | | | | 2022 vs. 2021 | | | | Increase | | | Depreciation and amortization(a) | $ | 63 | | | | Regulatory asset amortization(b) | 55 | | | | | | | | Total increase | $ | 118 | | | |
__________ (a)Reflects ongoing capital expenditures. (b)Includes amortization of ComEd's energy efficiency formula rate regulatory asset.
Taxes other than income taxes increased by $54 million for the year December 31, 2022, compared to the same period in 2021, primarily due to taxes related to ETAC, which is recovered through Operating revenues. Interest expense, net increased $25 million for the year ended December 31, 2022, compared to the same period in 2021, primarily due to the issuance of debt in 2021 and 2022. Effective income tax rateswere 22.4%and 18.8% for the years ended December 31, 2022and2021, 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 | | | | | | | | | | | | | | | | | | | 2022 | | 2021 | | Favorable (Unfavorable) Variance | Operating revenues | $ | 3,903 | | | $ | 3,198 | | | $ | 705 | | Operating expenses | | | | | | Purchased power and fuel | 1,535 | | | 1,081 | | | (454) | | Operating and maintenance | 992 | | | 934 | | | (58) | | Depreciation and amortization | 373 | | | 348 | | | (25) | | Taxes other than income taxes | 202 | | | 184 | | | (18) | | Total operating expenses | 3,102 | | | 2,547 | | | (555) | | | | | | | | Operating income | 801 | | | 651 | | | 150 | | Other income and (deductions) | | | | | | Interest expense, net | (177) | | | (161) | | | (16) | | Other, net | 31 | | | 26 | | | 5 | | Total other income and (deductions) | (146) | | | (135) | | | (11) | | Income before income taxes | 655 | | | 516 | | | 139 | | Income taxes | 79 | | | 12 | | | (67) | | | | | | | | | | | | | | Net income | $ | 576 | | | $ | 504 | | | $ | 72 | |
Year Ended December 31, 2022 Compared to Year Ended December 31, 2021.Net income increased by $72 million, primarily due to increases in electric and gas distribution rates and a decrease in storm costs, partially offset by the one-time non-cash impacts associated with the outputPennsylvania corporate income tax legislation passed in July 2022, and increases in depreciation expense, credit loss expense, and interest expense. The changes in Operating revenues consisted of the following: | | | | | | | | | | | | | | | | | | | 2022 vs. 2021 | | Increase (Decrease) | | Electric | | Gas | | Total | Weather | $ | 32 | | | $ | 10 | | | $ | 42 | | Volume | (21) | | | 8 | | | (13) | | Pricing | 138 | | | 25 | | | 163 | | Transmission | 15 | | | — | | | 15 | | Other | 15 | | | 6 | | | 21 | | | 179 | | | 49 | | | 228 | | Regulatory required programs | 327 | | | 150 | | | 477 | | Total increase | $ | 506 | | | $ | 199 | | | $ | 705 | |
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, 2022 compared to the same period in 2021, 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, 2022 compared to the same period in 2021 and normal weather consisted of the following:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | | | | % Change | PECO Service Territory | 2022 | | 2021 | | Normal | | 2022 vs. 2021 | | 2022 vs. Normal | Heating Degree-Days | 4,135 | | | 3,946 | | | 4,408 | | | 4.8 | % | | (6.2) | % | Cooling Degree-Days | 1,743 | | | 1,586 | | | 1,443 | | | 9.9 | % | | 20.8 | % |
Volume. Electric volume, exclusive of the effects of weather, for the year ended December 31, 2022 compared to the same period in 2021, decreased due to unfavorable load change. Natural gas volume for the year ended December 31, 2022 compared to the same period in 2021, increased due to favorable load change. | | | | | | | | | | | | | | | | | | | | | | | | Electric Retail Deliveries to Customers (in GWhs) | 2022 | | 2021 | | % Change | | Weather - Normal % Change(b) | Residential | 14,379 | | | 14,262 | | | 0.8 | % | | (1.8) | % | Small commercial & industrial | 7,701 | | | 7,597 | | | 1.4 | % | | 0.4 | % | Large commercial & industrial | 14,046 | | | 14,003 | | | 0.3 | % | | — | % | Public authorities & electric railroads | 638 | | | 559 | | | 14.1 | % | | 14.1 | % | Total electric retail deliveries(a) | 36,764 | | | 36,421 | | | 0.9 | % | | (0.4) | % |
__________ (a)Reflects delivery volumes from ownedcustomers purchasing electricity directly from PECO and contractedcustomers purchasing electricity from a competitive electric generation is managed using various commodity transactions including salessupplier 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 | 2022 | | 2021 | Residential | 1,525,635 | | | 1,517,806 | | Small commercial & industrial | 155,576 | | | 155,308 | | Large commercial & industrial | 3,121 | | | 3,107 | | Public authorities & electric railroads | 10,393 | | | 10,306 | | Total | 1,694,725 | | | 1,686,527 | |
| | | | | | | | | | | | | | | | | | | | | | | | Natural Gas Deliveries to customers (in mmcf) | 2022 | | 2021 | | % Change | | Weather - Normal % Change(b) | Residential | 42,135 | | | 39,580 | | | 6.5 | % | | 3.0 | % | Small commercial & industrial | 23,449 | | | 21,361 | | | 9.8 | % | | 6.0 | % | Large commercial & industrial | 31 | | | 34 | | | (8.8) | % | | 12.3 | % | Transportation | 25,011 | | | 25,081 | | | (0.3) | % | | (1.8) | % | Total natural gas deliveries(a) | 90,626 | | | 86,056 | | | 5.3 | % | | 2.4 | % |
__________ (a)Reflects delivery volumes from customers purchasing natural gas directly from PECO and customers purchasing electricity 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.
| | | | | | | | | | | | | As of December 31, | Number of Gas Customers | 2022 | | 2021 | Residential | 502,944 | | | 497,873 | | Small commercial & industrial | 44,957 | | | 44,815 | | Large commercial & industrial | 9 | | | 6 | | Transportation | 655 | | | 670 | | Total | 548,565 | | | 543,364 | |
Pricing for the year ended December 31, 2022 compared to the same period in 2021 increased primarily due to increases in electric and gas distribution rates charged to customers.
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, 2022 compared to the same period in 2021, increased primarily due to revenue related to late payment charges. Regulatory Required Programs represents revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency, PGC, and the GSA. The main objectiveriders 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 obtain low-cost energy supplypurchase 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 meet physical delivery obligationsthe electricity and/or natural gas. For customers that choose to both wholesale and retail customers. Generation sellspurchase 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 $454 million for the year ended December 31, 2022, compared to the same period in 2021, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs. The changes in Operating and maintenance expense consisted of the following: | | | | | | | | 2022 vs. 2021 | | | (Decrease) Increase | | Storm-related costs | $ | (34) | | | Pension and non-pension postretirement benefits expense | (9) | | | Credit loss expense | 6 | | | Labor, other benefits, contracting, and materials | 20 | | | BSC costs | 29 | | | Other(a) | 30 | | | | 42 | | | Regulatory Required Programs | 16 | | | Total increase | $ | 58 | | | __________(a) Primarily reflects an increase in charitable contributions. The changes in Depreciation and amortization expense consisted of the following: | | | | | | | 2022 vs. 2021 | | Increase | Depreciation and amortization(a) | $ | 24 | | Regulatory asset amortization | 1 | | Total increase | $ | 25 | |
__________ (a)Depreciation and amortization expense increased primarily due to ongoing capital expenditures.
Taxes other than income taxes increased by $18 million for the year ended December 31, 2022, compared to the same period in 2021, primarily due to higher Pennsylvania gross receipts tax, which is offset in Operating revenues, and offset by lower Pennsylvania use tax. Interest expense, net increased $16 million for the year ended December 31, 2022, compared to the same period in 2021, primarily due to the issuance of debt in 2021 and 2022 and increases in interest rates. Effective income tax rates were 12.1% and 2.3% for the years ended December 31, 2022 and 2021, respectively. The change in effective tax rate is primarily related to the one-time non-cash impacts associated with the Pennsylvania corporate income tax legislation passed in July 2022. 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—BGE | | | | | | | | | | | | | | | | | | | | | | | 2022 | | 2021 | | Favorable (Unfavorable) Variance | | | | | Operating revenues | $ | 3,895 | | | $ | 3,341 | | | $ | 554 | | | | | | Operating expenses | | | | | | | | | | Purchased power and fuel | 1,567 | | | 1,175 | | | (392) | | | | | | Operating and maintenance | 877 | | | 811 | | | (66) | | | | | | Depreciation and amortization | 630 | | | 591 | | | (39) | | | | | | Taxes other than income taxes | 302 | | | 283 | | | (19) | | | | | | Total operating expenses | 3,376 | | | 2,860 | | | (516) | | | | | | | | | | | | | | | | Operating income | 519 | | | 481 | | | 38 | | | | | | Other income and (deductions) | | | | | | | | | | Interest expense, net | (152) | | | (138) | | | (14) | | | | | | Other, net | 21 | | | 30 | | | (9) | | | | | | Total other income and (deductions) | (131) | | | (108) | | | (23) | | | | | | Income before income taxes | 388 | | | 373 | | | 15 | | | | | | Income taxes | 8 | | | (35) | | | (43) | | | | | | Net income | $ | 380 | | | $ | 408 | | | $ | (28) | | | | | | | | | | | | | | | |
Year Ended December 31, 2022 Compared to Year Ended December 31, 2021.Net income decreased $28 million primarily due to an asset impairment in 2022 and an increase in depreciation expense, credit loss expense, and interest expense, partially offset by favorable impacts of the multi-year plans and a decrease in storm costs. See Note 11 — Asset Impairments for additional information on the asset impairment. The changes in Operating revenues consisted of the following: | | | | | | | | | | | | | | | | | | | | | | | | | 2022 vs. 2021 | | | | Increase | | | | Electric | | Gas | | Total | | | | | | | Distribution | $ | 70 | | | $ | 27 | | | $ | 97 | | | | | | | | Transmission | 14 | | | — | | | 14 | | | | | | | | Other | 10 | | | 10 | | | 20 | | | | | | | | | 94 | | | 37 | | | 131 | | | | | | | | Regulatory required programs | 272 | | | 151 | | | 423 | | | | | | | | Total increase | $ | 366 | | | $ | 188 | | | $ | 554 | | | | | | | |
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 | 2022 | | 2021 | | | Residential | 1,204,429 | | | 1,195,929 | | | | Small commercial & industrial | 115,524 | | | 115,049 | | | | Large commercial & industrial | 12,839 | | | 12,637 | | | | Public authorities & electric railroads | 266 | | | 268 | | | | Total | 1,333,058 | | | 1,323,883 | | | |
| | | | | | | | | | | | | | | As of December 31, | | | Number of Gas Customers | 2022 | | 2021 | | | Residential | 655,373 | | | 651,589 | | | | Small commercial & industrial | 38,207 | | | 38,300 | | | | Large commercial & industrial | 6,233 | | | 6,179 | | | | Total | 699,813 | | | 696,068 | | | |
Distribution Revenue increased for the year ended December 31, 2022 compared to the same period in 2021, due to favorable impacts of the multi-year plans. Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue increased for the year ended December 31, 2022 compared to the same period in 2021 primarily due to 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, 2022 compared to the same period in 2021, primarily due to an increase in late fees charged to customers. Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as conservation, demand response, STRIDE, and the POLR mechanism. The riders are designed to provide full and current cost recovery, as well as a return in certain instances. The costs of these programs are included in Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers. Customer choice programs do not impact the volume of deliveries as BGE remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation or natural gas from competitive suppliers, BGE 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 $392 million for the year ended December 31, 2022 compared to the same period in 2021 in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.
The changes in Operating and maintenance expense consisted of the following: | | | | | | | | | 2022 vs. 2021 | | | | Increase (Decrease) | | | Asset impairment(a) | $ | 48 | | | | BSC costs | 14 | | | | Credit loss expense | 7 | | | | Labor, other benefits, contracting, and materials | 4 | | | | Storm-related costs | (11) | | | | Pension and non-pension postretirement benefits expense | (12) | | | | Other | 12 | | | | | 62 | | | | Regulatory required programs | 4 | | | | Total increase | $ | 66 | | | |
__________ (a)See Note 11 — Asset Impairments for additional information on the asset impairment. The changes in Depreciation and amortization expense consisted of the following: | | | | | | | | | 2022 vs. 2021 | | | | Increase | | | Depreciation and amortization(a) | $ | 35 | | | | Regulatory required programs | 3 | | | | Regulatory asset amortization | 1 | | | | Total increase | $ | 39 | | | |
__________ (a)Depreciation and amortization increased primarily due to ongoing capital expenditures. Taxes other than income taxes increased by $19 million for the year ended December 31, 2022 compared to the same period in 2021, primarily due to increased property taxes. Interest expense, net increased $14 million for the year ended December 31, 2022 compared to the same period in 2021, due to the issuance of debt in 2021 and 2022 and increases in interest rates. Effective income tax rates were 2.1% and (9.4)% for the years ended December 31, 2022 and 2021, respectively. The change is primarily due to decreases in the multi-year plans' accelerated income tax benefits in 2022 compared to 2021. 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 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. 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, 2022 compared to the same period in 2021. See the Results of Operations for Pepco, DPL, and ACE for additional information. | | | | | | | | | | | | | | | | | | | 2022 | | 2021 | | Favorable (Unfavorable) Variance | PHI | $ | 608 | | | $ | 561 | | | $ | 47 | | Pepco | 305 | | | 296 | | | 9 | | DPL | 169 | | | 128 | | | 41 | | ACE | 148 | | | 146 | | | 2 | | Other(a) | (14) | | | (9) | | | (5) | |
__________ (a)Primarily includes eliminating and consolidating adjustments, PHI's corporate operations, shared service entities, and other financing and investing activities. Year Ended December 31, 2022 Compared to Year Ended December 31, 2021. Net income increased by $47 million primarily due to favorable impacts as a result of Pepco's Maryland and District of Columbia multi-year plans, higher distribution rates at DPL and ACE, and the absence of the recognition of a valuation allowance against a deferred tax asset due to a change in Delaware tax law in 2021 at DPL, partially offset by an increase in depreciation expense, interest expense, credit loss expense and storm costs at Pepco and DPL.
Results of Operations—Pepco | | | | | | | | | | | | | | | | | | | 2022 | | 2021 | | Favorable (Unfavorable) Variance | Operating revenues | $ | 2,531 | | | $ | 2,274 | | | $ | 257 | | Operating expenses | | | | | | Purchased power | 834 | | | 624 | | | (210) | | Operating and maintenance | 507 | | | 471 | | | (36) | | Depreciation and amortization | 417 | | | 403 | | | (14) | | Taxes other than income taxes | 382 | | | 373 | | | (9) | | Total operating expenses | 2,140 | | | 1,871 | | | (269) | | | | | | | | Operating income | 391 | | | 403 | | | (12) | | Other income and (deductions) | | | | | | Interest expense, net | (150) | | | (140) | | | (10) | | Other, net | 55 | | | 48 | | | 7 | | Total other income and (deductions) | (95) | | | (92) | | | (3) | | Income before income taxes | 296 | | | 311 | | | (15) | | Income taxes | (9) | | | 15 | | | 24 | | Net income | $ | 305 | | | $ | 296 | | | $ | 9 | |
Year Ended December 31, 2022 Compared to Year Ended December 31, 2021.Net income increased by $9 million primarily due to favorable impacts of the Maryland and District of Columbia multi-year plans, partially offset by an increase in credit loss expense, depreciation expense, interest expense and storm costs. The changes in Operating revenues consisted of the following: | | | | | | | | | 2022 vs. 2021 | | | | Increase (Decrease) | | | Distribution | $ | 44 | | | | Transmission | 1 | | | | Other | (3) | | | | | 42 | | | | Regulatory required programs | 215 | | | | Total increase | $ | 257 | | | |
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 | 2022 | | 2021 | | | Residential | 856,037 | | | 841,831 | | | | Small commercial & industrial | 54,339 | | | 54,216 | | | | Large commercial & industrial | 22,841 | | | 22,568 | | | | Public authorities & electric railroads | 197 | | | 181 | | | | Total | 933,414 | | | 918,796 | | | |
Distribution Revenue increased for the year ended December 31, 2022 compared to the same period in 2021, primarily due to favorable impacts of the Maryland and District of Columbia multi-year plans. Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue remained relatively consistent for the year ended December 31, 2022 compared to the same period in 2021. 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, Pepco does not record Operating revenues or Purchased power expense related productsto the electricity. For customers that choose to purchase electric generation from Pepco, Pepco is permitted to recover the electricity and solutionsREC procurement costs from customers and therefore records the amounts related to variousthe electricity and RECs in Operating revenues and Purchased power expense. Pepco recovers electricity and REC procurement costs from customers includingwith 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 $210 million for the year ended December 31, 2022 compared to the same period in 2021, 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: | | | | | | | | | 2022 vs. 2021 | | | | Increase (Decrease) | | | | | | | | | | | Credit loss expense | $ | 17 | | | | BSC and PHISCO costs | 13 | | | | Storm-related costs | 8 | | | | Labor, other benefits, contracting, and materials | (2) | | | | | | | | | | | | | | | | Other | (6) | | | | | 30 | | | | Regulatory required programs | 6 | | | | Total increase | $ | 36 | | | |
The changes in Depreciation and amortizationexpense consisted of the following: | | | | | | | | | 2022 vs. 2021 | | | | Increase (Decrease) | | | Depreciation and amortization(a) | $ | 14 | | | | Regulatory asset amortization | (3) | | | | Regulatory required programs | 3 | | | | Total increase | $ | 14 | | | |
__________ (a)Depreciation and amortization increased primarily due to ongoing capital expenditures. Taxes other than income taxes increased $9 million for the year ended December 31, 2022 compared to the same period in 2021, primarily due to an increase in property taxes and gross receipts taxes. Interest expense, net increased $10 million for the year ended December 31, 2022 compared to the same period in 2021 primarily due to the issuance of debt in 2021 and 2022 and increases in interest rates. Other, net increased $7 million for the year ended December 31, 2022 compared to the same period in 2021, primarily due to higher AFUDC equity. Effective income tax rates were (3.0)% and 4.8% for the years ended December 31, 2022 and 2021, respectively. The change is primarily due to the acceleration of certain income tax benefits as a result of the Maryland and District of Columbia multi-year plans. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on the three-year electric distribution utilities, municipalities, cooperatives,multi-year plans and commercial, industrial, governmentalNote 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—DPL | | | | | | | | | | | | | | | | | | | 2022 | | 2021 | | Favorable (Unfavorable) Variance | Operating revenues | $ | 1,595 | | | $ | 1,380 | | | $ | 215 | | Operating expenses | | | | | | Purchased power and fuel | 706 | | | 539 | | | (167) | | Operating and maintenance | 349 | | | 345 | | | (4) | | Depreciation and amortization | 232 | | | 210 | | | (22) | | Taxes other than income taxes | 72 | | | 67 | | | (5) | | Total operating expenses | 1,359 | | | 1,161 | | | (198) | | | | | | | | Operating income | 236 | | | 219 | | | 17 | | Other income and (deductions) | | | | | | Interest expense, net | (66) | | | (61) | | | (5) | | Other, net | 13 | | | 12 | | | 1 | | Total other income and (deductions) | (53) | | | (49) | | | (4) | | Income before income taxes | 183 | | | 170 | | | 13 | | Income taxes | 14 | | | 42 | | | 28 | | Net income | $ | 169 | | | $ | 128 | | | $ | 41 | |
Year Ended December 31, 2022 Compared to Year Ended December 31, 2021.Net income increased by $41 million primarily due to higher distribution rates and residentialthe absence of the recognition of a valuation allowance against a deferred tax asset due to a change in Delaware tax law in 2021, partially offset by an increase in depreciation expense, interest expense, storm costs, and credit loss expense. The changes in Operating revenues consisted of the following: | | | | | | | | | | | | | | | | | | | | | | | | | 2022 vs. 2021 | | | | Increase (Decrease) | | | | Electric | | Gas | | Total | | | | | | | Weather | $ | — | | | $ | 3 | | | $ | 3 | | | | | | | | Volume | 2 | | | 2 | | | 4 | | | | | | | | Distribution | 23 | | | 9 | | | 32 | | | | | | | | Transmission | 6 | | | — | | | 6 | | | | | | | | Other | (2) | | | — | | | (2) | | | | | | | | | 29 | | | 14 | | | 43 | | | | | | | | Regulatory required programs | 116 | | | 56 | | | 172 | | | | | | | | Total increase | $ | 145 | | | $ | 70 | | | $ | 215 | | | | | | | |
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 customers 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, 2022 compared to the same period in 2021, Operating revenues related to weather increased due to favorable weather conditions in DPL's Delaware natural gas 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, 2022 compared to same period in 2021 and normal weather consisted of the following: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | | | | % Change | Delaware Electric Service Territory | 2022 | | 2021 | | Normal | | 2022 vs. 2021 | | 2022 vs. Normal | Heating Degree-Days | 4,428 | | | 4,239 | | | 4,593 | | | 4.5 | % | | (3.6) | % | Cooling Degree-Days | 1,382 | | | 1,380 | | | 1,272 | | | 0.1 | % | | 8.6 | % | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | | | | % Change | Delaware Natural Gas Service Territory | 2022 | | 2021 | | Normal | | 2022 vs. 2021 | | 2022 vs. Normal | Heating Degree-Days | 4,428 | | | 4,239 | | | 4,676 | | | 4.5 | % | | (5.3) | % | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Volume, exclusive of the effects of weather, increased for the year ended December 31, 2022 compared to the same period in 2021 primarily due to customer growth and usage. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Electric Retail Deliveries to Delaware Customers (in GWhs) | 2022 | | 2021 | | % Change | | Weather - Normal % Change (b) | | | | | | | Residential | 3,242 | | | 3,214 | | | 0.9 | % | | (0.1) | % | | | | | | | Small commercial & industrial | 1,443 | | | 1,452 | | | (0.6) | % | | (1.0) | % | | | | | | | Large commercial & industrial | 3,162 | | | 3,149 | | | 0.4 | % | | 0.4 | % | | | | | | | Public authorities & electric railroads | 33 | | | 34 | | | (2.9) | % | | (4.4) | % | | | | | | | Total electric retail deliveries(a) | 7,880 | | | 7,849 | | | 0.4 | % | | (0.1) | % | | | | | | |
| | | | | | | | | | | | | | | As of December 31, | | | Number of Total Electric Customers (Maryland and Delaware) | 2022 | | 2021 | | | Residential | 481,688 | | | 476,260 | | | | Small commercial & industrial | 63,738 | | | 63,195 | | | | Large commercial & industrial | 1,235 | | | 1,218 | | | | Public authorities & electric railroads | 597 | | | 604 | | | | Total | 547,258 | | | 541,277 | | | |
__________ (a)Reflects delivery volumes from customers purchasing electricity directly from DPL and customers purchasing electricity from a competitive markets. Where necessary, Generationelectric 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) | 2022 | | 2021 | | % Change | | Weather - Normal % Change(b) | | | | | | | Residential | 8,709 | | | 7,914 | | | 10.0 | % | | 4.2 | % | | | | | | | Small commercial & industrial | 4,176 | | | 3,747 | | | 11.4 | % | | 7.0 | % | | | | | | | Large commercial & industrial | 1,697 | | | 1,679 | | | 1.1 | % | | 1.1 | % | | | | | | | Transportation | 6,696 | | | 6,778 | | | (1.2) | % | | (2.3) | % | | | | | | | Total natural gas deliveries(a) | 21,278 | | | 20,118 | | | 5.8 | % | | 2.4 | % | | | | | | |
| | | | | | | | | | | | | | | As of December 31, | | | Number of Delaware Natural Gas Customers | 2022 | | 2021 | | | Residential | 129,502 | | | 128,121 | | | | Small commercial & industrial | 10,144 | | | 10,027 | | | | Large commercial & industrial | 17 | | | 20 | | | | Transportation | 156 | | | 158 | | | | Total | 139,819 | | | 138,326 | | | |
__________ (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, 2022 compared to the same period in 2021 primarily due to higher electric distribution rates in Maryland that became effective in March 2022, higher DSIC rates in Delaware that became effective in January and July 2022, and higher natural gas distribution rates in Delaware that became effective in August 2022. 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, 2022 compared to the same period in 2021 primarily due to 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, 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 $167 million for the year ended December 31, 2022 compared to the same period in 2021, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.
The changes in Operating and maintenance expense consisted of the following: | | | | | | | | | 2022 vs. 2021 | | | | Increase (Decrease) | | | Credit loss expense | $ | 5 | | | | Storm-related costs | 5 | | | | BSC and PHISCO costs | 5 | | | | | | | | Labor, other benefits, contracting, and materials | (13) | | | | Other | (3) | | | | | (1) | | | | Regulatory required programs | 5 | | | | Total increase | $ | 4 | | | |
The changes in Depreciation and amortization expense consisted of the following: | | | | | | | | | 2022 vs. 2021 | | | | Increase (Decrease) | | | Depreciation and amortization(a) | $ | 23 | | | | Regulatory asset amortization | (3) | | | | Regulatory required programs | 2 | | | | Total increase | $ | 22 | | | |
__________ (a)Depreciation and amortization increased primarily due to ongoing capital expenditures.
Taxes other than income taxes increased by $5 million for the year ended December 31, 2022 compared to the same period in 2021, primarily due to an increase in property taxes and gross receipts taxes. Interest expense, net increased $5 million for the year ended December 31, 2022 compared to the same period in 2021 primarily due to the issuance of debt in 2021 and 2022. Effective income tax rates were 7.7%and24.7% for the years ended December 31, 2022and2021, respectively. The decrease for the year ended December 31, 2022 is primarily related to the absence of the recognition of a valuation allowance against a deferred tax asset due to a change in Delaware tax law in 2021. 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 | | | | | | | | | | | | | | | | | | | 2022 | | 2021 | | Favorable (Unfavorable) Variance | Operating revenues | $ | 1,431 | | | $ | 1,388 | | | $ | 43 | | Operating expenses | | | | | | Purchased power | 624 | | | 694 | | | 70 | | Operating and maintenance | 331 | | | 320 | | | (11) | | Depreciation and amortization | 261 | | | 179 | | | (82) | | Taxes other than income taxes | 9 | | | 8 | | | (1) | | Total operating expenses | 1,225 | | | 1,201 | | | (24) | | | | | | | | Operating income | 206 | | | 187 | | | 19 | | Other income and (deductions) | | | | | | Interest expense, net | (66) | | | (58) | | | (8) | | Other, net | 11 | | | 4 | | | 7 | | Total other income and (deductions) | (55) | | | (54) | | | (1) | | Income before income taxes | 151 | | | 133 | | | 18 | | Income taxes | 3 | | | (13) | | | (16) | | Net income | $ | 148 | | | $ | 146 | | | $ | 2 | |
Year Ended December 31, 2022 Compared to Year Ended December 31, 2021. Net income increased $2 million primarily due to increases in distribution rates, partially offset by an increase in depreciation expense, the absence of favorable weather and volume as a result of the CIP, and an increase in interest expense. The changes in Operating revenues consisted of the following: | | | | | | | | | 2022 vs. 2021 | | | | (Decrease) Increase | | | Weather | $ | (3) | | | | Volume | (11) | | | | Distribution | 48 | | | | | | | | Transmission | 9 | | | | | | | | | | | | | | | | Other | (1) | | | | | 42 | | | | Regulatory required programs | 1 | | | | Total increase | $ | 43 | | | |
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 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. During the year ended December 31, 2022 compared to the same period in 2021, Operating revenues related to weather decreased due to the absence of favorable impacts in the first and second quarter of 2022 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, 2022 compared to same period in 2021 and normal weather consisted of the following: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | | Normal | | % Change | Heating and Cooling Degree-Days | 2022 | | 2021 | | | 2022 vs. 2021 | | 2022 vs. Normal | Heating Degree-Days | 4,629 | | | 4,256 | | | 4,589 | | | 8.8 | % | | 0.9 | % | Cooling Degree-Days | 1,243 | | | 1,284 | | | 1,210 | | | (3.2) | % | | 2.7 | % | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Volume,exclusive of the effects of weather, decreased for the year ended December 31, 2022 compared to the same period in 2021, primarily due to the absence of favorable impacts in the first and second quarter of 2022 as a result of the CIP. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Electric Retail Deliveries to Customers (in GWhs) | 2022 | | 2021 | | % Change | | Weather - Normal % Change(b) | | | | | | | Residential | 4,131 | | | 4,220 | | | (2.1) | % | | (2.4) | % | | | | | | | Small commercial & industrial | 1,499 | | | 1,409 | | | 6.4 | % | | 6.2 | % | | | | | | | Large commercial & industrial | 3,103 | | | 3,146 | | | (1.4) | % | | (1.5) | % | | | | | | | Public authorities & electric railroads | 47 | | | 46 | | | 2.2 | % | | 1.8 | % | | | | | | | Total electric retail deliveries(a) | 8,780 | | | 8,821 | | | (0.5) | % | | (0.7) | % | | | | | | |
| | | | | | | | | | | | | | | As of December 31, | | | Number of Electric Customers | 2022 | | 2021 | | | Residential | 502,247 | | | 499,628 | | | | Small commercial & industrial | 62,246 | | | 61,900 | | | | Large commercial & industrial | 3,051 | | | 3,156 | | | | Public authorities & electric railroads | 734 | | | 717 | | | | Total | 568,278 | | | 565,401 | | | |
__________ (a)Reflects delivery volumes from customers purchasing electricity directly from ACE and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. (b)Reflects the change in delivery volumes assuming normalized weather based on the historical 20-year average. Distribution Revenue increased for the year ended December 31, 2022 compared to the same period in 2021 due to higher distribution rates that became effective in January 2022. 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, 2022 compared to the same period in 2021 primarily due to increases in capital investment and underlying costs. 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, ACE does not record Operating revenues or Purchased power expense related to the electricity. For customers that choose to purchase electric generation from ACE, ACE is permitted to recover the electricity, ZEC, and REC procurement costs without mark-up and therefore records equal and offsetting amounts in Operating revenues and Purchased power expense related to the electricity, ZECs, and RECs. See Note 5 - Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ACE's revenue disaggregation. The decrease of $70 million for the year ended December 31, 2022 compared to same period in 2021, 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: | | | | | | | | | 2022 vs. 2021 | | | | (Decrease) Increase | | | Labor, other benefits, contracting and materials | $ | (5) | | | | | | | | Storm-related costs | 1 | | | | BSC and PHISCO costs | 1 | | | | | | | | | | | | Other | 9 | | | | | 6 | | | | Regulatory required programs(a) | 5 | | | | Total increase | $ | 11 | | | |
__________ (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: | | | | | | | | | 2022 vs. 2021 | | | | Increase | | | Depreciation and amortization(a) | $ | 18 | | | | Regulatory asset amortization | 2 | | | | Regulatory required programs(b) | 62 | | | | | | | | Total increase | $ | 82 | | | |
__________ (a)Depreciation and amortization increased primarily due to ongoing capital expenditures. (b)Regulatory required programs increased primarily due to the regulatory asset amortization of the PPA termination obligation which is fully offset in Operating revenues. Interest expense, net increased $8 million for the year ended December 31, 2022 compared to the same period in 2021 primarily due to the issuance of debt in 2021 and 2022. Other, net increased $7 million for the year ended December 31, 2022 compared to the same period in 2021 primarily due to higher AFUDC equity. Effective income tax rates were 2.0% and (9.8)% for the years ended December 31, 2022 and 2021, respectively. The change is primarily related to the absence of impacts of the July 14, 2021 settlement, which allowed ACE to retain certain tax benefits in 2021. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information regarding the July 14, 2021 settlement agreement and Note 13 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the 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. Each of the Registrants annually evaluates its financing plan, dividend practices, and credit line sizing, focusing on maintaining its investment grade ratings while meeting its cash needs to fund capital requirements, including construction expenditures, retire debt, pay dividends, and fund pension and OPEB obligations. 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 also purchase transmission servicebe delayed or limited and where such recovery takes place over an extended period of time. Each Registrant’s access to ensureexternal financing on reasonable terms depends on its credit ratings and current overall capital market business conditions, including that it has reliable transmission capacityof the utility industry in general. If these conditions deteriorate to physically move its power suppliesthe 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 $4.0 billion, as of December 31, 2022. 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 and Cash Requirements” section below for additional information. The Registrants expect cash flows to be sufficient to meet operating expenses, financing costs, and capital expenditure requirements. See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ debt and credit agreements. Cash flows related to Generation have not been presented as discontinued operations and are included in the Consolidated Statements of Cash Flows for all periods presented. The Exelon Consolidated Statement of Cash Flows for the year ended December 31, 2022 includes one month of cash flows from Generation. The Exelon Consolidated Statement of Cash Flows for the year ended December 31, 2021 includes twelve months of cash flows from Generation. This is the primary reason for the changes in cash flows as shown in the tables unless otherwise noted below. Cash Flows from Operating Activities 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. Additionally, ComEd is required to purchase CMCs from participating nuclear-powered generating facilities for a five-year period, and all of its costs of doing so will be recovered through a new rider. The price to be paid for each CMC is established through a competitive bidding process. ComEd will provide net payments to, or collect net payments from, customers for the difference between customer deliverycredits issued and the credit to be received from the participating nuclear-powered generating facilities. ComEd’s cash flows are affected by the establishment of CMC prices and the timing of recovering costs through the CMC regulatory asset. See Note 3 — Regulatory Matters and Note 18 — 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, 2022 and 2021 by Registrant: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Increase (decrease) in cash flows from operating activities | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Net income | $ | 342 | | | $ | 175 | | | $ | 72 | | | $ | (28) | | | $ | 47 | | | $ | 9 | | | $ | 41 | | | $ | 2 | | Adjustments to reconcile net income to cash: | | | | | | | | | | | | | | | | Non-cash operating activities | (2,382) | | | (176) | | | 124 | | | 173 | | | 259 | | | 93 | | | 25 | | | 141 | | Option premiums paid, net | 299 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Collateral received (posted), net | 1,322 | | | 51 | | | — | | | 16 | | | 99 | | | 22 | | | 35 | | | 42 | | Income taxes | (331) | | | — | | | (25) | | | (37) | | | (18) | | | (30) | | | (13) | | | 11 | | Pension and non-pension postretirement benefit contributions | 49 | | | 12 | | | — | | | 13 | | | (30) | | | — | | | — | | | (4) | | Regulatory assets and liabilities, net | (692) | | | (645) | | | (24) | | | (8) | | | (37) | | | 12 | | | 9 | | | (43) | | Changes in working capital and other noncurrent assets and liabilities | 3,251 | | | 185 | | | (79) | | | (98) | | | (227) | | | (97) | | | (64) | | | (60) | | Increase (decrease) in cash flows from operating activities | $ | 1,858 | | | $ | (398) | | | $ | 68 | | | $ | 31 | | | $ | 93 | | | $ | 9 | | | $ | 33 | | | $ | 89 | |
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. See above for additional information related to cash flows from Generation. Significant operating cash flow impacts for the Registrants and Generation for 2022 and 2021 were as follows: •See Note 22 —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. •Changes in collateral depended upon whether Generation was in a net mark-to-market liability or asset position, and collateral may have been required to be posted with or collected from its counterparties. In addition, the collateral posting and collection requirements differed depending on whether the transactions were on an exchange or in the over-the-counter markets. Changes in collateral for the Utility Registrants are dependent upon the credit exposure of procurement contracts that may require suppliers to post collateral. The amount of cash collateral received from external counterparties increased due to rising energy prices. See Note 15 — Derivative Financial Instruments for additional information. •See Note 13 — 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 regulatory assets and liabilities, net, are due to the timing of cash payments for costs recoverable, or cash receipts for costs recovered, under our regulatory mechanisms differs from the recovery period of those costs. Included within the changes is energy efficiency spend for ComEd of $394 million and $343 million for the years ended December 31, 2022 and 2021, respectively. Also included within the changes is energy efficiency and demand response programs spend for BGE, Pepco, DPL, and ACE of $113 million, $71 million, $28 million, and $11 million for the year ended December 31, 2022, respectively, and $107 million, $72 million, $29 million, and $4 million for the year ended December 31, 2021, respectively. PECO had no energy efficiency and demand response programs spend recorded to a regulatory asset for the years ended December 31, 2022 and 2021. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. •Changes in working capital and other noncurrent assets and liabilities for the Utility Registrants and Exelon Corporate total $(304) million and for Generation total $3,555 million. The change for Generation primarily relates to the revolving accounts receivable financing arrangement. See the Collection of DPP discussion below for additional information. The change in working capital and other noncurrent assets and liabilities for Exelon Corporate and the Utility Registrants is dependent upon the normal course of operations for all Registrants. For ComEd, it is also
dependent upon whether the participating nuclear-powered generating facilities owe money to ComEd as a result of the established pricing for CMCs. In 2022, the established pricing resulted in a receivable from nuclear-powered generating facilities, which is reported within the cash flows from operations as a change in accounts receivable. In future periods the established pricing could result in ComEd owing payments to nuclear-powered generating facilities, which would be reported within cash flows from operations as a change in accounts payable and accrued expenses. Cash Flows from Investing Activities The following table provides a summary of the change in cash flows from investing activities for the years ended December 31, 2022 and 2021 by Registrant: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Increase (decrease) in cash flows from investing activities | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Capital expenditures | $ | 834 | | | $ | (119) | | | $ | (109) | | | $ | (36) | | | $ | 11 | | | $ | (31) | | | $ | (1) | | | $ | 47 | | Investment in NDT fund sales, net | 113 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Collection of DPP | (3,733) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Proceeds from sales of assets and businesses | (861) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | | | | | | | | | | | | | | | | Other investing activities | (26) | | | 2 | | | (1) | | | (7) | | | 4 | | | 4 | | | (1) | | | — | | (Decrease) increase in cash flows from investing activities | $ | (3,673) | | | $ | (117) | | | $ | (110) | | | $ | (43) | | | $ | 15 | | | $ | (27) | | | $ | (2) | | | $ | 47 | |
Significant investing cash flow impacts for the Registrants for 2022 and 2021 were as follows: •Variances in capital expenditures are primarily due to the timing of cash expenditures for capital projects. See the "Credit Matters and Cash Requirements" section below for additional information on projected capital expenditure spending for the Utility Registrants. See Note 2 — Discontinued Operations of the Combined Notes to Consolidated Financial Statements for capital expenditures related to Generation prior to the separation. •Collection of DPP relates to Generation's revolving accounts receivable financing agreement which Generation entered into in April 2020. Generation received $400 million of additional funding related to the DPP in February and March of 2021. •Proceeds from sales of assets and businesses decreased primarily due to the sale of a significant portion of Generation's solar business and a biomass facility in 2021. Cash Flows from Financing Activities The following table provides a summary of the change in cash flows from financing activities for the years ended December 31, 2022 and 2021 by Registrant: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (Decrease) increase in cash flows from financing activities | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Changes in short-term borrowings, net | $ | (513) | | | $ | 900 | | | $ | 239 | | | $ | 148 | | | $ | (154) | | | $ | (16) | | | $ | (37) | | | $ | (101) | | Long-term debt, net | 2,395 | | | (50) | | | (25) | | | (50) | | | 50 | | | 40 | | | — | | | 10 | | Changes in intercompany money pool | — | | | — | | | 40 | | | — | | | 51 | | | — | | | — | | | — | | Issuance of common stock | 563 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Dividends paid on common stock | 163 | | | (71) | | | (60) | | | (8) | | | — | | | (195) | | | 4 | | | 143 | | Acquisition of noncontrolling interest | 885 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Distributions to member | — | | | — | | | — | | | — | | | (47) | | | — | | | — | | | — | | Contributions from parent/member | — | | | (121) | | | (140) | | | 29 | | | 104 | | | 221 | | | 27 | | | (144) | | Transfer of cash, restricted cash, and cash equivalents to Constellation | (2,594) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Other financing activities | (66) | | | 5 | | | (6) | | | (5) | | | (5) | | | (4) | | | — | | | — | | Increase (decrease) in cash flows from financing activities | $ | 833 | | | $ | 663 | | | $ | 48 | | | $ | 114 | | | $ | (1) | | | $ | 46 | | | $ | (6) | | | $ | (92) | |
Significant financing cash flow impacts for the Registrants for 2022 and 2021 were as follows: •Changes in short-term borrowings, net, are driven by repayments on and issuances of notes due in less than 365 days. Refer to Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on short-term borrowings for the Registrants. These changes also included repayments of $552 million in commercial paper and term loans by Generation prior to the separation. •Long-term debt, net, varies due to debt issuances and redemptions each year. Refer to the debt issuances and redemptions tables below for additional information for the Registrants. •Changes inintercompany money pool are driven by short-term borrowing needs. Refer below for more information regarding the intercompany money pool. Price•Issuance of common stock relates to the August 2022 underwritten public offering of Exelon common stock. See Note 19 — Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for additional information.
•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 Supply Risk Managementcash 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. •Acquisition of noncontrolling interest relates to Generation's acquisition of CENG noncontrolling interest in 2021. •Refer to Note 2 — Discontinued Operations for the transfer of cash, restricted cash, and cash equivalents to Constellation related to the separation. •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 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of the Registrants’ long-term debt. Debt activity for 2022 and 2021 by Registrant was as follows: During 2022, the following long-term debt was issued: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Company | | Type | | Interest Rate | | Maturity | | Amount | | Use of Proceeds | Exelon | | SMBC Term Loan Agreement | | SOFR plus 0.65% | | July 21, 2023(a) | | $300 | | Fund a cash payment to Constellation and for general corporate purposes. | Exelon | | U.S. Bank Term Loan Agreement | | SOFR plus 0.65% | | July 21, 2023(a) | | 300 | | Fund a cash payment to Constellation and for general corporate purposes. | Exelon | | PNC Term Loan Agreement | | SOFR plus 0.65% | | July 24, 2023(a) | | 250 | | Fund a cash payment to Constellation and for general corporate purposes. | Exelon | | Notes(b) | | 2.75% | | March 15, 2027 | | 650 | | Repay existing indebtedness and for general corporate purposes. | Exelon | | Notes(b) | | 3.35% | | March 15, 2032 | | 650 | | Repay existing indebtedness and for general corporate purposes. | Exelon | | Notes(b) | | 4.10% | | March 15, 2052 | | 700 | | Repay existing indebtedness and for general corporate purposes. | Exelon | | Long-Term Software License Agreements | | 2.30% | | December 1, 2025 | | 17 | | Procurement of software licenses | Exelon | | Long-Term Software License Agreements | | 3.70% | | August 9, 2025 | | 8 | | Procurement of software licenses | Exelon | | SMBC Term Loan Agreement | | SOFR plus 0.85% | | April 7, 2024 | | 500 | | Repay existing indebtedness and for general corporate purposes. | ComEd(c) | | First Mortgage Bonds, Series 132 | | 3.15% | | March 15, 2032 | | 300 | | Repay outstanding commercial paper obligations and to fund other general corporate purposes. | ComEd | | First Mortgage Bonds, Series 133 | | 3.85% | | March 15, 2052 | | 450 | | Repay outstanding commercial paper obligations and to fund other general corporate purposes. | PECO | | First and Refunding Mortgage Bonds | | 4.60% | | May 15, 2052 | | 350 | | Refinance existing indebtedness and for general corporate purposes. | PECO | | First and Refunding Mortgage Bonds | | 4.375% | | August 15, 2052 | | 425 | | Refinance outstanding commercial paper and for general corporate purposes. | BGE | | Notes | | 4.55% | | June 1, 2052 | | 500 | | Repay outstanding commercial paper obligations, repay existing indebtedness, and for general corporate purposes. | Pepco | | First Mortgage Bonds | | 3.97% | | March 24, 2052 | | 400 | | Repay existing indebtedness and for general corporate purposes. | Pepco | | First Mortgage Bonds | | 3.35% | | September 15, 2032 | | 225 | | Repay existing indebtedness and for general corporate purposes. | DPL | | First Mortgage Bonds | | 3.06% | | February 15, 2052 | | 125 | | Repay existing indebtedness and for general corporate purposes. | ACE | | First Mortgage Bonds | | 2.27% | | February 15, 2032 | | 25 | | Repay existing indebtedness and for general corporate purposes. | ACE | | First Mortgage Bonds | | 3.06% | | February 15, 2052 | | 150 | | Repay existing indebtedness and for general corporate purposes. |
__________ (a)During the third quarter of 2022, the SMBC Term Loan, U.S. Bank Term Loan, and PNC Term Loan were all reclassified to Long-term debt due within one year on the Exelon Consolidated Balance Sheet, given that the Term Loans have maturity dates of July 21, 2023 , and July 24, 2023, respectively. (b)In connection with the issuance and sale of the Notes, Exelon entered into a Registration Rights Agreement with the representatives of the initial purchasers of the Notes and other parties. Pursuant to the Registration Rights Agreement,
Exelon filed a registration statement on August 3, 2022, with respect to an offer to exchange the Notes for substantially similar notes of Exelon that are registered under the Securities Act. An exchange offer of registered notes for the Notes was completed on January 12, 2023. The registered notes issued in exchange for Notes in the exchange offer have terms identical in all respects to the Notes, except that their issuance was registered under the Securities Act. (c)On January 3, 2023, ComEd entered into a purchase agreement of First Mortgage Bonds of $400 million and $575 million at 4.90% and 5.30% due on February 1, 2033 and February 1, 2053, respectively. The closing date of the issuance occurred on January 10, 2023. During 2021, the following long-term debt was issued: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Company | | Type | | Interest Rate | | Maturity | | Amount | | Use of Proceeds | Exelon | | Long-Term Software License Agreements | | 3.62% | | December 1, 2025 | | $4 | | Procurement of software licenses. | ComEd | | First Mortgage Bonds, Series 130 | | 3.13% | | March 15, 2051 | | 700 | | Repay a portion of outstanding commercial paper obligations and two outstanding term loans, and to fund other general corporate purposes. | ComEd | | First Mortgage Bonds, Series 131 | | 2.75% | | September 1, 2051 | | 450 | | Refinance existing indebtedness and for general corporate purposes. | PECO | | First and Refunding Mortgage Bonds | | 3.05% | | March 15, 2051 | | 375 | | Funding for general corporate purposes. | PECO | | First and Refunding Mortgage Bonds | | 2.85% | | September 15, 2051 | | 375 | | Refinance existing indebtedness and for general corporate purposes. | BGE | | Senior Notes | | 2.25% | | June 15, 2031 | | 600 | | Repay a portion of outstanding commercial paper obligations, repay existing indebtedness, and to fund other general corporate purposes. | Pepco | | First Mortgage Bonds | | 2.32% | | March 30, 2031 | | 150 | | Repay existing indebtedness and for general corporate purposes. | Pepco | | First Mortgage Bonds | | 3.29% | | September 28, 2051 | | 125 | | Repay existing indebtedness and for general corporate purposes. | DPL | | First Mortgage Bonds | | 3.24% | | March 30, 2051 | | 125 | | Repay existing indebtedness and for general corporate purposes. | 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 | | 2.27% | | February 15, 2032 | | 75 | | Repay existing indebtedness and for general corporate purposes. |
During 2022, the following long-term debt was retired and/or redeemed: | | | | | | | | | | | | | | | | | | | | | | | | | | | Company | | Type | | Interest Rate | | Maturity | | Amount | Exelon | | Junior Subordinated Notes | | 3.50% | | May 2, 2022 | | $ | 1,150 | | Exelon | | Long-Term Software License Agreement | | 3.96% | | May 1, 2024 | | 2 | Exelon | | Long-Term Software License Agreement | | 2.30% | | December 1, 2025 | | 4 | | Exelon | | Long-Term Software License Agreement | | 3.70% | | August 9, 2025 | | 1 | | PECO | | First Mortgage Bonds | | 2.375% | | September 15, 2022 | | 350 | | BGE | | Notes | | 2.80% | | August 15, 2022 | | 250 | Pepco | | First Mortgage Bonds | | 3.05% | | April 1, 2022 | | 200 | Pepco | | Tax-Exempt Bonds | | 1.70% | | September 1, 2022 | | 110 |
Additionally, in connection with the separation, on January 31, 2022, Exelon Corporate received cash from Generation also managesof $258 million to settle an intercompany loan that mirrored the terms and amounts of the third-party debt obligations. The loan agreements were entered into as part of the 2012 Constellation merger. See Note 16
— Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the mirror debt. During 2021, the following long-term debt was retired and/or redeemed: | | | | | | | | | | | | | | | | | | | | | | | | | | | Company | | Type | | Interest Rate | | Maturity | | Amount | Exelon | | Senior Notes | | 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 |
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, 2022 and for the first quarter of 2023 were as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | Period | | Declaration Date | | Shareholder of Record Date | | Dividend Payable Date | | Cash per Share(a) | First Quarter 2022 | | February 8, 2022 | | February 25, 2022 | | March 10, 2022 | | $ | 0.3375 | | Second Quarter 2022 | | April 26, 2022 | | May 13, 2022 | | June 10, 2022 | | $ | 0.3375 | | Third Quarter 2022 | | July 26, 2022 | | August 15, 2022 | | September 9, 2022 | | $ | 0.3375 | | Fourth Quarter 2022 | | October 28, 2022 | | November 15, 2022 | | December 9, 2022 | | $ | 0.3375 | | First Quarter 2023 | | February 14, 2023 | | February 27, 2023 | | March 10, 2023 | | $ | 0.3600 | |
___________ (a)Exelon's Board of Directors approved an updated dividend policy for 2023. The 2023 quarterly dividend will be $0.36 per share. Credit Matters and Cash Requirements 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 $4.0 billion in aggregate total commitments of which $2.1 billion was available to support additional commercial paper as of December 31, 2022, and of which no financial institution has more than 6% 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 16 — 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 2022 to fund their short-term liquidity needs, when necessary. 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 supply risks for energythe impacts of hypothetical credit downgrades. The Registrants closely monitor events in the financial markets and fuelthe financial institutions associated with generation assetsthe 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 riskseffects of power marketing activities. Generation implements a three-year ratable sales planuncertainty in the capital and credit markets. The Registrants believe their cash flow from operating activities, access to align its hedging strategycredit markets, and their credit facilities provide sufficient liquidity to support the estimated future cash requirements discussed below.
On August 4, 2022, Exelon entered into an agreement with its financial objectives. Generation may also enter into transactions that are outsidecertain underwriters in connection with an underwritten public offering of this ratable sales plan. Generation is exposed to commodity price risk in 2020 and beyond for portions12.995 million shares of its electricity portfolio that are unhedged.common stock, no par value. The net proceeds were $563 million before expenses paid. Exelon used the proceeds, together with available cash balances, to repay $575 million in borrowings under a $1.15 billion term loan credit facility. See Note 19 — Shareholders' Equity and Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. On August 4, 2022, Exelon executed an equity distribution agreement (“Equity Distribution Agreement”) with certain sales agents and forward sellers and certain forward purchasers establishing an ATM equity distribution program under which it may offer and sell shares of its common stock, having an aggregate gross sales price of up to $1.0 billion. Exelon has no obligation to offer or sell any shares of common stock under the Equity Distribution Agreement and may at any time suspend or terminate offers and sales under the Equity Distribution Agreement. As of December 31, 2019,2022, Exelon has not issued any shares of common stock under the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New YorkATM program 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 saleshas not entered into any forward sale agreements. Pursuant to the Utility RegistrantsSeparation Agreement between Exelon and Constellation Energy Corporation, Exelon made a cash payment of $1.75 billion to serve their retail load. A portion of Generation’s hedging strategy may be implemented through the use of fuel products basedGeneration on assumed correlations between power and fuel prices. The risk management group and Exelon’s RMC monitor the financial risksJanuary 31, 2022. See Note 2 — Discontinued Operations 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 subjectCombined Notes to a risk management policy that includes stringent risk management limits. See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKConsolidated Financial Statements for additional information.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, 2022 and available credit facility capacity prior to any incremental collateral at December 31, 2022: | | | | | | | | | | | | | | | | | | | PJM Credit Policy Collateral | | Other Incremental Collateral Required(a) | | Available Credit Facility Capacity Prior to Any Incremental Collateral | ComEd | $ | 31 | | | $ | — | | | $ | 568 | | PECO | 1 | | | 71 | | | 361 | | BGE | 3 | | | 119 | | | 191 | | Pepco | 5 | | | — | | | 1 | | DPL | 6 | | | 15 | | | 185 | | ACE | 2 | | | — | | | 300 | | __________(a)Represents incremental collateral related to natural gas procurement contracts.
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 CEJA, 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. 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. ComEd filed a petition with the ICC seeking approval of a multi-year rate plan (MRP) for 2024-2027 on January 17, 2023. PECO's and DPL's electric and gas distribution costs and ACE's electric distribution costs have generally been recovered through rate case proceedings, with PECO utilizing a fully projected future test year while DPL and ACE utilize a historical test year. BGE’s electric and gas distribution costs and Pepco’s and DPL Maryland's electric distribution costs are currently recovered through multi-year rate case proceedings, as 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. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. 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 Exelon does not generate the electricity it delivers. The Utility Registrants' electric supply for its customers is primarily procured through contracts as directed by their respective state laws and regulatory commission actions. The Utility Registrants procure electricity supply from various approved bidders or from purchases on the PJM operated markets. PECO's, BGE’s, and DPL's natural gas supplies are purchased from a number of suppliers for terms that currently do not exceed three years. PECO, BGE, and DPL each have annual firm transportation contracts of 443,000 mmcf, 268,000 mmcf, and 44,000 mmcf, respectively, for delivery of gas. To supplement gas transportation and 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 27%, 42%, and 33% of PECO's, BGE’s, and DPL's 2022-2023 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, with limited exceptions, earns a return on its energy efficiency costs through a regulatory asset. BGE, Pepco Maryland, DPL Maryland, and ACE earn a return on most of their energy efficiency and demand response program costs through a regulatory asset. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. Capital ExpendituresInvestment Generation’s business isThe Utility Registrants' businesses are capital intensive and requiresrequire significant investments, primarily in nuclear fuelelectric transmission and energy generation assets. Generation’s estimated capital expenditures for 2020 includes Generation's sharedistribution and natural gas transportation and distribution facilities, to ensure the adequate capacity, reliability, and efficiency of the investment in the co-owned Salem plant and the total capital expenditures for CENG.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 20202023 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 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. 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 Following the separation on February 1, 2022, Exelon is now a Distribution and Transmission company, focused on delivering electricity and natural gas service to our customers and communities. Exelon's businesses remain focused on maintaining industry leading operational excellence, meeting or exceeding their financial commitments, ensuring timely recovery on investments to enable customer benefits, supporting clean energy policies including those that advance our jurisdictions' clean energy targets, 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 jurisdictions in which Exelon has operations have set some of the nation's leading clean energy targets and our strategy is to enable that future for all our stakeholders. The Utility Registrants invest in rate base that supports service to our customers and the community, including investments that sustain and improve reliability and resiliency and that enhance the service experience of our customers. The Utility Registrants make these investments prudently at a 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.
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 $31 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 $18 billion by the end of 2026. These investments provide greater reliability, improved service for our customers, increased capacity to accommodate new technologies and support a cleaner grid, and a stable return for the company. In August 2021, Exelon announced a Path to Clean goal to collectively reduce its operations-driven GHG emissions 50% by 2030 against a 2015 baseline and to reach net zero operations-driven GHG emissions by 2050, while supporting customers and communities in achieving their GHG reduction goals (Path to Clean). Exelon's quantitative goals include its Scope 1 and 2 GHG emissions, with the exception of Scope 2 emissions associated with system losses of electric power delivered to customers ("line losses"), and build upon Exelon's long-standing commitment to reducing our GHG emissions. Exelon's Path to Clean efforts extend beyond these quantitative goals to include efforts such as customer energy efficiency programs, which support reductions in customers' direct emissions and have the potential to reduce Exelon's Scope 3 emissions and Scope 2 line losses as well. 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 culture that promotes and embodies diversity, inclusion, innovation, and safety for their employees. In order to provide the services and products that their customers expect, the Registrants aspire to create teams that reflect the diversity of the communities that the Registrants serve. Therefore, the Registrants take steps to attract highly qualified and diverse talent and seek to create hiring and promotion practices that are equitable and neutralize any bias, including 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; mentorship programs; 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 typically conduct an employee engagement survey every other year to help identify organizational strengths and areas of opportunity for growth. 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, 2022. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Employees | | Exelon | | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Female(a)(b)(c) | | 5,300 | | | | | 1,535 | | | 752 | | | 786 | | | 1,270 | | | 329 | | | 139 | | | 109 | | People of Color(b)(c) | | 7,519 | | | | | 2,575 | | | 990 | | | 1,170 | | | 1,803 | | | 865 | | | 203 | | | 145 | | Aged <30 | | 2,026 | | | | | 721 | | | 361 | | | 286 | | | 424 | | | 169 | | | 85 | | | 61 | | Aged 30-50 | | 10,548 | | | | | 3,728 | | | 1,455 | | | 1,819 | | | 2,271 | | | 739 | | | 465 | | | 357 | | Aged >50 | | 6,489 | | | | | 1,907 | | | 1,070 | | | 1,061 | | | 1,466 | | | 442 | | | 341 | | | 203 | | Total Employees(d) | | 19,063 | | | | | 6,356 | | | 2,886 | | | 3,166 | | | 4,161 | | | 1,350 | | | 891 | | | 621 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Management(e) | | Exelon | | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Female(a)(b)(c) | | 961 | | | | | 235 | | | 139 | | | 122 | | | 206 | | | 51 | | | 13 | | | 21 | | People of Color(b)(c) | | 1,086 | | | | | 331 | | | 134 | | | 166 | | | 276 | | | 116 | | | 32 | | | 22 | | Aged <30 | | 29 | | | | | 7 | | | 9 | | | 4 | | | 6 | | | — | | | 2 | | | 2 | | Aged 30-50 | | 1,715 | | | | | 510 | | | 182 | | | 265 | | | 395 | | | 120 | | | 58 | | | 40 | | Aged >50 | | 1,286 | | | | | 363 | | | 190 | | | 163 | | | 276 | | | 61 | | | 57 | | | 40 | | Within 10 years of retirement eligibility | | 1,787 | | | | | 520 | | | 238 | | | 226 | | | 379 | | | 91 | | | 68 | | | 55 | | Total Employees in Management(d) | | 3,030 | | | | | 880 | | | 381 | | | 432 | | | 677 | | | 181 | | | 117 | | | 82 | |
__________ (a)The Registrants have a particular focus on creating an environment that attracts and retains women by enabling them to stay in the workforce, grow with the company, and move up the ranks. (b)To effectuate Exelon's pay equity goals, Exelon conducts analysis on gender and racial pay equity. (c)Information concerning women and people of color is based on self-disclosed information. (d)Total employees represents the sum of the aged categories. (e)Management is defined as executive/senior level officials and managers as well as all employees who have direct reports and/or 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 2020 to 2022. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exelon | | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Retirement Age | | 3.71 | % | | | | 4.09 | % | | 4.10 | % | | 3.48 | % | | 3.79 | % | | 3.74 | % | | 4.42 | % | | 3.88 | % | Voluntary | | 2.79 | % | | | | 2.22 | % | | 2.71 | % | | 1.76 | % | | 2.52 | % | | 2.81 | % | | 1.46 | % | | 1.84 | % | Non-Voluntary | | 0.81 | % | | | | 0.60 | % | | 1.10 | % | | 1.06 | % | | 1.02 | % | | 1.95 | % | | 0.47 | % | | 0.68 | % |
Collective Bargaining Agreements Approximately 44% of Exelon’s employees participate in CBAs. The following table presents employee information, including information about CBAs, as of December 31, 2022. | | | | | | | | | | | | | | | | | | | | | | | | | Total Employees Covered by CBAs | | Number of CBAs | | CBAs New and Renewed in 2022(a) | | Total Employees Under CBAs New and Renewed in 2022 | Exelon | 8,379 | | | 10 | | | 2 | | | 906 | | | | | | | | | | ComEd | 3,477 | | | 2 | | | — | | | — | | PECO | 1,368 | | | 2 | | | — | | | — | | BGE | 1,414 | | | 1 | | | — | | | — | | PHI | 2,113 | | | 5 | | | 2 | | | 906 | | Pepco | 890 | | | 1 | | | 1 | | | 890 | | DPL | 621 | | | 2 | | | — | | | — | | ACE | 401 | | | 2 | | | 1 | | | 16 | |
__________ (a)Does not include CBAs that were extended in 2022 while negotiations are ongoing for renewal.
Environmental Matters and Regulation 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 Audit and Risk Committee oversees compliance with environmental laws and regulations, including environmental risks related to Exelon's operations and facilities, as well as SEC disclosures related to environmental matters. Exelon's Corporate Governance Committee has the authority to oversee Exelon’s climate change and sustainability policies and programs, as discussed in further detail below. The respective Boards of the Utility Registrants oversee environmental issues related to these companies. The Exelon Board of Directors has general oversight responsibilities for ESG matters, including strategies and efforts to protect and improve the quality of the environment. 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 to the physical climate and environment, 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 climate legislation, Exelon supports the 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 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, as distributors of natural gas are regulated with respect to reporting of natural gas (methane) leakage on the natural gas systems and consumer use of such natural gas. Since its inception, Exelon has positioned itself as a leader in climate change mitigation. Exelon uses definitions and protocols provided by the World Resources Institute for its GHG inventory. In 2021, Exelon's Scope 1 and 2 GHG emissions, as revised following its separation from Constellation, were just over 5.7 million metric tons carbon dioxide equivalent using the World Resources Institute Corporate Standard Market-based accounting. Of these emissions, 0.5 million metric tons are considered to be operations-driven and in more direct control of our employees and processes. The majority of these operations-driven emissions are fugitive emissions from the gas delivery systems of Registrants PECO, BGE, and DPL. The remaining 5.2 million metric tons, approximately 91%, are the indirect emissions associated with the operation and use of the electric distribution and transmission system and primarily consists of losses resulting from the Utility Registrant's delivery of electricity to their customers (line losses). These emissions are driven primarily by customer demand for electricity and the mix of generation assets supplying energy to the electric grid. The Registrants do not own generation and must comply with applicable legal and regulatory requirements governing procurement of electricity for delivery to retail customers and use of the system to support other transmission transactions. However, the Registrants do engage in efforts that help to reduce these emissions, including customer programs to drive customer energy efficiency, help to manage peak demands, and enable distributed solar generation.
In August 2021, Exelon announced a Path to Clean goal to collectively reduce their operations-driven GHG emissions 50% by 2030 against a 2015 baseline, and to reach net zero operations-driven GHG emissions by 2050, while also supporting customers and communities to achieve their clean energy and emissions goals. Exelon’s quantitative goals include its Scope 1 and 2 GHG emissions, with the exception of Scope 2 line losses, and builds upon Exelon's long-standing commitment to reducing our GHG emissions. Exelon's activities in support of the Path to Clean goal will include efficiency and clean electricity for operations, vehicle fleet electrification, equipment and processes to reduce sulfur hexafluoride (SF6) leakage, investments in natural gas infrastructure to minimize methane leaks and increase safety and reliability, and investment and collaboration to develop new technologies. Beyond 2030, Exelon recognizes that technology advancement and continued policy support will be needed to ensure achievement of Net-Zero by 2050. Exelon is laying the groundwork by partnering with national labs, universities and research consortia to research, develop, and pilot clean technologies that will be needed, as well as working with our states, jurisdictions and policy makers to understand the scope and scale of energy transformation, and needed policies and incentives, that will be needed to reach local ambitions for GHG emissions reductions. The Utility Registrants are also supporting customers and communities to achieve their clean energy and emissions goals through significant energy efficiency programs. During 2023 - 2026, estimated customer program energy efficiency investments across the Utility Registrants total $3.5 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. As an energy delivery company, Exelon can play a key role in lowering GHG emissions across much of the economy in its service territories. In connecting end users of energy to electric and gas supply, Exelon can leverage its assets and customer interface to encourage efficient use of lower emitting resources as they become available. 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 have a goal to electrify 30% of their own vehicle fleet by 2025, increasing to 50% by 2030. Clean fuels and other emerging technologies can also support the transition, lessen the strain on electric system expansion, and support energy system resiliency. Exelon, and its registrants PECO, BGE, and DPL that own gas distribution assets, are also continuing to explore these other decarbonization opportunities, supporting pilots of emerging energy technologies and clean fuels to support both operational and customer-driven emissions reductions. The energy transition may present challenges for the Utility Registrants and their service territories. Exelon believes its market and business model could be significantly affected by the transition of the energy system, such as through an increased electric load and decreased demand for natural gas, potentially accompanied by changes in technology, customer expectations, and/or regulatory structures. See ITEM 1A. RISK FACTORS. The Registrants are potentially affected by emerging technologies that could over time affect or transform the energy industry. Climate Change Adaptation The Registrants' facilities and operations are subject to the impacts of global 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 for additional information related to the Registrants' risks associated with climate change. 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 established 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. 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, but on January 20, 2021, President Biden
accepted the Agreement, which resulted in the United States’ formal re-entry on February 19, 2021. The United States has set an economy-wide target of reducing its net GHG emissions by 50-52% below 2005 levels by 2030. On November 11, 2022 at the UNFCCC Conference of the Parties (COP 27), President Biden recommitted the U.S. to these goals and detailed the significant domestic climate actions the U.S. had taken to spur a new era of clean American manufacturing, enhance energy security, and drive down the costs of clean energy for consumers in the U.S. and around the world. Federal Climate Change Legislation and Regulation.On August 16, 2022, President Biden signed the Inflation Reduction Act (IRA), which aims to reduce U.S. carbon emissions and promote economic development through investments in clean and renewable energy projects. The consumer-facing clean energy tax credits created or expanded by the IRA are intended to drive rapid adoption of energy efficiency, electric transportation, and solar energy which would require Exelon's utilities to expand and modernize infrastructure, systems and services to integrate and optimize these resources. 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, challenging the rescission of the Clean Power Plan and enactment of the Affordable Clean Energy rule as unlawful. On January 19, 2021, the D.C. Circuit held the Affordable Clean Energy Rule (including its rescission of the Clean Power Plan) to be unlawful, vacated the rule, and remanded it to the EPA. The Supreme Court granted certiorari to examine the extent of the EPA's authority to regulate GHGs from power plants and, on June 30, 2022, reversed and remanded the D.C. Circuit's decision. The Supreme Court ruled that the EPA's use of generation shifting for development of standards in the Clean Power Plan went beyond Congress' intended authority under the Clean Air Act. The EPA has indicated that 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, following its separation from Constellation, Exelon no longer owns 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. Certain northeast and mid-Atlantic states (Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Pennsylvania, Rhode Island, Vermont, Virginia) currently participate in the RGGI. The program requires most fossil fuel-fired power plant owners and operators 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. Pennsylvania joined RGGI in April 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 expects to meet and exceed the mandate set in the Greenhouse Gas Emissions Reduction Act to reduce statewide GHG emissions 40% (from 2006 levels) by 2030, and the state’s Climate Solutions Now Act of 2022 further updates requirements with a proposal to reduce emissions 60% (from 2006 levels) by 2031. 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. Illinois’ climate bill, CEJA, establishes decarbonization requirements for the state to transition to 100% clean energy by 2050 and supports programs to improve energy efficiency, manage energy demand, attract clean energy investment and accelerate job creation. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on CEJA. The Registrants cannot predict the nature of future regulations or how such regulations might impact future financial statements.
Renewable and Clean Energy Standards. Each of 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 acquiring sufficient bundled or unbundled credits such as RECs, CMCs, or ZECs, or 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. 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, which were operated by ComEd's and PECO's predecessor companies. 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 certain environmental remediation costs of the MGP sites through a provision within customer rates. BGE, Pepco, DPL, and ACE do not have material contingent liabilities relating to MGP sites. The amount to be
expended in 2023 for compliance with environmental remediation related to contamination at former MGP sites and other gas purification sites is estimated to be approximately $52 million which consists primarily of $44 million at ComEd. As of December 31, 2022, 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 18 — 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 14, 2023 Exelon | | | | | | | | | | | | | | | | | | | | | Name | | Age | | Position | | Period | Butler, Calvin G. Jr. | | 53 | | | President and Chief Executive Officer, Exelon | | 2022 - Present | | | | | Chief Operating Officer, Exelon | | 2021 - 2022 | | | | | Senior Executive Vice President, Exelon | | 2019 - 2022 | | | | | Chief Executive Officer, Exelon Utilities | | 2019 - 2022 | | | | | Chief Executive Officer, BGE | | 2014 - 2019 | | | | | | | | | | | | | | | Jones, Jeanne | | 43 | | | Executive Vice President and Chief Financial Officer, Exelon | | 2022 - Present | | | | | Senior Vice President, Corporate Finance, Exelon | | 2021 - 2022 | | | | | Senior Vice President and Chief Financial Officer, ComEd | | 2018 - 2021 | | | | | | | | Glockner, David | | 62 | | | Executive Vice President, Compliance, Audit and Risk, Exelon | | 2020 - Present | | | | | Chief Compliance Officer, Citadel LLC | | 2017 - 2020 | | | | | | | | Littleton, Gayle E. | | 50 | | | Executive Vice President, General Counsel, Exelon | | 2020 - Present | | | | | Partner, Jenner & Block LLP | | 2015 - 2020 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Quiniones, Gil | | 56 | | | Chief Executive Officer, ComEd | | 2021 - Present | | | | | President and Chief Executive Officer, New York Power Authority | | 2011 - 2021 | | | | | | | | Innocenzo, Michael A. | | 57 | | | President and Chief Executive Officer, PECO | | 2018 - Present | | | | | | | | | | | | | | | Khouzami, Carim V. | | 48 | | | President, BGE | | 2021 - Present | | | | | Chief Executive Officer, BGE | | 2019 - Present | | | | | Senior Vice President & COO, Exelon Utilities | | 2018 - 2019 | | | | | | | | Anthony, J. Tyler | | 58 | | | President and Chief Executive Officer, PHI, Pepco, DPL, and ACE | | 2021 - Present | | | | | Senior Vice President and Chief Operating Officer, PHI, Pepco, DPL, and ACE | | 2016 - 2021 | | | | | | | | Trpik, Joseph R. | | 53 | | | Senior Vice President and Corporate Controller, Exelon | | 2022 - Present | | | | | Interim Senior Vice President & CFO, ComEd | | 2021 - 2022 | | | | | Senior Vice President & CFO, Exelon Utilities | | 2018 - 2021 | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
ComEd | | | | | | | | | | | | | | | | | | | | | Name | | Age | | Position | | Period | Quiniones, Gil | | 56 | | | Chief Executive Officer, ComEd | | 2021 - Present | | | | | President and Chief Executive Officer, New York Power Authority | | 2011 - 2021 | | | | | | | | Donnelly, Terence R. | | 62 | | | President and Chief Operating Officer, ComEd | | 2018 - Present | | | | | | | | | | | | | | | Graham, Elisabeth J. | | 44 | | | Senior Vice President, Chief Financial Officer & Treasurer, ComEd | | 2022 - Present | | | | | Treasurer, Exelon | | 2018 - 2022 | | | | | | | | | | | | | | | Rippie, E. Glenn | | 62 | | | Senior Vice President and General Counsel, ComEd | | 2022 - Present | | | | | Senior Vice President and Deputy General Counsel, Energy Regulation, Exelon | | 2022 - Present | | | | | Partner, Jenner & Block LLP | | 2019 - 2021 | | | | | Partner and Chief Financial Officer, Rooney, Rippie & Ratnaswamy, LLP | | 2010 - 2019 | | | | | | | | Washington, Melissa | | 53 | | | Senior Vice President, Customer Operations, 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 | | | | | | | | Binswanger, Lewis | | 63 | | | Senior Vice President, Governmental, Regulatory and External Affairs, ComEd | | 2022 - Present | | | | | Vice President, External Affairs, Nicor Gas | | 2013 - 2022 | | | | | | | | | | | | | | | | | | | | | |
PECO | | | | | | | | | | | | | | | | | | | | | Name | | Age | | Position | | Period | Innocenzo, Michael A. | | 57 | | | President and Chief Executive Officer, PECO | | 2018 - Present | | | | | | | | | | | | | | | Levine, Nicole | | 46 | | | Senior Vice President and Chief Operations Officer, PECO | | 2022 - Present | | | | | Vice President, Electrical Operations, PECO | | 2018 - 2022 | Humphrey, Marissa | | 43 | | | Senior Vice President, Chief Financial Officer and Treasurer, PECO | | 2022 - Present | | | | | Vice President, Regulatory Policy and Strategy (NJ/DE), PHI, DPL, and ACE | | 2021 - 2022 | | | | | Vice President, Finance, Exelon Utilities | | 2019 - 2020 | | | | | Vice President, Financial Planning and Analysis, PHI, Pepco, DPL, and ACE | | 2016 - 2019 | | | | | | | | Murphy, Elizabeth A. | | 63 | | | Senior Vice President, Governmental, Regulatory and External Affairs, PECO | | 2016 - Present | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Williamson, Olufunmilayo | | 44 | | | Senior Vice President, Customer Operations, PECO | | 2021 - Present | | | | | Senior Vice President, Chief Commercial Risk Officer, Exelon | | 2017 - 2020 | | | | | | | | | | | | | | | Gay, Anthony | | 57 | | | 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. | | 48 | | | President, BGE | | 2021 - Present | | | | | Chief Executive Officer, BGE | | 2019 - Present | | | | | Senior Vice President & COO, Exelon Utilities | | 2018 - 2019 | | | | | | | | Dickens, Derrick | | 58 | | | Senior Vice President and Chief Operating Officer, BGE | | 2021 - Present | | | | | Senior Vice President, Customer Operations, PHI, Pepco, DPL, and ACE | | 2020 - 2021 | | | | | Vice President, Technical Services, BGE | | 2016 - 2020 | | | | | | | | | | | | | | | Vahos, David M. | | 50 | | | Senior Vice President, Chief Financial Officer and Treasurer, BGE | | 2016 - Present | | | | | | | | | | | | | | | Núñez, Alexander G. | | 51 | | | Senior Vice President, Governmental, Regulatory and External Affairs, BGE | | 2021 - Present | | | | | Senior Vice President, Regulatory Affairs and Strategy, BGE | | 2020 - 2021 | | | | | Senior Vice President, Regulatory and External Affairs, BGE | | 2016 - 2020 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Galambos, Denise | | 60 | | | Senior Vice President, Customer Operations, BGE | | 2021 - Present | | | | | Vice President, Utility Oversight, Exelon Utilities | | 2020 - 2021 | | | | | Vice President, Human Resources, BGE | | 2018 - 2020 | | | | | | | | | | | | | | | Ralph, David | | 56 | | | Vice President and General Counsel, BGE | | 2021 - Present | | | | | Associate General Counsel, BGE | | 2019 - 2021 | | | | | Assistant General Counsel, Exelon | | 2017 - 2019 | | | | | | | |
PHI, Pepco, DPL, and ACE | | | | | | | | | | | | | | | | | | | | | Name | | Age | | Position | | Period | Anthony, J. Tyler | | 58 | | | President and Chief Executive Officer, PHI, Pepco, DPL, and ACE | | 2021 - Present | | | | | Senior Vice President and Chief Operating Officer, PHI, Pepco, DPL, and ACE | | 2016 - 2021 | | | | | | | | Olivier, Tamla | | 50 | | | 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. | | 59 | | | Senior Vice President, Chief Financial Officer and Treasurer, PHI, Pepco, DPL, and ACE | | 2018 - Present | | | | | | | | | | | | | | | | | | | | | | Oddoye, Rodney | | 46 | | | Senior Vice President, Governmental, Regulatory and 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 | | | | | | | | | | | | | | | Bancroft, Anne | | 56 | | | Vice President and General Counsel, PHI, Pepco, DPL, and ACE | | 2021 - Present | | | | | Associate General Counsel, Exelon | | 2017 - 2021 | | | | | | | | | | | | | | | Bell-Izzard, Morlon | | 57 | | | Senior Vice President, Customer Operations, PHI, Pepco, DPL, and ACE | | 2021 - Present | | | | | Vice President, Customer Operations, PHI, Pepco, DPL, and ACE | | 2019 - 2021 | | | | | Director, Utility Performance Assessment, Exelon | | 2016 - 2019 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
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, financial condition or liquidity/cash flows due to public health crises, epidemics or pandemics, such as 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 Constellation 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. Increasing pressure from both the private and public sectors to take actions to mitigate climate change could also push the speed and nature of this transition. 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 14 — 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 because 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, 2022, approximately 23%, 10%, and 16% of the Registrants’ available credit facilities were with European, Canadian, and Asian banks, respectively. Additionally, higher interest rates may put pressure on the Registrants’ overall liquidity profile, financial health and impact financial results. See Note 16 — 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 and Cash Requirements — 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. Public health crises, epidemics, or pandemics, such as COVID-19 could negatively impact the Registrants' results (All Registrants). COVID-19 disrupted economic activity in the Registrants’ respective markets and negatively affected the Registrants’ results of operations in 2020. However, the financial impacts were not material for the years ended December 31, 2021 and December 31, 2022, other than the 2022 impairment disclosure within Note 11 — Asset Impairments. 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 our vendors, competitors or customers and customer demand as well as 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 7 — Property, Plant, and Equipment, Note 11 — Asset Impairments, and Note 12 — 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 Constellation, Constellation 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 Constellation as part of the restructuring. If the third-party, Constellation, 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 Constellation'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 if 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 electric and gas revenue and earnings 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, transmission, 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' respective terms and conditions of service, including their respective rates, along with adoption of new rate structures and constructs, or establishment of new rate cases, 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, adoption of new rate structures and constructs or establishment of new rate cases. 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 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. 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 way 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 several 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' earnings, if timely recovery is not allowed. 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 to estimate their obligations to taxing authorities, which includes general tax positions taken and associated reserves established. Tax obligations include, but are not limited to: income, real estate, sales and use, and employment-related taxes and ongoing appeal issues related to these tax matters. All tax estimates could be subject to challenge by the tax authorities. Additionally, earnings may be impacted due to changes in federal or local/state tax laws, and the inherent difficulty of estimating potential tax effects of ongoing business decisions. See Note 1 — Significant Accounting Policies and Note 13 — 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 18 — 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, or disrupt 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 18 — 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 U.S. 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 18 — 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). The Registrants periodically perform analyses to better understand long-term projections of climate change and how those changes in the physical environments where they operate could affect their facilities and operations. The Registrants primarily operate in the Midwest and Mid-Atlantic 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 at greater risk of damage as changes in the global climate affect temperature and weather patterns, or be placed at greater risk of damage should climate changes result in more intense, frequent and extreme weather events, elevated levels of precipitation, sea level rise, increased surface water temperatures, and/or other effects. Over time, the Registrants are making 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 are making additional investments to adapt to changes in operational requirements to manage demand changes and customer expectations caused by climate change. Climate Change risks include changes to the energy systems due to 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 energy system transition pathways to reduce 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 ITEM 1.A. "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 several 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, including sophisticated nation-state actors, 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. Additionally, the U.S. government has warned that the Ukraine conflict may increase the risks of attacks targeting critical infrastructure in the United States. A security breach of the Registrants' physical assets or information systems or those of the Registrants competitors, vendors, business partners and interconnected entities in RTOs and ISOs, or regulators could materially impact Registrants by, among other things, impairing the availability of electricity and gas distributed by Registrants and/or the reliability of transmission and distribution systems, impairing the availability of vendor services and materials that the Registrants rely on to maintain their operations, or by leading to the theft or inappropriate release of certain types of information, including critical infrastructure information, sensitive customer, vendor, or employee data, or other confidential data. The risk of these 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 material 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 security 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 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 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. 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 or be impacted by lack of availability of critical parts, 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. Additionally, if critical parts are not available, it may impact the timing of execution of capital projects. The Registrants' consolidated financial statements could be negatively affected if they were unable to effectively manage their capital projects or raise the necessary capital, or if they are deemed liable for operational failure. 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 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 as well as areas where new technologies are pertinent. The Registrants’ performance could be negatively affected by poor performance of third-party contractors that perform periodic or ongoing work (All Registrants). All Registrants rely on third-party contractors to perform operations, maintenance, and construction work. Performance standards typically are included in all contractual obligations, but poor performance may impact the capital execution plan or operations, or have adverse financial or reputational consequences. 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 and broader beneficial electrification. 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 Constellation, 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 Constellation will indemnify each other for certain liabilities. If Exelon is required to pay under these indemnities to Constellation, Exelon's financial results could be negatively impacted. The Constellation indemnities may not be sufficient to hold Exelon harmless from the full amount of liabilities for which Constellation will be allocated responsibility, and Constellation may not be able to satisfy its indemnification obligations in the future. Pursuant to the separation agreement and certain other agreements between Exelon and Constellation, 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 Constellation 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 Constellation 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 Constellation for Exelon's benefit may not be
sufficient to protect Exelon against the full amount of such liabilities, and Constellation may not be able to fully satisfy its indemnification obligations. Moreover, even if Exelon ultimately succeeds in recovering from Constellation 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.
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, 2022 were as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Voltage | Circuit Miles | (Volts) | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE | 765,000 | 90 | | — | | — | | — | | — | | — | 500,000(a) | — | | 188 | | 216 | | 109 | | 15 | | — | 345,000 | 2,678 | | — | | — | | — | | — | | — | 230,000 | — | | 550 | | 352 | | 770 | | 472 | | 272 | 138,000 | 2,257 | | 135 | | 55 | | 61 | | 586 | | 214 | 115,000 | — | | — | | 700 | | 25 | | — | | — | 69,000 | — | | 177 | | — | | — | | 567 | | 662 |
___________ (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 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 | | 12,965 | | 9,155 | | 4,130 | | 6,007 | | 7,345 | Underground | 32,684 | | 9,590 | | 17,927 | | 7,207 | | 6,513 | | 3,007 |
Gas The following table presents PECO’s, BGE’s, and DPL’s natural gas pipeline miles at December 31, 2022: | | | | | | | | | | | | | | | | | | | PECO | | BGE | | DPL | Transmission(a) | 9 | | 152 | | 8 | Distribution | 6,990 | | 7,527 | | 2,198 | Service piping | 6,479 | | 6,761 | | 1,486 | Total | 13,478 | | 14,440 | | 3,692 |
___________ (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 16 — 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 18 — 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, 2023, there were 994,126,931 shares of common stock outstanding and approximately 80,780 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, compared with the S&P 500 Stock Index and the S&P Utility Index, for the period 2018 through 2022. Cumulative total returns account for the separation of Constellation, as spin-off dividend is assumed to be reinvested as received. This performance chart assumes: •$100 invested on December 31, 2017 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, | | 2017 | 2018 | 2019 | 2020 | 2021 | 2022 | Exelon Corporation | $100.00 | $118.33 | $123.39 | $118.59 | $167.70 | $181.67 | S&P 500 | $100.00 | $95.62 | $125.72 | $148.85 | $191.58 | $156.88 | S&P Utilities | $100.00 | $104.11 | $131.54 | $132.18 | $155.53 | $157.97 |
ComEd As of January 31, 2023, there were 127,021,394 outstanding shares of common stock, $12.50 par value, of ComEd, of which 127,002,904 shares were indirectly held by Exelon. As of January 31, 2023, in addition to Exelon, there were 283 record holders of ComEd common stock. There is no established market for shares of the common stock of ComEd. PECO As of January 31, 2023, 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, 2023, 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, 2023, Exelon indirectly held the entire membership interest in PHI. Pepco As of January 31, 2023, 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, 2023, 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, 2023, 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 by the MDPSC and DCPSC that prohibit Pepco from paying a dividend on its common shares if (a) after the dividend payment, Pepco's equity ratio would be below 48% as calculated pursuant to the MDPSC's and DCPSC's ratemaking precedents, 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 by the DEPSC and MDPSC that prohibit DPL from paying a dividend on its common shares if (a) after the dividend payment, DPL's equity ratio would be below 48% as calculated pursuant to the DEPSC's and MDPSC's ratemaking precedents, or (b) DPL’s corporate issuer or senior unsecured credit rating, or its equivalent, is rated by any of the three major credit rating agencies below the generally accepted definition of investment grade. No such event has occurred. ACE is subject to certain dividend restrictions established by settlements approved by the NJBPU that prohibit ACE from paying a dividend on its common shares if (a) after the dividend payment, ACE's common equity ratio would be below 48% as calculated pursuant to the NJBPU's ratemaking precedents, or (b) ACE's senior corporate issuer or 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 notify and 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 2023. The 2023 quarterly dividend will be $0.36 per share. As of December 31, 2022, Exelon had retained earnings of $4,597 million, ComEd had retained earnings of $2,030 million, PECO had retained earnings of $1,861 million, BGE had retained earnings of $2,075 million, and PHI had undistributed losses of $352 million. The following table sets forth Exelon’s quarterly cash dividends per share paid during 2022 and 2021: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2022 | | 2021 | (per share) | Fourth Quarter | | Third Quarter | | Second Quarter | | First Quarter | | Fourth Quarter | | Third Quarter | | Second Quarter | | First Quarter | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exelon | $ | 0.3375 | | | $ | 0.3375 | | | $ | 0.3375 | | | $ | 0.3375 | | | $ | 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: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2022 | | 2021 | (in millions) | 4th Quarter | | 3rd Quarter | | 2nd Quarter | | 1st Quarter | | 4th Quarter | | 3rd Quarter | | 2nd Quarter | | 1st Quarter | ComEd | 144 | | | 145 | | | 145 | | | 144 | | | 127 | | | 127 | | | 126 | | | 127 | | PECO | 100 | | | 99 | | | 100 | | | 100 | | | 85 | | | 85 | | | 84 | | | 85 | | BGE | 74 | | | 75 | | | 75 | | | 76 | | | 73 | | | 73 | | | 72 | | | 74 | | PHI | 125 | | | 230 | | | 293 | | | 102 | | | 98 | | | 191 | | | 333 | | | 81 | | Pepco | 63 | | | 100 | | | 258 | | | 42 | | | 47 | | | 98 | | | 95 | | | 28 | | DPL | 48 | | | 39 | | | 15 | | | 41 | | | 41 | | | 43 | | | 23 | | | 40 | | ACE | 17 | | | 90 | | | 19 | | | 19 | | | 8 | | | 51 | | | 215 | | | 14 | |
First Quarter 2023 Dividend On February 14, 2023, Exelon's Board of Directors declared a regular quarterly dividend of $0.36 per share on Exelon’s common stock for the first quarter of 2023. The dividend is payable on Friday, March 10, 2023, to shareholders of record of Exelon as of 5 p.m. Eastern time on Monday, February 27, 2023.
| | | | | | 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 Exelon is a utility services holding company engaged in the energy distribution and transmission businesses through ComEd, PECO, BGE, Pepco, DPL, and ACE. Exelon has six reportable segments consisting of 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, which, along with Exelon, are collectively referred to as the Registrants. The following combined Management’s Discussion and Analysis of Financial Condition and Results of Operations is separately filed by Exelon, 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 Utility Registrants' year ended December 31, 2021 compared to the year ended December 31, 2020, refer to ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS in the 2021 Recast Form 10-K, which was filed with the SEC on June 30, 2022. 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. There were no material impacts to Exelon from unfavorable economic conditions due to COVID-19 for the years ended December 31, 2022 and 2021, other than the 2022 impairment discussed below. The Registrants assessed long-lived assets, goodwill, and investments for recoverability. Exelon and BGE recorded a pre-tax impairment charge of $48 million in 2022 as a result of COVID-19 impacts on office use. See Note 12 — Asset Impairments for additional information related to this impairment assessment. None of the other Registrants recorded material impairment charges in 2022 as a result of COVID-19. Additionally, there were no material impairment charges recorded in 2021 as a result of COVID-19. 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 Service TerritoriesGAAP Results of Operations. The following table sets forth Exelon's GAAP consolidated Net income attributable to common shareholders from continuing operations and the Utility Registrants' Net income for the year ended December 31, 2022 compared to the same period in 2021. For additional information regarding the financial results for the years ended December 31, 2022 and 2021 see the discussions of Results of Operations by Registrant.
| | | | | | | | | | | | | | | | | | | 2022 | | 2021 | | Favorable (Unfavorable) Variance | Exelon | 2,054 | | | 1,616 | | | $ | 438 | | ComEd | 917 | | | 742 | | | 175 | | PECO | 576 | | | 504 | | | 72 | | BGE | 380 | | | 408 | | | (28) | | PHI | 608 | | | 561 | | | 47 | | Pepco | 305 | | | 296 | | | 9 | | DPL | 169 | | | 128 | | | 41 | | ACE | 148 | | | 146 | | | 2 | | Other(a) | (427) | | | (599) | | | 172 | |
__________ (a)Primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities, and other financing and investing activities. The separation of Constellation Energy Corporation, including Generation and its subsidiaries, meets the criteria for discontinued operations and as such, Generation's results of operations are presented as discontinued operations and have been excluded from Exelon's continuing operations for all periods presented. See Note 1 — Significant Accounting Policies and Note 2 — Discontinued Operations for additional information. Accounting rules require that certain BSC costs previously allocated to Generation be presented as part of Exelon’s continuing operations as these costs do not qualify as expenses of the discontinued operations. Such costs are included in Other in the table above and were $28 million and $429 million on a pre-tax basis, for the years ended December 31, 2022 and 2021, respectively. Year Ended December 31, 2022 Compared to Year Ended December 31, 2021. Net income attributable to common shareholders from continuing operationsincreased by $438 million and diluted earnings per average common share from continuing operations increased to $2.08 in 2022 from $1.65 in 2021 primarily due to: •Higher electric distribution earnings and energy efficiency earnings from higher rate base and higher allowed ROE due to an increase in treasury rates at ComEd; •The favorable impacts of rate increases at PECO, BGE, and PHI; •Favorable impacts of decreased storm costs at PECO and BGE; and •Lower BSC costs presented in Exelon’s continuing operations, which were previously allocated to Generation but do not qualify as expenses of the discontinued operation per the accounting rules. The increases were partially offset by: •An income tax expense recorded in connection with the separation primarily due to the long-term marginal state income tax rate change, the recognition of valuation allowances against the net deferred tax assets positions for certain standalone state filing jurisdictions, and nondeductible transaction costs partially offset by a one-time impact associated with a state tax benefit; •An adjustment at PECO to exclude one-time non-cash impacts associated with the remeasurement of deferred income taxes as a result of the reduction in Pennsylvania corporate income tax rate;
•Higher depreciation expense at PECO, BGE, and PHI; •Higher credit loss expense at PECO, BGE, and PHI; •Higher storm costs at PHI; and •Higher interest expense at PECO, BGE, PHI, and Exelon Corporate. Adjusted (non-GAAP) Operating Earnings. In addition to Net income, Exelon evaluates its operating performance using the measure of Adjusted (non-GAAP) operating earnings because management believes it represents earnings directly related to the ongoing operations of the business. Adjusted (non-GAAP) operating earnings exclude certain costs, expenses, gains and losses, and other specified items. This information is intended to enhance an investor’s overall understanding of year-to-year operating results and provide an indication of Exelon’s baseline operating performance excluding items that are considered by management to be not directly related to the ongoing operations of the business. In addition, this information is among the primary indicators management uses as a basis for evaluating performance, allocating resources, setting incentive compensation targets, and planning and forecasting of future periods. Adjusted (non-GAAP) operating earnings is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.
The following table provides a reconciliation between Net income attributable to common shareholders from continuing operations as determined in accordance with GAAP and Adjusted (non-GAAP) operating earnings for the year ended December 31, 2022 compared to 2021: | | | | | | | | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | | 2022 | | 2021 | (In millions, except per share data) | | | Earnings per Diluted Share | | | | Earnings per Diluted Share | Net Income Attributable to Common Shareholders from Continuing Operations | $ | 2,054 | | | $ | 2.08 | | | $ | 1,616 | | | $ | 1.65 | | Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $1 and $3, respectively) | 4 | | | — | | | 4 | | | — | | Asset Impairments (net of taxes of $10)(a) | 38 | | | 0.04 | | | — | | | — | | Cost Management Program (net of taxes of $1)(b) | — | | | — | | | 6 | | | 0.01 | | Asset Retirement Obligation (net of taxes of $2 and $1, respectively) | (4) | | | — | | | 2 | | | — | | COVID-19 Direct Costs (net of taxes of $6)(c) | — | | | — | | | 14 | | | 0.01 | | | | | | | | | | Acquisition Related Costs (net of taxes of $5)(d) | — | | | — | | | 15 | | | 0.02 | | ERP System Implementation Costs (net of taxes of $0 and $4, respectively)(e) | 1 | | | — | | | 13 | | | 0.01 | | Separation Costs (net of taxes of $10 and $21, respectively)(f) | 24 | | | 0.02 | | | 58 | | | 0.06 | | Income Tax-Related Adjustments (entire amount represents tax expense)(g) | 122 | | | 0.12 | | | 62 | | | 0.06 | | Adjusted (non-GAAP) Operating Earnings | $ | 2,239 | | | $ | 2.27 | | | $ | 1,791 | | | $ | 1.83 | |
__________ 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. The marginal statutory income tax rates for 2022 and 2021 ranged from 24.0% to 29.0%.
(a)Reflects costs related to the impairment of an office building at BGE, which are recorded in Operating and maintenance expense. (b)Primarily represents reorganization costs related to cost management programs. (c)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, which are recorded in Operating and maintenance expense. (d)Reflects certain BSC costs related to the acquisition of EDF's interest in CENG, which was completed in the third quarter of 2021, that were historically allocated to Generation but are presented as part of continuing operations in Exelon's results as these costs do not qualify as expenses of the discontinued operations per the accounting rules. (e)Reflects costs related to a multi-year ERP system implementation, which are recorded in Operating and maintenance expense. (f)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 separation, and employee-related severance costs, which are recorded in Operating and maintenance expense. (g)In 2021, for PHI, 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, for Corporate, reflects the adjustment to deferred income taxes due to changes in forecasted apportionment. In 2022, for PECO, primarily reflects an adjustment to exclude one-time non-cash impacts associated with the remeasurement of deferred income taxes as a result of the reduction in Pennsylvania corporate income tax rate. In 2022, for Corporate, in connection with the separation, Exelon recorded an income tax expense primarily due to the long-term marginal state income tax rate change, the recognition of valuation allowances against the deferred tax assets positions for certain standalone state filing jurisdictions, and nondeductible transaction costs partially offset by a one-time impact associated with a state tax benefit.
Significant 2022 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 (“the separation”). Exelon completed the separation on February 1, 2022. Constellation was newly formed and incorporated in Pennsylvania on June 15, 2021 for the purpose of separation and holds Generation. The separation represented a strategic shift that would have a major effect on Exelon’s operations and financial results. Accordingly, the separation meets the criteria for discontinued operations. See Note 2 — Discontinued Operations of the Combined Notes to Consolidated Financial Statements for additional information on the separation and discontinued operations. In connection with the separation, Exelon incurred separation costs impacting continuing operations of $34 million and $79 million on a pre-tax basis for the year ended December 31, 2022 and 2021, respectively, which are recorded in Operating and maintenance expense. These costs are excluded from Adjusted (non-GAAP) Operating Earnings. The separation 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. Equity Securities Offering On August 4, 2022, Exelon entered into an agreement with certain underwriters in connection with an underwritten public offering of 12.995 million shares of its common stock, no par value. The net proceeds were $563 million before expenses paid by Exelon. See Note 19 — Shareholders' Equity 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 2022. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on these and other regulatory proceedings.
Completed Distribution Base Rate Case Proceedings | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Registrant/Jurisdiction | | Filing Date | | Service | | Requested Revenue Requirement Increase | | Approved Revenue Requirement Increase | | Approved ROE | | Approval Date | | Rate Effective Date | ComEd - Illinois | | April 16, 2021 | | Electric | | $ | 51 | | | $ | 46 | | | 7.36 | % | | December 1, 2021 | | January 1, 2022 | | April 15, 2022 | | Electric | | 199 | | | 199 | | | 7.85 | % | | November 17, 2022 | | January 1, 2023 | PECO - Pennsylvania | | March 30, 2021 | | Electric | | 246 | | | 132 | | | N/A | | November 18, 2021 | | January 1, 2022 | | March 31, 2022 | | Natural Gas | | 82 | | | 55 | | | | October 27, 2022 | | January 1, 2023 | BGE - Maryland | | May 15, 2020 (amended September 11, 2020) | | Electric | | 203 | | | 140 | | | 9.50 | % | | December 16, 2020 | | January 1, 2021 | | | Natural Gas | | 108 | | | 74 | | | 9.65 | % | | | Pepco - District of Columbia | | May 30, 2019 (amended June 1, 2020) | | Electric | | 136 | | | 109 | | | 9.275 | % | | June 8, 2021 | | July 1, 2021 | Pepco - Maryland | | October 26, 2020 (amended March 31, 2021) | | Electric | | 104 | | | 52 | | | 9.55 | % | | June 28, 2021 | | June 28, 2021 | DPL - Maryland | | September 1, 2021 (amended December 23, 2021) | | Electric | | 27 | | | 13 | | | 9.60 | % | | March 2, 2022 | | March 2, 2022 | | May 19, 2022 | | Electric | | 38 | | | 29 | | | 9.60 | % | | December 14, 2022 | | January 1, 2023 | DPL - Delaware | | January 14, 2022 (amended August 15, 2022) | | Natural Gas | | 13 | | | 8 | | | 9.60 | % | | October 12, 2022 | | August 14, 2022 | ACE - New Jersey | | December 9, 2020 (amended February 26, 2021) | | Electric | | 67 | | | 41 | | | 9.60 | % | | July 14, 2021 | | January 1, 2022 |
Pending Distribution Base Rate Case Proceedings | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Registrant/Jurisdiction | | Filing Date | | Service | | Requested Revenue Requirement Increase | | Requested ROE | | Expected Approval Timing | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ComEd - Illinois | | January 17, 2023 | | Electric | | $ | 1,472 | | | 10.50% to 10.65% | | Fourth quarter of 2023 | DPL - Delaware | | December 15, 2022 | | Electric | | 60 | | | 10.50 | % | | Second quarter of 2024 | | | | | | | | | | | | | | | | | | | | | | |
Transmission Formula Rates The following total increases/(decreases) were included in the Utility Registrants' 2022 annual electric transmission formula rate updates. All rates are effective June 1, 2022 to May 31, 2023, subject to review by interested parties pursuant to review protocols of each Utility Registrants' tariff. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Registrant | | Initial Revenue Requirement Increase | | Annual Reconciliation (Decrease) Increase | | Total Revenue Requirement Increase | | Allowed Return on Rate Base | | Allowed ROE | ComEd | | $ | 24 | | | $ | (24) | | | $ | — | | | 8.11 | % | | 11.50 | % | PECO | | 23 | | | 16 | | | 39 | | | 7.30 | % | | 10.35 | % | BGE | | 25 | | | (4) | | | 16 | | | 7.30 | % | | 10.50 | % | Pepco | | 16 | | | 15 | | | 31 | | | 7.60 | % | | 10.50 | % | DPL | | 9 | | | 2 | | | 11 | | | 7.09 | % | | 10.50 | % | ACE | | 21 | | | 13 | | | 34 | | | 7.18 | % | | 10.50 | % |
Pennsylvania Corporate Income Tax Rate Change On July 8, 2022, Pennsylvania enacted House Bill 1342, which will permanently reduce the corporate income tax rate from 9.99% to 4.99%. The tax rate will be reduced to 8.99% for the 2023 tax year. Starting with the 2024 tax year, the rate is reduced by 0.50% annually until it reaches 4.99% in 2031. As a result of the rate change, in the third quarter of 2022, Exelon and PECO recorded a one-time decrease to deferred income taxes of $390 million with a corresponding decrease to the deferred income taxes regulatory asset of $428 million for the amounts that are expected to be settled through future customer rates and an increase to income tax expense of $38 million (net of federal taxes), which was excluded from Exelon's Adjusted (non-GAAP) Operating Earnings. The tax rate decrease is not expected to have a material ongoing impact to Exelon’s and PECO’s financial statements. See Note 13 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information. Inflation Reduction Act On August 16, 2022, the Inflation Reduction Act (IRA) was signed into law. The bill extends tax benefits for renewable technologies like solar and wind, and it creates new tax benefits for alternative clean energy sources like nuclear and hydrogen and it focuses on energy efficiency, electrification, and equity. However, the bill also implements a new 15.0% corporate minimum tax based on modified GAAP net income. Exelon estimates the IRA could result in an increase in cash taxes for Exelon of approximately $200 million per year starting in 2023. Exelon is continuing to assess the impacts of the IRA on the financial statements and will update estimates based on guidance to be issued by the U.S. Treasury in the future. Asset Impairment In the third quarter of 2022, a review of the impacts of COVID-19 on office use resulted in plans to cease the renovation and dispose of an office building at BGE before the asset was placed into service. BGE determined that the carrying value was not recoverable and that its fair value was less than carrying value. As a result, Exelon and BGE recorded a pre-tax impairment charge of $48 million in 2022, which was excluded from Exelon's Adjusted (non-GAAP) Operating Earnings. See Note 11 — Asset Impairments of the Combined Notes to Consolidated Financial Statements for additional information. ComEd's FERC Audit The Registrants are subject to periodic audits and investigations by FERC. FERC’s Division of Audits and Accounting initiated a nonpublic audit of ComEd in May 2021 evaluating ComEd’s compliance with (1) approved terms, rates and conditions of its transmission formula rate mechanism; (2) accounting requirements of the Uniform System of Accounts; (3) reporting requirements of the FERC Form 1; and (4) the requirements for record retention. The audit covered the period from January 1, 2017 through August 31, 2022. On January 17, 2023, ComEd was provided with information on a series of potential findings, including concerning ComEd's
methodology regarding the allocation of certain overhead costs to capital under FERC regulations. The final outcome and resolution of the findings or of the audit itself cannot be predicted and the results, while not reasonably estimable at this time, could be material to the Exelon and ComEd financial statements. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. 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 City of Chicago Franchise Agreement The current ComEd Franchise Agreement with the City of Chicago (the City) has been in force 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 become effective. 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. 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. However, the City did not proceed to issue an RFP. Since that time, ComEd and the City continued to negotiate and have arrived at a proposed Chicago Franchise Agreement (CFA) and an Energy and Equity Agreement (EEA). These agreements together are intended to grant ComEd the right to continue providing electric utility services using public ways within the City of Chicago, and to create a new non-profit entity to advance energy and energy-related equity projects. On February 1, 2023, the proposed CFA and EEA were introduced to the City Council. The proposed CFA and EEA remain subject to approval by the City Council and the Exelon Board. While Exelon and ComEd cannot predict the ultimate outcome of these processes, fundamental changes in the agreements 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. Infrastructure Investment and Jobs Act On November 15, 2021, President Biden signed the $1.2 trillion Infrastructure Investment and Jobs Act (IIJA) into law. IIJA provides for approximately $550 billion in new federal spending. Categories of funding include funding for a variety of infrastructure needs, including but not limited to: (1) power and grid reliability and resilience, (2) resilience for cybersecurity to address critical infrastructure needs, and (3) electric vehicle charging infrastructure for alternative fuel corridors. Federal agencies are developing guidelines to implement spending programs under IIJA. The time needed to develop these guidelines will vary with some limited program applications opened as early as the first quarter of 2022. The Registrants are continuing to analyze the legislation and considering possible opportunities to apply for funding, either directly or in potential collaborations with state and/or local
agencies and key stakeholders. The Registrants cannot predict the ultimate timing and success of securing funding from programs under IIJA. ComEd and BGE applied for the Middle Mile Grant (MMG), which establishes and funds construction, improvement, or acquisition of middle mile broadband infrastructure which creates high-speed internet services. The MMG addresses inequitable broadband access by expansion and extension of the middle mile infrastructure in underserved communities. ComEd and BGE cannot predict if their applications will be approved as filed or the timing of receiving any funds if they are awarded a grant. In December 2022, Exelon and the Utility Registrants submitted 14 concept papers in response to the Department of Energy's Grid Resilience and Innovation Partnership (GRIP) program. These concept papers are focused on delivering grid resilience and grid benefits to customers and communities across the Exelon footprint. Eleven of the fourteen opportunities received letters of encouragement to submit applications due in the first half of 2023. Exelon cannot predict if their applications will be approved as filed or the timing of receiving any funds if they are awarded a grant. Exelon and the Utility Registrants are supporting three different Regional Clean Hydrogen Hub opportunities, covering all five states that Exelon operates in plus Washington D.C., that have submitted concept papers to the Department of Energy. All three opportunities have received letters of encouragement from Department of Energy to submit applications due in April 2023. The program will create networks of hydrogen producers, consumers, and local connective infrastructure to accelerate the use of hydrogen as a clean energy carrier that can deliver or store energy. Exelon cannot predict if their applications will be approved as filed or the timing of receiving any funds if they are awarded a grant. 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. Goodwill (Exelon, ComEd, and PHI) As of December 31, 2022, Exelon’s $6.6 billion carrying amount of goodwill consists 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 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, 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 2022 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 12 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information. Unamortized Energy Contract Liabilities (Exelon and PHI) Unamortized energy contract liabilities represent the remaining unamortized balances of non-derivative electricity contracts that 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. Offsetting regulatory assets were also recorded for those energy contract costs that are probable of recovery through customer rates. The unamortized energy contract liabilities and the corresponding regulatory assets, 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 liabilities are recorded through purchased power and fuel expense. See Note 3 — Regulatory Matters and Note 12 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information. Depreciable Lives of Property, Plant, and Equipment (All Registrants) The Registrants have significant investments in electric and natural gas transmission and distribution assets. These assets are generally depreciated on a straight-line basis, using the group, or composite 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 regulatory action, or changes in retirement patterns indicate an update is necessary. Depreciation studies generally serve as the basis for amounts allowed in customer rates for recovery of depreciation costs. Generally, the 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. Changes in estimated useful lives 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. Retirement 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 2022 cost: | | | | | | | | | | | | Discount rate(a) | 3.24% | | 3.20% | | 0.5% | | $ | (16) | | | $ | (2) | | | $ | (18) | | | 3.24% | | 3.20% | | (0.5)% | | 31 | | | 7 | | | 38 | | EROA | 7.00% | | 6.44% | | 0.5% | | (54) | | | (7) | | | (61) | | | 7.00% | | 6.44% | | (0.5)% | | 54 | | | 7 | | | 61 | | Change in benefit obligation at December 31, 2022: | | | | | | | | | | | | Discount rate(a) | 5.53% | | 5.51% | | 0.5% | | (508) | | | (83) | | | (591) | | | 5.53% | | 5.51% | | (0.5)% | | 655 | | | 104 | | | 759 | |
__________ (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 14 — 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) as of December 31, 2022: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (In millions) | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Gain (loss) | $ | 2,461 | | | $ | 3,697 | | | $ | (387) | | | $ | 159 | | | $ | (978) | | | $ | (211) | | | $ | 142 | | | $ | (442) | | Charge against OCI(a) | (2,590) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
___________ (a)Exelon's charge against OCI (before taxes) consists of up to $1.9 billion, $347 million, $492 million, $279 million, $113 million, and $59 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 $115 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. Derivative Financial Instruments (All Registrants) The Registrants use derivative instruments to manage commodity price risk and interest rate risk related to ongoing business operations. See Note 15 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information. 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. All derivatives are recognized on the balance sheet at their fair value, except for certain derivatives that qualify for, and are elected under, NPNS. For derivatives that qualify and are designated as cash flow hedges, changes in fair value each period are initially recorded in AOCI and recognized in earnings when the hedged transaction
affects earnings. For derivatives intended to serve as economic hedges, which are not designated for hedge accounting, changes in fair value each period are recognized in earnings on the Consolidated Statement of Operations and Comprehensive Income or are recorded as a regulatory asset or liability when there is an ability to recover or return the associated costs or benefits in accordance with regulatory requirements. NPNS. Contracts that are designated as NPNS are not required to be recorded at fair value, but rather on an accrual basis of accounting. Determining whether a contract qualifies for NPNS requires judgment on whether the contract will physically deliver and requires that management ensure compliance with all the associated qualification and documentation requirements. For all NPNS derivative instruments, accounts payable is recorded when derivatives settle and expense is recognized in earnings as the underlying physical commodity is consumed. Contracts that qualify for 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 NPNS. Commodity Contracts. The Registrants make estimates and assumptions concerning future commodity prices, interest rates, and the timing of future transactions and their probable cash flows in deciding whether to enter derivative transactions, and in determining the initial accounting treatment for derivative transactions. The Registrants categorize these derivatives under a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. Derivative contracts can be 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. For derivatives that trade in liquid markets, 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 the assessment of nonperformance risk. The impacts of nonperformance and credit risk to date have generally not been material to the Registrants’ financial statements. Interest Rate Derivative Instruments. Exelon Corporate utilizes interest rate swaps to manage interest rate risk on existing and planned future debt issuances as well as potential fluctuations in Electric operating revenues at the corporate level in consolidation, which are directly correlated to yields on U.S. Treasury bonds under ComEd's distribution formula rate. The fair value of the swaps is calculated by discounting the future net cash flows to the present value based on the terms and conditions of the agreements and the forward interest rate curves. As these inputs are based on observable data and valuations of similar instruments, the interest rate derivatives are primarily categorized in Level 2 in the fair value hierarchy. 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 Statements for additional information regarding the Registrants’ derivative instruments. Income Taxes (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 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, 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. 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. Revenues (All Registrants) Sources of Revenue and Determination of Accounting Treatment. The Registrants earn revenues from the sale and delivery of power and natural gas in regulated markets. 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, and Alternative Revenue Program accounting guidance to recognize revenues 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 and natural gas are physically delivered to the customer. Transactions of the Registrants within the scope of Revenue from Contracts with Customers generally include sales to utility customers under regulated service tariffs.
The determination of the Registrants' 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 Registrant’s 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. Alternative Revenue Program Accounting. Certain of the 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 Registrants’ formula rate mechanisms and revenue decoupling mechanisms, the 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 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) The 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 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. The Registrants' customer accounts are written off consistent with approved regulatory requirements. The 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 Results of Operations—ComEd | | | | | | | | | | | | | | | | | | | 2022 | | 2021 | | (Unfavorable) Favorable Variance | Operating revenues | $ | 5,761 | | | $ | 6,406 | | | $ | (645) | | | | | | | | | | | | | | Operating expenses | | | | | | Purchased power | 1,109 | | | 2,271 | | | 1,162 | | Operating and maintenance | 1,412 | | | 1,355 | | | (57) | | Depreciation and amortization | 1,323 | | | 1,205 | | | (118) | | Taxes other than income taxes | 374 | | | 320 | | | (54) | | Total operating expenses | 4,218 | | | 5,151 | | | 933 | | Gain on sales of assets | (2) | | | — | | | (2) | | Operating income | 1,541 | | | 1,255 | | | 286 | | Other income and (deductions) | | | | | | Interest expense, net | (414) | | | (389) | | | (25) | | Other, net | 54 | | | 48 | | | 6 | | Total other income and (deductions) | (360) | | | (341) | | | (19) | | Income before income taxes | 1,181 | | | 914 | | | 267 | | Income taxes | 264 | | | 172 | | | (92) | | Net income | $ | 917 | | | $ | 742 | | | $ | 175 | |
Year Ended December 31, 2022 Compared to Year Ended December 31, 2021.Net income increased by $175 million primarily due to increases in electric distribution and energy efficiency formula rate earnings (reflecting higher allowed ROE due to an increase in U.S. Treasury rates and the impacts of higher rate base). The changes in Operating revenues consisted of the following: | | | | | | | 2022 vs. 2021 | | Increase (Decrease) | Distribution | $ | 310 | | Transmission | 65 | | Energy efficiency | 65 | | Other | 12 | | 452 | | Regulatory required programs | (1,097) | | Total decrease | $ | (645) | |
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, 2022, compared to the same period in 2021, due to higher allowed ROE due to an increase in U.S. Treasury rates, the impact of a higher rate base, and higher fully recoverable costs.
Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered, and the highest daily peak load, which is updated annually in January based on the prior calendar year. Generally, increases/decreases in the highest daily peak load will result in higher/lower transmission revenue. Transmission revenues increased during the year ended December 31, 2022, compared to the same period in 2021, primarily due to the impact of a higher rate base and higher fully recoverable costs. Energy Efficiency Revenue. FEJA provides for a performance-based formula rate, which requires an annual reconciliation of the revenue requirement in effect to the actual costs that the ICC determines are prudently and reasonably incurred in a given year. 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, 2022, compared to the same period in 2021, primarily due to higher allowed ROE due to an increase in U.S. Treasury rates, the impact of a higher rate base, and increased regulatory asset amortization, which is fully recoverable. Other Revenue primarily includes assistance provided to other utilities through mutual assistance programs. Other revenue increased for the year ended December 31, 2022, compared to the same period in 2021, 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, ETAC, and costs related to electricity, ZEC, CMC, and REC procurement. See Note 3 - Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information regarding CMCs. ETAC is a retail customer surcharge collected by electric utilities operating in Illinois established by CEJA and remitted to an Illinois state agency for programs to support clean energy jobs and training. The riders are designed to provide full and current cost recovery. The costs of these programs are included in Purchased power expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries as ComEd remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation from competitive suppliers, ComEd either acts as the billing agent or the competitive supplier separately bills its own customers, and therefore does not record Operating revenues or Purchased power expense related to the electricity. For customers that choose to purchase electric generation from ComEd, ComEd is permitted to recover the electricity, ZEC, CMC, and REC procurement costs without mark-up and therefore records equal and offsetting amounts in Operating revenues and Purchased power expense related to the electricity, ZECs, CMCs, and RECs. See Note 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ComEd's revenue disaggregation. The decrease of $1,162 million for the year ended December 31, 2022, compared to the same period in 2021, in Purchased power expense is primarily due to the CMCs from the participating nuclear-powered generating facilities. This favorability is offset by a decrease in Operating revenues as part of regulatory required programs. See Note 3 - Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information regarding CMCs.
The changes in Operating and maintenance expense consisted of the following: | | | | | | | | | 2022 vs. 2021 | | | | Increase (Decrease) | | | Labor, other benefits, contracting, and materials | $ | 57 | | | | Storm-related costs | 13 | | | | BSC Costs | 13 | | | | Pension and non-pension postretirement benefits expense | (30) | | | | Other | 5 | | | | | 58 | | | | Regulatory required programs(a) | (1) | | | | Total increase | $ | 57 | | | | | | | | | | | | | | | | | | | |
__________ (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 changes in Depreciation and amortization expense consisted of the following: | | | | | | | | | 2022 vs. 2021 | | | | Increase | | | Depreciation and amortization(a) | $ | 63 | | | | Regulatory asset amortization(b) | 55 | | | | | | | | Total increase | $ | 118 | | | |
__________ (a)Reflects ongoing capital expenditures. (b)Includes amortization of ComEd's energy efficiency formula rate regulatory asset.
Taxes other than income taxes increased by $54 million for the year December 31, 2022, compared to the same period in 2021, primarily due to taxes related to ETAC, which is recovered through Operating revenues. Interest expense, net increased $25 million for the year ended December 31, 2022, compared to the same period in 2021, primarily due to the issuance of debt in 2021 and 2022. Effective income tax rateswere 22.4%and 18.8% for the years ended December 31, 2022and2021, 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 | | | | | | | | | | | | | | | | | | | 2022 | | 2021 | | Favorable (Unfavorable) Variance | Operating revenues | $ | 3,903 | | | $ | 3,198 | | | $ | 705 | | Operating expenses | | | | | | Purchased power and fuel | 1,535 | | | 1,081 | | | (454) | | Operating and maintenance | 992 | | | 934 | | | (58) | | Depreciation and amortization | 373 | | | 348 | | | (25) | | Taxes other than income taxes | 202 | | | 184 | | | (18) | | Total operating expenses | 3,102 | | | 2,547 | | | (555) | | | | | | | | Operating income | 801 | | | 651 | | | 150 | | Other income and (deductions) | | | | | | Interest expense, net | (177) | | | (161) | | | (16) | | Other, net | 31 | | | 26 | | | 5 | | Total other income and (deductions) | (146) | | | (135) | | | (11) | | Income before income taxes | 655 | | | 516 | | | 139 | | Income taxes | 79 | | | 12 | | | (67) | | | | | | | | | | | | | | Net income | $ | 576 | | | $ | 504 | | | $ | 72 | |
Year Ended December 31, 2022 Compared to Year Ended December 31, 2021.Net income increased by $72 million, primarily due to increases in electric and gas distribution rates and a decrease in storm costs, partially offset by the one-time non-cash impacts associated with the Pennsylvania corporate income tax legislation passed in July 2022, and increases in depreciation expense, credit loss expense, and interest expense. The changes in Operating revenues consisted of the following: | | | | | | | | | | | | | | | | | | | 2022 vs. 2021 | | Increase (Decrease) | | Electric | | Gas | | Total | Weather | $ | 32 | | | $ | 10 | | | $ | 42 | | Volume | (21) | | | 8 | | | (13) | | Pricing | 138 | | | 25 | | | 163 | | Transmission | 15 | | | — | | | 15 | | Other | 15 | | | 6 | | | 21 | | | 179 | | | 49 | | | 228 | | Regulatory required programs | 327 | | | 150 | | | 477 | | Total increase | $ | 506 | | | $ | 199 | | | $ | 705 | |
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, 2022 compared to the same period in 2021, 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, 2022 compared to the same period in 2021 and normal weather consisted of the following:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | | | | % Change | PECO Service Territory | 2022 | | 2021 | | Normal | | 2022 vs. 2021 | | 2022 vs. Normal | Heating Degree-Days | 4,135 | | | 3,946 | | | 4,408 | | | 4.8 | % | | (6.2) | % | Cooling Degree-Days | 1,743 | | | 1,586 | | | 1,443 | | | 9.9 | % | | 20.8 | % |
Volume. Electric volume, exclusive of the effects of weather, for the year ended December 31, 2022 compared to the same period in 2021, decreased due to unfavorable load change. Natural gas volume for the year ended December 31, 2022 compared to the same period in 2021, increased due to favorable load change. | | | | | | | | | | | | | | | | | | | | | | | | Electric Retail Deliveries to Customers (in GWhs) | 2022 | | 2021 | | % Change | | Weather - Normal % Change(b) | Residential | 14,379 | | | 14,262 | | | 0.8 | % | | (1.8) | % | Small commercial & industrial | 7,701 | | | 7,597 | | | 1.4 | % | | 0.4 | % | Large commercial & industrial | 14,046 | | | 14,003 | | | 0.3 | % | | — | % | Public authorities & electric railroads | 638 | | | 559 | | | 14.1 | % | | 14.1 | % | Total electric retail deliveries(a) | 36,764 | | | 36,421 | | | 0.9 | % | | (0.4) | % |
__________ (a)Reflects delivery volumes from customers purchasing electricity directly from PECO and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. (b)Reflects the change in delivery volumes assuming normalized weather based on the historical 30-year average.
| | | | | | | | | | | | | As of December 31, | Number of Electric Customers | 2022 | | 2021 | Residential | 1,525,635 | | | 1,517,806 | | Small commercial & industrial | 155,576 | | | 155,308 | | Large commercial & industrial | 3,121 | | | 3,107 | | Public authorities & electric railroads | 10,393 | | | 10,306 | | Total | 1,694,725 | | | 1,686,527 | |
| | | | | | | | | | | | | | | | | | | | | | | | Natural Gas Deliveries to customers (in mmcf) | 2022 | | 2021 | | % Change | | Weather - Normal % Change(b) | Residential | 42,135 | | | 39,580 | | | 6.5 | % | | 3.0 | % | Small commercial & industrial | 23,449 | | | 21,361 | | | 9.8 | % | | 6.0 | % | Large commercial & industrial | 31 | | | 34 | | | (8.8) | % | | 12.3 | % | Transportation | 25,011 | | | 25,081 | | | (0.3) | % | | (1.8) | % | Total natural gas deliveries(a) | 90,626 | | | 86,056 | | | 5.3 | % | | 2.4 | % |
__________ (a)Reflects delivery volumes from customers purchasing natural gas directly from PECO and customers purchasing electricity 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.
| | | | | | | | | | | | | As of December 31, | Number of Gas Customers | 2022 | | 2021 | Residential | 502,944 | | | 497,873 | | Small commercial & industrial | 44,957 | | | 44,815 | | Large commercial & industrial | 9 | | | 6 | | Transportation | 655 | | | 670 | | Total | 548,565 | | | 543,364 | |
Pricing for the year ended December 31, 2022 compared to the same period in 2021 increased primarily due to increases in electric and gas distribution rates charged to customers.
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, 2022 compared to the same period in 2021, increased primarily due to revenue related to late payment charges. Regulatory Required Programs represents revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency, PGC, and the GSA. The riders are designed to provide full and current cost recovery as well as a return. The costs of these programs are included in Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense, and Income taxes. Customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers. Customer choice programs do not impact the volume of deliveries as PECO remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation or natural gas from competitive suppliers, PECO either acts as the billing agent or the competitive supplier separately bills its own customers and therefore PECO does not record Operating revenues or Purchased power and fuel expense related to the electricity and/or natural gas. For customers that choose to purchase electric generation or natural gas from PECO, PECO is permitted to recover the electricity, natural gas, and REC procurement costs without mark-up and therefore records equal and offsetting amounts in Operating revenues and Purchased power and fuel expense related to the electricity, natural gas, and RECs. See Note 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of PECO's revenue disaggregation. The increase of $454 million for the year ended December 31, 2022, compared to the same period in 2021, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs. The changes in Operating and maintenance expense consisted of the following: | | | | | | | | 2022 vs. 2021 | | | (Decrease) Increase | | Storm-related costs | $ | (34) | | | Pension and non-pension postretirement benefits expense | (9) | | | Credit loss expense | 6 | | | Labor, other benefits, contracting, and materials | 20 | | | BSC costs | 29 | | | Other(a) | 30 | | | | 42 | | | Regulatory Required Programs | 16 | | | Total increase | $ | 58 | | | __________(a) Primarily reflects an increase in charitable contributions. The changes in Depreciation and amortization expense consisted of the following: | | | | | | | 2022 vs. 2021 | | Increase | Depreciation and amortization(a) | $ | 24 | | Regulatory asset amortization | 1 | | Total increase | $ | 25 | |
__________ (a)Depreciation and amortization expense increased primarily due to ongoing capital expenditures.
Taxes other than income taxes increased by $18 million for the year ended December 31, 2022, compared to the same period in 2021, primarily due to higher Pennsylvania gross receipts tax, which is offset in Operating revenues, and offset by lower Pennsylvania use tax. Interest expense, net increased $16 million for the year ended December 31, 2022, compared to the same period in 2021, primarily due to the issuance of debt in 2021 and 2022 and increases in interest rates. Effective income tax rates were 12.1% and 2.3% for the years ended December 31, 2022 and 2021, respectively. The change in effective tax rate is primarily related to the one-time non-cash impacts associated with the Pennsylvania corporate income tax legislation passed in July 2022. 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—BGE | | | | | | | | | | | | | | | | | | | | | | | 2022 | | 2021 | | Favorable (Unfavorable) Variance | | | | | Operating revenues | $ | 3,895 | | | $ | 3,341 | | | $ | 554 | | | | | | Operating expenses | | | | | | | | | | Purchased power and fuel | 1,567 | | | 1,175 | | | (392) | | | | | | Operating and maintenance | 877 | | | 811 | | | (66) | | | | | | Depreciation and amortization | 630 | | | 591 | | | (39) | | | | | | Taxes other than income taxes | 302 | | | 283 | | | (19) | | | | | | Total operating expenses | 3,376 | | | 2,860 | | | (516) | | | | | | | | | | | | | | | | Operating income | 519 | | | 481 | | | 38 | | | | | | Other income and (deductions) | | | | | | | | | | Interest expense, net | (152) | | | (138) | | | (14) | | | | | | Other, net | 21 | | | 30 | | | (9) | | | | | | Total other income and (deductions) | (131) | | | (108) | | | (23) | | | | | | Income before income taxes | 388 | | | 373 | | | 15 | | | | | | Income taxes | 8 | | | (35) | | | (43) | | | | | | Net income | $ | 380 | | | $ | 408 | | | $ | (28) | | | | | | | | | | | | | | | |
Year Ended December 31, 2022 Compared to Year Ended December 31, 2021.Net income decreased $28 million primarily due to an asset impairment in 2022 and an increase in depreciation expense, credit loss expense, and interest expense, partially offset by favorable impacts of the multi-year plans and a decrease in storm costs. See Note 11 — Asset Impairments for additional information on the asset impairment. The changes in Operating revenues consisted of the following: | | | | | | | | | | | | | | | | | | | | | | | | | 2022 vs. 2021 | | | | Increase | | | | Electric | | Gas | | Total | | | | | | | Distribution | $ | 70 | | | $ | 27 | | | $ | 97 | | | | | | | | Transmission | 14 | | | — | | | 14 | | | | | | | | Other | 10 | | | 10 | | | 20 | | | | | | | | | 94 | | | 37 | | | 131 | | | | | | | | Regulatory required programs | 272 | | | 151 | | | 423 | | | | | | | | Total increase | $ | 366 | | | $ | 188 | | | $ | 554 | | | | | | | |
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 | 2022 | | 2021 | | | Residential | 1,204,429 | | | 1,195,929 | | | | Small commercial & industrial | 115,524 | | | 115,049 | | | | Large commercial & industrial | 12,839 | | | 12,637 | | | | Public authorities & electric railroads | 266 | | | 268 | | | | Total | 1,333,058 | | | 1,323,883 | | | |
| | | | | | | | | | | | | | | As of December 31, | | | Number of Gas Customers | 2022 | | 2021 | | | Residential | 655,373 | | | 651,589 | | | | Small commercial & industrial | 38,207 | | | 38,300 | | | | Large commercial & industrial | 6,233 | | | 6,179 | | | | Total | 699,813 | | | 696,068 | | | |
Distribution Revenue increased for the year ended December 31, 2022 compared to the same period in 2021, due to favorable impacts of the multi-year plans. Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue increased for the year ended December 31, 2022 compared to the same period in 2021 primarily due to 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, 2022 compared to the same period in 2021, primarily due to an increase in late fees charged to customers. Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as conservation, demand response, STRIDE, and the POLR mechanism. The riders are designed to provide full and current cost recovery, as well as a return in certain instances. The costs of these programs are included in Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers. Customer choice programs do not impact the volume of deliveries as BGE remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation or natural gas from competitive suppliers, BGE 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 $392 million for the year ended December 31, 2022 compared to the same period in 2021 in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.
The changes in Operating and maintenance expense consisted of the following: | | | | | | | | | 2022 vs. 2021 | | | | Increase (Decrease) | | | Asset impairment(a) | $ | 48 | | | | BSC costs | 14 | | | | Credit loss expense | 7 | | | | Labor, other benefits, contracting, and materials | 4 | | | | Storm-related costs | (11) | | | | Pension and non-pension postretirement benefits expense | (12) | | | | Other | 12 | | | | | 62 | | | | Regulatory required programs | 4 | | | | Total increase | $ | 66 | | | |
__________ (a)See Note 11 — Asset Impairments for additional information on the asset impairment. The changes in Depreciation and amortization expense consisted of the following: | | | | | | | | | 2022 vs. 2021 | | | | Increase | | | Depreciation and amortization(a) | $ | 35 | | | | Regulatory required programs | 3 | | | | Regulatory asset amortization | 1 | | | | Total increase | $ | 39 | | | |
__________ (a)Depreciation and amortization increased primarily due to ongoing capital expenditures. Taxes other than income taxes increased by $19 million for the year ended December 31, 2022 compared to the same period in 2021, primarily due to increased property taxes. Interest expense, net increased $14 million for the year ended December 31, 2022 compared to the same period in 2021, due to the issuance of debt in 2021 and 2022 and increases in interest rates. Effective income tax rates were 2.1% and (9.4)% for the years ended December 31, 2022 and 2021, respectively. The change is primarily due to decreases in the multi-year plans' accelerated income tax benefits in 2022 compared to 2021. 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 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. 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, 2022 compared to the same period in 2021. See the Results of Operations for Pepco, DPL, and ACE for additional information. | | | | | | | | | | | | | | | | | | | 2022 | | 2021 | | Favorable (Unfavorable) Variance | PHI | $ | 608 | | | $ | 561 | | | $ | 47 | | Pepco | 305 | | | 296 | | | 9 | | DPL | 169 | | | 128 | | | 41 | | ACE | 148 | | | 146 | | | 2 | | Other(a) | (14) | | | (9) | | | (5) | |
__________ (a)Primarily includes eliminating and consolidating adjustments, PHI's corporate operations, shared service entities, and other financing and investing activities. Year Ended December 31, 2022 Compared to Year Ended December 31, 2021. Net income increased by $47 million primarily due to favorable impacts as a result of Pepco's Maryland and District of Columbia multi-year plans, higher distribution rates at DPL and ACE, and the absence of the recognition of a valuation allowance against a deferred tax asset due to a change in Delaware tax law in 2021 at DPL, partially offset by an increase in depreciation expense, interest expense, credit loss expense and storm costs at Pepco and DPL.
Results of Operations—Pepco | | | | | | | | | | | | | | | | | | | 2022 | | 2021 | | Favorable (Unfavorable) Variance | Operating revenues | $ | 2,531 | | | $ | 2,274 | | | $ | 257 | | Operating expenses | | | | | | Purchased power | 834 | | | 624 | | | (210) | | Operating and maintenance | 507 | | | 471 | | | (36) | | Depreciation and amortization | 417 | | | 403 | | | (14) | | Taxes other than income taxes | 382 | | | 373 | | | (9) | | Total operating expenses | 2,140 | | | 1,871 | | | (269) | | | | | | | | Operating income | 391 | | | 403 | | | (12) | | Other income and (deductions) | | | | | | Interest expense, net | (150) | | | (140) | | | (10) | | Other, net | 55 | | | 48 | | | 7 | | Total other income and (deductions) | (95) | | | (92) | | | (3) | | Income before income taxes | 296 | | | 311 | | | (15) | | Income taxes | (9) | | | 15 | | | 24 | | Net income | $ | 305 | | | $ | 296 | | | $ | 9 | |
Year Ended December 31, 2022 Compared to Year Ended December 31, 2021.Net income increased by $9 million primarily due to favorable impacts of the Maryland and District of Columbia multi-year plans, partially offset by an increase in credit loss expense, depreciation expense, interest expense and storm costs. The changes in Operating revenues consisted of the following: | | | | | | | | | 2022 vs. 2021 | | | | Increase (Decrease) | | | Distribution | $ | 44 | | | | Transmission | 1 | | | | Other | (3) | | | | | 42 | | | | Regulatory required programs | 215 | | | | Total increase | $ | 257 | | | |
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 | 2022 | | 2021 | | | Residential | 856,037 | | | 841,831 | | | | Small commercial & industrial | 54,339 | | | 54,216 | | | | Large commercial & industrial | 22,841 | | | 22,568 | | | | Public authorities & electric railroads | 197 | | | 181 | | | | Total | 933,414 | | | 918,796 | | | |
Distribution Revenue increased for the year ended December 31, 2022 compared to the same period in 2021, primarily due to favorable impacts of the Maryland and District of Columbia multi-year plans. Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue remained relatively consistent for the year ended December 31, 2022 compared to the same period in 2021. 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, Pepco does not record Operating revenues or Purchased power expense related to the electricity. For customers that choose to purchase electric generation from Pepco, Pepco is permitted to recover the electricity and REC procurement costs from customers and therefore records the amounts related to the electricity and RECs in Operating revenues and Purchased power expense. Pepco recovers electricity and REC procurement costs from customers with a slight mark-up. See Note 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of Pepco's revenue disaggregation. The increase of $210 million for the year ended December 31, 2022 compared to the same period in 2021, 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: | | | | | | | | | 2022 vs. 2021 | | | | Increase (Decrease) | | | | | | | | | | | Credit loss expense | $ | 17 | | | | BSC and PHISCO costs | 13 | | | | Storm-related costs | 8 | | | | Labor, other benefits, contracting, and materials | (2) | | | | | | | | | | | | | | | | Other | (6) | | | | | 30 | | | | Regulatory required programs | 6 | | | | Total increase | $ | 36 | | | |
The changes in Depreciation and amortizationexpense consisted of the following: | | | | | | | | | 2022 vs. 2021 | | | | Increase (Decrease) | | | Depreciation and amortization(a) | $ | 14 | | | | Regulatory asset amortization | (3) | | | | Regulatory required programs | 3 | | | | Total increase | $ | 14 | | | |
__________ (a)Depreciation and amortization increased primarily due to ongoing capital expenditures. Taxes other than income taxes increased $9 million for the year ended December 31, 2022 compared to the same period in 2021, primarily due to an increase in property taxes and gross receipts taxes. Interest expense, net increased $10 million for the year ended December 31, 2022 compared to the same period in 2021 primarily due to the issuance of debt in 2021 and 2022 and increases in interest rates. Other, net increased $7 million for the year ended December 31, 2022 compared to the same period in 2021, primarily due to higher AFUDC equity. Effective income tax rates were (3.0)% and 4.8% for the years ended December 31, 2022 and 2021, respectively. The change is primarily due to the acceleration of certain income tax benefits as a result of the Maryland and District of Columbia multi-year plans. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on the three-year electric distribution multi-year plans and 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—DPL | | | | | | | | | | | | | | | | | | | 2022 | | 2021 | | Favorable (Unfavorable) Variance | Operating revenues | $ | 1,595 | | | $ | 1,380 | | | $ | 215 | | Operating expenses | | | | | | Purchased power and fuel | 706 | | | 539 | | | (167) | | Operating and maintenance | 349 | | | 345 | | | (4) | | Depreciation and amortization | 232 | | | 210 | | | (22) | | Taxes other than income taxes | 72 | | | 67 | | | (5) | | Total operating expenses | 1,359 | | | 1,161 | | | (198) | | | | | | | | Operating income | 236 | | | 219 | | | 17 | | Other income and (deductions) | | | | | | Interest expense, net | (66) | | | (61) | | | (5) | | Other, net | 13 | | | 12 | | | 1 | | Total other income and (deductions) | (53) | | | (49) | | | (4) | | Income before income taxes | 183 | | | 170 | | | 13 | | Income taxes | 14 | | | 42 | | | 28 | | Net income | $ | 169 | | | $ | 128 | | | $ | 41 | |
Year Ended December 31, 2022 Compared to Year Ended December 31, 2021.Net income increased by $41 million primarily due to higher distribution rates and the absence of the recognition of a valuation allowance against a deferred tax asset due to a change in Delaware tax law in 2021, partially offset by an increase in depreciation expense, interest expense, storm costs, and credit loss expense. The changes in Operating revenues consisted of the following: | | | | | | | | | | | | | | | | | | | | | | | | | 2022 vs. 2021 | | | | Increase (Decrease) | | | | Electric | | Gas | | Total | | | | | | | Weather | $ | — | | | $ | 3 | | | $ | 3 | | | | | | | | Volume | 2 | | | 2 | | | 4 | | | | | | | | Distribution | 23 | | | 9 | | | 32 | | | | | | | | Transmission | 6 | | | — | | | 6 | | | | | | | | Other | (2) | | | — | | | (2) | | | | | | | | | 29 | | | 14 | | | 43 | | | | | | | | Regulatory required programs | 116 | | | 56 | | | 172 | | | | | | | | Total increase | $ | 145 | | | $ | 70 | | | $ | 215 | | | | | | | |
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 customers 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, 2022 compared to the same period in 2021, Operating revenues related to weather increased due to favorable weather conditions in DPL's Delaware natural gas 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, 2022 compared to same period in 2021 and normal weather consisted of the following: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | | | | % Change | Delaware Electric Service Territory | 2022 | | 2021 | | Normal | | 2022 vs. 2021 | | 2022 vs. Normal | Heating Degree-Days | 4,428 | | | 4,239 | | | 4,593 | | | 4.5 | % | | (3.6) | % | Cooling Degree-Days | 1,382 | | | 1,380 | | | 1,272 | | | 0.1 | % | | 8.6 | % | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | | | | % Change | Delaware Natural Gas Service Territory | 2022 | | 2021 | | Normal | | 2022 vs. 2021 | | 2022 vs. Normal | Heating Degree-Days | 4,428 | | | 4,239 | | | 4,676 | | | 4.5 | % | | (5.3) | % | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Volume, exclusive of the effects of weather, increased for the year ended December 31, 2022 compared to the same period in 2021 primarily due to customer growth and usage. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Electric Retail Deliveries to Delaware Customers (in GWhs) | 2022 | | 2021 | | % Change | | Weather - Normal % Change (b) | | | | | | | Residential | 3,242 | | | 3,214 | | | 0.9 | % | | (0.1) | % | | | | | | | Small commercial & industrial | 1,443 | | | 1,452 | | | (0.6) | % | | (1.0) | % | | | | | | | Large commercial & industrial | 3,162 | | | 3,149 | | | 0.4 | % | | 0.4 | % | | | | | | | Public authorities & electric railroads | 33 | | | 34 | | | (2.9) | % | | (4.4) | % | | | | | | | Total electric retail deliveries(a) | 7,880 | | | 7,849 | | | 0.4 | % | | (0.1) | % | | | | | | |
| | | | | | | | | | | | | | | As of December 31, | | | Number of Total Electric Customers (Maryland and Delaware) | 2022 | | 2021 | | | Residential | 481,688 | | | 476,260 | | | | Small commercial & industrial | 63,738 | | | 63,195 | | | | Large commercial & industrial | 1,235 | | | 1,218 | | | | Public authorities & electric railroads | 597 | | | 604 | | | | Total | 547,258 | | | 541,277 | | | |
__________ (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) | 2022 | | 2021 | | % Change | | Weather - Normal % Change(b) | | | | | | | Residential | 8,709 | | | 7,914 | | | 10.0 | % | | 4.2 | % | | | | | | | Small commercial & industrial | 4,176 | | | 3,747 | | | 11.4 | % | | 7.0 | % | | | | | | | Large commercial & industrial | 1,697 | | | 1,679 | | | 1.1 | % | | 1.1 | % | | | | | | | Transportation | 6,696 | | | 6,778 | | | (1.2) | % | | (2.3) | % | | | | | | | Total natural gas deliveries(a) | 21,278 | | | 20,118 | | | 5.8 | % | | 2.4 | % | | | | | | |
| | | | | | | | | | | | | | | As of December 31, | | | Number of Delaware Natural Gas Customers | 2022 | | 2021 | | | Residential | 129,502 | | | 128,121 | | | | Small commercial & industrial | 10,144 | | | 10,027 | | | | Large commercial & industrial | 17 | | | 20 | | | | Transportation | 156 | | | 158 | | | | Total | 139,819 | | | 138,326 | | | |
__________ (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, 2022 compared to the same period in 2021 primarily due to higher electric distribution rates in Maryland that became effective in March 2022, higher DSIC rates in Delaware that became effective in January and July 2022, and higher natural gas distribution rates in Delaware that became effective in August 2022. 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, 2022 compared to the same period in 2021 primarily due to 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, 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 $167 million for the year ended December 31, 2022 compared to the same period in 2021, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.
The changes in Operating and maintenance expense consisted of the following: | | | | | | | | | 2022 vs. 2021 | | | | Increase (Decrease) | | | Credit loss expense | $ | 5 | | | | Storm-related costs | 5 | | | | BSC and PHISCO costs | 5 | | | | | | | | Labor, other benefits, contracting, and materials | (13) | | | | Other | (3) | | | | | (1) | | | | Regulatory required programs | 5 | | | | Total increase | $ | 4 | | | |
The changes in Depreciation and amortization expense consisted of the following: | | | | | | | | | 2022 vs. 2021 | | | | Increase (Decrease) | | | Depreciation and amortization(a) | $ | 23 | | | | Regulatory asset amortization | (3) | | | | Regulatory required programs | 2 | | | | Total increase | $ | 22 | | | |
__________ (a)Depreciation and amortization increased primarily due to ongoing capital expenditures.
Taxes other than income taxes increased by $5 million for the year ended December 31, 2022 compared to the same period in 2021, primarily due to an increase in property taxes and gross receipts taxes. Interest expense, net increased $5 million for the year ended December 31, 2022 compared to the same period in 2021 primarily due to the issuance of debt in 2021 and 2022. Effective income tax rates were 7.7%and24.7% for the years ended December 31, 2022and2021, respectively. The decrease for the year ended December 31, 2022 is primarily related to the absence of the recognition of a valuation allowance against a deferred tax asset due to a change in Delaware tax law in 2021. 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 | | | | | | | | | | | | | | | | | | | 2022 | | 2021 | | Favorable (Unfavorable) Variance | Operating revenues | $ | 1,431 | | | $ | 1,388 | | | $ | 43 | | Operating expenses | | | | | | Purchased power | 624 | | | 694 | | | 70 | | Operating and maintenance | 331 | | | 320 | | | (11) | | Depreciation and amortization | 261 | | | 179 | | | (82) | | Taxes other than income taxes | 9 | | | 8 | | | (1) | | Total operating expenses | 1,225 | | | 1,201 | | | (24) | | | | | | | | Operating income | 206 | | | 187 | | | 19 | | Other income and (deductions) | | | | | | Interest expense, net | (66) | | | (58) | | | (8) | | Other, net | 11 | | | 4 | | | 7 | | Total other income and (deductions) | (55) | | | (54) | | | (1) | | Income before income taxes | 151 | | | 133 | | | 18 | | Income taxes | 3 | | | (13) | | | (16) | | Net income | $ | 148 | | | $ | 146 | | | $ | 2 | |
Year Ended December 31, 2022 Compared to Year Ended December 31, 2021. Net income increased $2 million primarily due to increases in distribution rates, partially offset by an increase in depreciation expense, the absence of favorable weather and volume as a result of the CIP, and an increase in interest expense. The changes in Operating revenues consisted of the following: | | | | | | | | | 2022 vs. 2021 | | | | (Decrease) Increase | | | Weather | $ | (3) | | | | Volume | (11) | | | | Distribution | 48 | | | | | | | | Transmission | 9 | | | | | | | | | | | | | | | | Other | (1) | | | | | 42 | | | | Regulatory required programs | 1 | | | | Total increase | $ | 43 | | | |
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 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. During the year ended December 31, 2022 compared to the same period in 2021, Operating revenues related to weather decreased due to the absence of favorable impacts in the first and second quarter of 2022 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, 2022 compared to same period in 2021 and normal weather consisted of the following: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | | Normal | | % Change | Heating and Cooling Degree-Days | 2022 | | 2021 | | | 2022 vs. 2021 | | 2022 vs. Normal | Heating Degree-Days | 4,629 | | | 4,256 | | | 4,589 | | | 8.8 | % | | 0.9 | % | Cooling Degree-Days | 1,243 | | | 1,284 | | | 1,210 | | | (3.2) | % | | 2.7 | % | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Volume,exclusive of the effects of weather, decreased for the year ended December 31, 2022 compared to the same period in 2021, primarily due to the absence of favorable impacts in the first and second quarter of 2022 as a result of the CIP. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Electric Retail Deliveries to Customers (in GWhs) | 2022 | | 2021 | | % Change | | Weather - Normal % Change(b) | | | | | | | Residential | 4,131 | | | 4,220 | | | (2.1) | % | | (2.4) | % | | | | | | | Small commercial & industrial | 1,499 | | | 1,409 | | | 6.4 | % | | 6.2 | % | | | | | | | Large commercial & industrial | 3,103 | | | 3,146 | | | (1.4) | % | | (1.5) | % | | | | | | | Public authorities & electric railroads | 47 | | | 46 | | | 2.2 | % | | 1.8 | % | | | | | | | Total electric retail deliveries(a) | 8,780 | | | 8,821 | | | (0.5) | % | | (0.7) | % | | | | | | |
| | | | | | | | | | | | | | | As of December 31, | | | Number of Electric Customers | 2022 | | 2021 | | | Residential | 502,247 | | | 499,628 | | | | Small commercial & industrial | 62,246 | | | 61,900 | | | | Large commercial & industrial | 3,051 | | | 3,156 | | | | Public authorities & electric railroads | 734 | | | 717 | | | | Total | 568,278 | | | 565,401 | | | |
__________ (a)Reflects delivery volumes from customers purchasing electricity directly from ACE and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. (b)Reflects the change in delivery volumes assuming normalized weather based on the historical 20-year average. Distribution Revenue increased for the year ended December 31, 2022 compared to the same period in 2021 due to higher distribution rates that became effective in January 2022. 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, 2022 compared to the same period in 2021 primarily due to increases in capital investment and underlying costs. 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, ACE does not record Operating revenues or Purchased power expense related to the electricity. For customers that choose to purchase electric generation from ACE, ACE is permitted to recover the electricity, ZEC, and REC procurement costs without mark-up and therefore records equal and offsetting amounts in Operating revenues and Purchased power expense related to the electricity, ZECs, and RECs. See Note 5 - Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ACE's revenue disaggregation. The decrease of $70 million for the year ended December 31, 2022 compared to same period in 2021, 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: | | | | | | | | | 2022 vs. 2021 | | | | (Decrease) Increase | | | Labor, other benefits, contracting and materials | $ | (5) | | | | | | | | Storm-related costs | 1 | | | | BSC and PHISCO costs | 1 | | | | | | | | | | | | Other | 9 | | | | | 6 | | | | Regulatory required programs(a) | 5 | | | | Total increase | $ | 11 | | | |
__________ (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: | | | | | | | | | 2022 vs. 2021 | | | | Increase | | | Depreciation and amortization(a) | $ | 18 | | | | Regulatory asset amortization | 2 | | | | Regulatory required programs(b) | 62 | | | | | | | | Total increase | $ | 82 | | | |
__________ (a)Depreciation and amortization increased primarily due to ongoing capital expenditures. (b)Regulatory required programs increased primarily due to the regulatory asset amortization of the PPA termination obligation which is fully offset in Operating revenues. Interest expense, net increased $8 million for the year ended December 31, 2022 compared to the same period in 2021 primarily due to the issuance of debt in 2021 and 2022. Other, net increased $7 million for the year ended December 31, 2022 compared to the same period in 2021 primarily due to higher AFUDC equity. Effective income tax rates were 2.0% and (9.8)% for the years ended December 31, 2022 and 2021, respectively. The change is primarily related to the absence of impacts of the July 14, 2021 settlement, which allowed ACE to retain certain tax benefits in 2021. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information regarding the July 14, 2021 settlement agreement and Note 13 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the 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. Each of the Registrants annually evaluates its financing plan, dividend practices, and credit line sizing, focusing on maintaining its investment grade ratings while meeting its cash needs to fund capital requirements, including construction expenditures, retire debt, pay dividends, and fund pension and OPEB obligations. 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. 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 $4.0 billion, as of December 31, 2022. 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 and Cash Requirements” section below for additional information. The Registrants expect cash flows to be sufficient to meet operating expenses, financing costs, and capital expenditure requirements. See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ debt and credit agreements. Cash flows related to Generation have not been presented as discontinued operations and are included in the Consolidated Statements of Cash Flows for all periods presented. The Exelon Consolidated Statement of Cash Flows for the year ended December 31, 2022 includes one month of cash flows from Generation. The Exelon Consolidated Statement of Cash Flows for the year ended December 31, 2021 includes twelve months of cash flows from Generation. This is the primary reason for the changes in cash flows as shown in the tables unless otherwise noted below. Cash Flows from Operating Activities 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. Additionally, ComEd is required to purchase CMCs from participating nuclear-powered generating facilities for a five-year period, and all of its costs of doing so will be recovered through a new rider. The price to be paid for each CMC is established through a competitive bidding process. ComEd will provide net payments to, or collect net payments from, customers for the difference between customer credits issued and the credit to be received from the participating nuclear-powered generating facilities. ComEd’s cash flows are affected by the establishment of CMC prices and the timing of recovering costs through the CMC regulatory asset. See Note 3 — Regulatory Matters and Note 18 — 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, 2022 and 2021 by Registrant: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Increase (decrease) in cash flows from operating activities | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Net income | $ | 342 | | | $ | 175 | | | $ | 72 | | | $ | (28) | | | $ | 47 | | | $ | 9 | | | $ | 41 | | | $ | 2 | | Adjustments to reconcile net income to cash: | | | | | | | | | | | | | | | | Non-cash operating activities | (2,382) | | | (176) | | | 124 | | | 173 | | | 259 | | | 93 | | | 25 | | | 141 | | Option premiums paid, net | 299 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Collateral received (posted), net | 1,322 | | | 51 | | | — | | | 16 | | | 99 | | | 22 | | | 35 | | | 42 | | Income taxes | (331) | | | — | | | (25) | | | (37) | | | (18) | | | (30) | | | (13) | | | 11 | | Pension and non-pension postretirement benefit contributions | 49 | | | 12 | | | — | | | 13 | | | (30) | | | — | | | — | | | (4) | | Regulatory assets and liabilities, net | (692) | | | (645) | | | (24) | | | (8) | | | (37) | | | 12 | | | 9 | | | (43) | | Changes in working capital and other noncurrent assets and liabilities | 3,251 | | | 185 | | | (79) | | | (98) | | | (227) | | | (97) | | | (64) | | | (60) | | Increase (decrease) in cash flows from operating activities | $ | 1,858 | | | $ | (398) | | | $ | 68 | | | $ | 31 | | | $ | 93 | | | $ | 9 | | | $ | 33 | | | $ | 89 | |
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. See above for additional information related to cash flows from Generation. Significant operating cash flow impacts for the Registrants and Generation for 2022 and 2021 were as follows: •See Note 22 —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. •Changes in collateral depended upon whether Generation was in a net mark-to-market liability or asset position, and collateral may have been required to be posted with or collected from its counterparties. In addition, the collateral posting and collection requirements differed depending on whether the transactions were on an exchange or in the over-the-counter markets. Changes in collateral for the Utility Registrants are dependent upon the credit exposure of procurement contracts that may require suppliers to post collateral. The amount of cash collateral received from external counterparties increased due to rising energy prices. See Note 15 — Derivative Financial Instruments for additional information. •See Note 13 — 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 regulatory assets and liabilities, net, are due to the timing of cash payments for costs recoverable, or cash receipts for costs recovered, under our regulatory mechanisms differs from the recovery period of those costs. Included within the changes is energy efficiency spend for ComEd of $394 million and $343 million for the years ended December 31, 2022 and 2021, respectively. Also included within the changes is energy efficiency and demand response programs spend for BGE, Pepco, DPL, and ACE of $113 million, $71 million, $28 million, and $11 million for the year ended December 31, 2022, respectively, and $107 million, $72 million, $29 million, and $4 million for the year ended December 31, 2021, respectively. PECO had no energy efficiency and demand response programs spend recorded to a regulatory asset for the years ended December 31, 2022 and 2021. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. •Changes in working capital and other noncurrent assets and liabilities for the Utility Registrants and Exelon Corporate total $(304) million and for Generation total $3,555 million. The change for Generation primarily relates to the revolving accounts receivable financing arrangement. See the Collection of DPP discussion below for additional information. The change in working capital and other noncurrent assets and liabilities for Exelon Corporate and the Utility Registrants is dependent upon the normal course of operations for all Registrants. For ComEd, it is also
dependent upon whether the participating nuclear-powered generating facilities owe money to ComEd as a result of the established pricing for CMCs. In 2022, the established pricing resulted in a receivable from nuclear-powered generating facilities, which is reported within the cash flows from operations as a change in accounts receivable. In future periods the established pricing could result in ComEd owing payments to nuclear-powered generating facilities, which would be reported within cash flows from operations as a change in accounts payable and accrued expenses. Cash Flows from Investing Activities The following table provides a summary of the change in cash flows from investing activities for the years ended December 31, 2022 and 2021 by Registrant: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Increase (decrease) in cash flows from investing activities | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Capital expenditures | $ | 834 | | | $ | (119) | | | $ | (109) | | | $ | (36) | | | $ | 11 | | | $ | (31) | | | $ | (1) | | | $ | 47 | | Investment in NDT fund sales, net | 113 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Collection of DPP | (3,733) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Proceeds from sales of assets and businesses | (861) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | | | | | | | | | | | | | | | | Other investing activities | (26) | | | 2 | | | (1) | | | (7) | | | 4 | | | 4 | | | (1) | | | — | | (Decrease) increase in cash flows from investing activities | $ | (3,673) | | | $ | (117) | | | $ | (110) | | | $ | (43) | | | $ | 15 | | | $ | (27) | | | $ | (2) | | | $ | 47 | |
Significant investing cash flow impacts for the Registrants for 2022 and 2021 were as follows: •Variances in capital expenditures are primarily due to the timing of cash expenditures for capital projects. See the "Credit Matters and Cash Requirements" section below for additional information on projected capital expenditure spending for the Utility Registrants. See Note 2 — Discontinued Operations of the Combined Notes to Consolidated Financial Statements for capital expenditures related to Generation prior to the separation. •Collection of DPP relates to Generation's revolving accounts receivable financing agreement which Generation entered into in April 2020. Generation received $400 million of additional funding related to the DPP in February and March of 2021. •Proceeds from sales of assets and businesses decreased primarily due to the sale of a significant portion of Generation's solar business and a biomass facility in 2021. Cash Flows from Financing Activities The following table provides a summary of the change in cash flows from financing activities for the years ended December 31, 2022 and 2021 by Registrant: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (Decrease) increase in cash flows from financing activities | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Changes in short-term borrowings, net | $ | (513) | | | $ | 900 | | | $ | 239 | | | $ | 148 | | | $ | (154) | | | $ | (16) | | | $ | (37) | | | $ | (101) | | Long-term debt, net | 2,395 | | | (50) | | | (25) | | | (50) | | | 50 | | | 40 | | | — | | | 10 | | Changes in intercompany money pool | — | | | — | | | 40 | | | — | | | 51 | | | — | | | — | | | — | | Issuance of common stock | 563 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Dividends paid on common stock | 163 | | | (71) | | | (60) | | | (8) | | | — | | | (195) | | | 4 | | | 143 | | Acquisition of noncontrolling interest | 885 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Distributions to member | — | | | — | | | — | | | — | | | (47) | | | — | | | — | | | — | | Contributions from parent/member | — | | | (121) | | | (140) | | | 29 | | | 104 | | | 221 | | | 27 | | | (144) | | Transfer of cash, restricted cash, and cash equivalents to Constellation | (2,594) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Other financing activities | (66) | | | 5 | | | (6) | | | (5) | | | (5) | | | (4) | | | — | | | — | | Increase (decrease) in cash flows from financing activities | $ | 833 | | | $ | 663 | | | $ | 48 | | | $ | 114 | | | $ | (1) | | | $ | 46 | | | $ | (6) | | | $ | (92) | |
Significant financing cash flow impacts for the Registrants for 2022 and 2021 were as follows: •Changes in short-term borrowings, net, are driven by repayments on and issuances of notes due in less than 365 days. Refer to Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on short-term borrowings for the Registrants. These changes also included repayments of $552 million in commercial paper and term loans by Generation prior to the separation. •Long-term debt, net, varies due to debt issuances and redemptions each year. Refer to the debt issuances and redemptions tables below for additional information for the Registrants. •Changes inintercompany money pool are driven by short-term borrowing needs. Refer below for more information regarding the intercompany money pool. •Issuance of common stock relates to the August 2022 underwritten public offering of Exelon common stock. See Note 19 — Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for additional information. •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. •Acquisition of noncontrolling interest relates to Generation's acquisition of CENG noncontrolling interest in 2021. •Refer to Note 2 — Discontinued Operations for the transfer of cash, restricted cash, and cash equivalents to Constellation related to the separation. •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 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of the Registrants’ long-term debt. Debt activity for 2022 and 2021 by Registrant was as follows: During 2022, the following long-term debt was issued: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Company | | Type | | Interest Rate | | Maturity | | Amount | | Use of Proceeds | Exelon | | SMBC Term Loan Agreement | | SOFR plus 0.65% | | July 21, 2023(a) | | $300 | | Fund a cash payment to Constellation and for general corporate purposes. | Exelon | | U.S. Bank Term Loan Agreement | | SOFR plus 0.65% | | July 21, 2023(a) | | 300 | | Fund a cash payment to Constellation and for general corporate purposes. | Exelon | | PNC Term Loan Agreement | | SOFR plus 0.65% | | July 24, 2023(a) | | 250 | | Fund a cash payment to Constellation and for general corporate purposes. | Exelon | | Notes(b) | | 2.75% | | March 15, 2027 | | 650 | | Repay existing indebtedness and for general corporate purposes. | Exelon | | Notes(b) | | 3.35% | | March 15, 2032 | | 650 | | Repay existing indebtedness and for general corporate purposes. | Exelon | | Notes(b) | | 4.10% | | March 15, 2052 | | 700 | | Repay existing indebtedness and for general corporate purposes. | Exelon | | Long-Term Software License Agreements | | 2.30% | | December 1, 2025 | | 17 | | Procurement of software licenses | Exelon | | Long-Term Software License Agreements | | 3.70% | | August 9, 2025 | | 8 | | Procurement of software licenses | Exelon | | SMBC Term Loan Agreement | | SOFR plus 0.85% | | April 7, 2024 | | 500 | | Repay existing indebtedness and for general corporate purposes. | ComEd(c) | | First Mortgage Bonds, Series 132 | | 3.15% | | March 15, 2032 | | 300 | | Repay outstanding commercial paper obligations and to fund other general corporate purposes. | ComEd | | First Mortgage Bonds, Series 133 | | 3.85% | | March 15, 2052 | | 450 | | Repay outstanding commercial paper obligations and to fund other general corporate purposes. | PECO | | First and Refunding Mortgage Bonds | | 4.60% | | May 15, 2052 | | 350 | | Refinance existing indebtedness and for general corporate purposes. | PECO | | First and Refunding Mortgage Bonds | | 4.375% | | August 15, 2052 | | 425 | | Refinance outstanding commercial paper and for general corporate purposes. | BGE | | Notes | | 4.55% | | June 1, 2052 | | 500 | | Repay outstanding commercial paper obligations, repay existing indebtedness, and for general corporate purposes. | Pepco | | First Mortgage Bonds | | 3.97% | | March 24, 2052 | | 400 | | Repay existing indebtedness and for general corporate purposes. | Pepco | | First Mortgage Bonds | | 3.35% | | September 15, 2032 | | 225 | | Repay existing indebtedness and for general corporate purposes. | DPL | | First Mortgage Bonds | | 3.06% | | February 15, 2052 | | 125 | | Repay existing indebtedness and for general corporate purposes. | ACE | | First Mortgage Bonds | | 2.27% | | February 15, 2032 | | 25 | | Repay existing indebtedness and for general corporate purposes. | ACE | | First Mortgage Bonds | | 3.06% | | February 15, 2052 | | 150 | | Repay existing indebtedness and for general corporate purposes. |
__________ (a)During the third quarter of 2022, the SMBC Term Loan, U.S. Bank Term Loan, and PNC Term Loan were all reclassified to Long-term debt due within one year on the Exelon Consolidated Balance Sheet, given that the Term Loans have maturity dates of July 21, 2023 , and July 24, 2023, respectively. (b)In connection with the issuance and sale of the Notes, Exelon entered into a Registration Rights Agreement with the representatives of the initial purchasers of the Notes and other parties. Pursuant to the Registration Rights Agreement,
Exelon filed a registration statement on August 3, 2022, with respect to an offer to exchange the Notes for substantially similar notes of Exelon that are registered under the Securities Act. An exchange offer of registered notes for the Notes was completed on January 12, 2023. The registered notes issued in exchange for Notes in the exchange offer have terms identical in all respects to the Notes, except that their issuance was registered under the Securities Act. (c)On January 3, 2023, ComEd entered into a purchase agreement of First Mortgage Bonds of $400 million and $575 million at 4.90% and 5.30% due on February 1, 2033 and February 1, 2053, respectively. The closing date of the issuance occurred on January 10, 2023. During 2021, the following long-term debt was issued: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Company | | Type | | Interest Rate | | Maturity | | Amount | | Use of Proceeds | Exelon | | Long-Term Software License Agreements | | 3.62% | | December 1, 2025 | | $4 | | Procurement of software licenses. | ComEd | | First Mortgage Bonds, Series 130 | | 3.13% | | March 15, 2051 | | 700 | | Repay a portion of outstanding commercial paper obligations and two outstanding term loans, and to fund other general corporate purposes. | ComEd | | First Mortgage Bonds, Series 131 | | 2.75% | | September 1, 2051 | | 450 | | Refinance existing indebtedness and for general corporate purposes. | PECO | | First and Refunding Mortgage Bonds | | 3.05% | | March 15, 2051 | | 375 | | Funding for general corporate purposes. | PECO | | First and Refunding Mortgage Bonds | | 2.85% | | September 15, 2051 | | 375 | | Refinance existing indebtedness and for general corporate purposes. | BGE | | Senior Notes | | 2.25% | | June 15, 2031 | | 600 | | Repay a portion of outstanding commercial paper obligations, repay existing indebtedness, and to fund other general corporate purposes. | Pepco | | First Mortgage Bonds | | 2.32% | | March 30, 2031 | | 150 | | Repay existing indebtedness and for general corporate purposes. | Pepco | | First Mortgage Bonds | | 3.29% | | September 28, 2051 | | 125 | | Repay existing indebtedness and for general corporate purposes. | DPL | | First Mortgage Bonds | | 3.24% | | March 30, 2051 | | 125 | | Repay existing indebtedness and for general corporate purposes. | 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 | | 2.27% | | February 15, 2032 | | 75 | | Repay existing indebtedness and for general corporate purposes. |
During 2022, the following long-term debt was retired and/or redeemed: | | | | | | | | | | | | | | | | | | | | | | | | | | | Company | | Type | | Interest Rate | | Maturity | | Amount | Exelon | | Junior Subordinated Notes | | 3.50% | | May 2, 2022 | | $ | 1,150 | | Exelon | | Long-Term Software License Agreement | | 3.96% | | May 1, 2024 | | 2 | Exelon | | Long-Term Software License Agreement | | 2.30% | | December 1, 2025 | | 4 | | Exelon | | Long-Term Software License Agreement | | 3.70% | | August 9, 2025 | | 1 | | PECO | | First Mortgage Bonds | | 2.375% | | September 15, 2022 | | 350 | | BGE | | Notes | | 2.80% | | August 15, 2022 | | 250 | Pepco | | First Mortgage Bonds | | 3.05% | | April 1, 2022 | | 200 | Pepco | | Tax-Exempt Bonds | | 1.70% | | September 1, 2022 | | 110 |
Additionally, in connection with the separation, on January 31, 2022, Exelon Corporate received cash from Generation of $258 million to settle an intercompany loan that mirrored the terms and amounts of the third-party debt obligations. The loan agreements were entered into as part of the 2012 Constellation merger. See Note 16
— Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the mirror debt. During 2021, the following long-term debt was retired and/or redeemed: | | | | | | | | | | | | | | | | | | | | | | | | | | | Company | | Type | | Interest Rate | | Maturity | | Amount | Exelon | | Senior Notes | | 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 |
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, 2022 and for the first quarter of 2023 were as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | Period | | Declaration Date | | Shareholder of Record Date | | Dividend Payable Date | | Cash per Share(a) | First Quarter 2022 | | February 8, 2022 | | February 25, 2022 | | March 10, 2022 | | $ | 0.3375 | | Second Quarter 2022 | | April 26, 2022 | | May 13, 2022 | | June 10, 2022 | | $ | 0.3375 | | Third Quarter 2022 | | July 26, 2022 | | August 15, 2022 | | September 9, 2022 | | $ | 0.3375 | | Fourth Quarter 2022 | | October 28, 2022 | | November 15, 2022 | | December 9, 2022 | | $ | 0.3375 | | First Quarter 2023 | | February 14, 2023 | | February 27, 2023 | | March 10, 2023 | | $ | 0.3600 | |
___________ (a)Exelon's Board of Directors approved an updated dividend policy for 2023. The 2023 quarterly dividend will be $0.36 per share. Credit Matters and Cash Requirements 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 $4.0 billion in aggregate total commitments of which $2.1 billion was available to support additional commercial paper as of December 31, 2022, and of which no financial institution has more than 6% 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 16 — 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 2022 to fund their short-term liquidity needs, when necessary. 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.
On August 4, 2022, Exelon entered into an agreement with certain underwriters in connection with an underwritten public offering of 12.995 million shares of its common stock, no par value. The net proceeds were $563 million before expenses paid. Exelon used the proceeds, together with available cash balances, to repay $575 million in borrowings under a $1.15 billion term loan credit facility. See Note 19 — Shareholders' Equity and Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. On August 4, 2022, Exelon executed an equity distribution agreement (“Equity Distribution Agreement”) with certain sales agents and forward sellers and certain forward purchasers establishing an ATM equity distribution program under which it may offer and sell shares of its common stock, having an aggregate gross sales price of up to $1.0 billion. Exelon has no obligation to offer or sell any shares of common stock under the Equity Distribution Agreement and may at any time suspend or terminate offers and sales under the Equity Distribution Agreement. As of December 31, 2022, Exelon has not issued any shares of common stock under the ATM program and has not entered into any forward sale agreements. 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 2 — Discontinued Operations of the Combined Notes to Consolidated Financial Statements for additional information on the separation. The following table presents the size of service territories, populations ofincremental collateral that each service territory andUtility Registrant would have been required to provide in the number of customers withinevent each service territory for the Utility Registrants as ofRegistrant lost its investment grade credit rating at December 31, 2019:2022 and available credit facility capacity prior to any incremental collateral at December 31, 2022: | | | | | | | | | | | | | | | | | | | PJM Credit Policy Collateral | | Other Incremental Collateral Required(a) | | Available Credit Facility Capacity Prior to Any Incremental Collateral | ComEd | $ | 31 | | | $ | — | | | $ | 568 | | PECO | 1 | | | 71 | | | 361 | | BGE | 3 | | | 119 | | | 191 | | Pepco | 5 | | | — | | | 1 | | DPL | 6 | | | 15 | | | 185 | | ACE | 2 | | | — | | | 300 | | __________ | | | | | | | | | | | | | | | | | | | | | | 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 |
|
The Utility Registrants have the necessary authorizations(a)Represents incremental collateral related 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.procurement contracts.
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/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. 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 CEJA, 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. 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. ComEd filed a petition with the ICC seeking approval of a multi-year rate plan (MRP) for 2024-2027 on January 17, 2023. PECO's BGE’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.proceedings, with PECO utilizing a fully projected future test year while DPL and ACE utilize a historical test year. BGE’s electric and gas distribution costs and Pepco’s and DPL Maryland's electric distribution costs are currently recovered through multi-year rate case proceedings, as 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. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. 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
Exelon does not generate the electricity it delivers. The Utility Registrants' electric supply for its customers is primarily procured through contracts as requireddirected by their respective state commissions.laws and regulatory commission actions. The Utility Registrants procure electricity supply from various approved bidders including Generation. RTO spot marketor from 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.PJM operated markets.
PECO's, BGE’s, and DPL's natural gas supplies are purchased from a number of suppliers for terms of up tothat currently do not exceed three years. PECO, BGE, and DPL each have annual firm supply and transportation contracts of 132,000443,000 mmcf, 129,000268,000 mmcf, and 58,00044,000 mmcf, respectively. In addition, torespectively, for delivery of gas. To supplement gas transportation and 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 27%, 42%, and 33% of PECO's, BGE’s, and DPL's 2022-2023 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 earnwith limited exceptions, earns a return on its energy efficiency costs.costs through a regulatory asset. BGE, Pepco Maryland, DPL Maryland, and ACE earn a return on most of their energy efficiency and demand response program costs through a regulatory asset. 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 20202023 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).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.owners. 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 Following the separation on February 1, 2022, Exelon is now a Distribution and Transmission company, focused on delivering electricity and natural gas service to our customers and communities. Exelon's businesses remain focused on maintaining industry leading operational excellence, meeting or exceeding their financial commitments, ensuring timely recovery on investments to enable customer benefits, supporting clean energy policies including those that advance our jurisdictions' clean energy targets, 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 jurisdictions in which Exelon has operations have set some of the nation's leading clean energy targets and our strategy is to enable that future for all our stakeholders. The Utility Registrants invest in rate base that supports service to our customers and the community, including investments that sustain and improve reliability and resiliency and that enhance the service experience of our customers. The Utility Registrants make these investments prudently at a 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.
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 $31 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 $18 billion by the end of 2026. These investments provide greater reliability, improved service for our customers, increased capacity to accommodate new technologies and support a cleaner grid, and a stable return for the company. In August 2021, Exelon announced a Path to Clean goal to collectively reduce its operations-driven GHG emissions 50% by 2030 against a 2015 baseline and to reach net zero operations-driven GHG emissions by 2050, while supporting customers and communities in achieving their GHG reduction goals (Path to Clean). Exelon's quantitative goals include its Scope 1 and 2 GHG emissions, with the exception of Scope 2 emissions associated with system losses of electric power delivered to customers ("line losses"), and build upon Exelon's long-standing commitment to reducing our GHG emissions. Exelon's Path to Clean efforts extend beyond these quantitative goals to include efforts such as customer energy efficiency programs, which support reductions in customers' direct emissions and have the potential to reduce Exelon's Scope 3 emissions and Scope 2 line losses as well. 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 culture that promotes and embodies diversity, inclusion, innovation, and safety for their employees. In order to provide the services and products that their customers expect, the Registrants aspire to create teams that reflect the diversity of the communities that the Registrants serve. Therefore, the Registrants take steps to attract highly qualified and diverse talent and seek to create hiring and promotion practices that are equitable and neutralize any bias, including 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; mentorship programs; 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 typically conduct an employee engagement survey every other year to help identify organizational strengths and areas of opportunity for growth. 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, 2022. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Employees | | Exelon | | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Female(a)(b)(c) | | 5,300 | | | | | 1,535 | | | 752 | | | 786 | | | 1,270 | | | 329 | | | 139 | | | 109 | | People of Color(b)(c) | | 7,519 | | | | | 2,575 | | | 990 | | | 1,170 | | | 1,803 | | | 865 | | | 203 | | | 145 | | Aged <30 | | 2,026 | | | | | 721 | | | 361 | | | 286 | | | 424 | | | 169 | | | 85 | | | 61 | | Aged 30-50 | | 10,548 | | | | | 3,728 | | | 1,455 | | | 1,819 | | | 2,271 | | | 739 | | | 465 | | | 357 | | Aged >50 | | 6,489 | | | | | 1,907 | | | 1,070 | | | 1,061 | | | 1,466 | | | 442 | | | 341 | | | 203 | | Total Employees(d) | | 19,063 | | | | | 6,356 | | | 2,886 | | | 3,166 | | | 4,161 | | | 1,350 | | | 891 | | | 621 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Management(e) | | Exelon | | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Female(a)(b)(c) | | 961 | | | | | 235 | | | 139 | | | 122 | | | 206 | | | 51 | | | 13 | | | 21 | | People of Color(b)(c) | | 1,086 | | | | | 331 | | | 134 | | | 166 | | | 276 | | | 116 | | | 32 | | | 22 | | Aged <30 | | 29 | | | | | 7 | | | 9 | | | 4 | | | 6 | | | — | | | 2 | | | 2 | | Aged 30-50 | | 1,715 | | | | | 510 | | | 182 | | | 265 | | | 395 | | | 120 | | | 58 | | | 40 | | Aged >50 | | 1,286 | | | | | 363 | | | 190 | | | 163 | | | 276 | | | 61 | | | 57 | | | 40 | | Within 10 years of retirement eligibility | | 1,787 | | | | | 520 | | | 238 | | | 226 | | | 379 | | | 91 | | | 68 | | | 55 | | Total Employees in Management(d) | | 3,030 | | | | | 880 | | | 381 | | | 432 | | | 677 | | | 181 | | | 117 | | | 82 | |
__________ (a)The Registrants have a particular focus on creating an environment that attracts and retains women by enabling them to stay in the workforce, grow with the company, and move up the ranks. (b)To effectuate Exelon's pay equity goals, Exelon conducts analysis on gender and racial pay equity. (c)Information concerning women and people of color is based on self-disclosed information. (d)Total employees represents the sum of the aged categories. (e)Management is defined as executive/senior level officials and managers as well as all employees who have direct reports and/or 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 2020 to 2022. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exelon | | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Retirement Age | | 3.71 | % | | | | 4.09 | % | | 4.10 | % | | 3.48 | % | | 3.79 | % | | 3.74 | % | | 4.42 | % | | 3.88 | % | Voluntary | | 2.79 | % | | | | 2.22 | % | | 2.71 | % | | 1.76 | % | | 2.52 | % | | 2.81 | % | | 1.46 | % | | 1.84 | % | Non-Voluntary | | 0.81 | % | | | | 0.60 | % | | 1.10 | % | | 1.06 | % | | 1.02 | % | | 1.95 | % | | 0.47 | % | | 0.68 | % |
Collective Bargaining Agreements Approximately 44% 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, 2019:2022. | | | | | | | | | | | | | | | | | | | | | | | | | Total Employees Covered by CBAs | | Number of CBAs | | CBAs New and Renewed in 2022(a) | | Total Employees Under CBAs New and Renewed in 2022 | Exelon | 8,379 | | | 10 | | | 2 | | | 906 | | | | | | | | | | ComEd | 3,477 | | | 2 | | | — | | | — | | PECO | 1,368 | | | 2 | | | — | | | — | | BGE | 1,414 | | | 1 | | | — | | | — | | PHI | 2,113 | | | 5 | | | 2 | | | 906 | | Pepco | 890 | | | 1 | | | 1 | | | 890 | | DPL | 621 | | | 2 | | | — | | | — | | ACE | 401 | | | 2 | | | 1 | | | 16 | |
__________ (a)Does not include CBAs that were extended in 2022 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 |
| | — |
| | — |
|
12
| | (a) | Does not include CBAs that were extended in 2019 while negotiations are ongoing for renewal. |
Environmental Matters and Regulation General
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 delegatedAudit and Risk Committee oversees compliance with environmental laws and regulations, including environmental risks related to its Generation Oversight CommitteeExelon's operations and thefacilities, as well as SEC disclosures related to environmental matters. Exelon's Corporate Governance Committee has 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. The Exelon Board of Directors has general oversight responsibilities for ESG matters, including strategies and efforts to protect and improve the quality of the environment. 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 to the physical climate and environment, 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 climate legislation, Exelon supports the EPA moving forward with meaningful regulation of GHG emissions under the Clean Air QualityAct. Air qualityThe Registrants currently are subject to, and may become subject to additional, federal and/or state legislation and/or regulations promulgatedaddressing GHG emissions. GHG emission sources associated with the Registrants include 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, as distributors of natural gas are regulated with respect to reporting of natural gas (methane) leakage on the natural gas systems and consumer use of such natural gas.
Since its inception, Exelon has positioned itself as a leader in climate change mitigation. Exelon uses definitions and protocols provided by the EPAWorld Resources Institute for its GHG inventory. In 2021, Exelon's Scope 1 and 2 GHG emissions, as revised following its separation from Constellation, were just over 5.7 million metric tons carbon dioxide equivalent using the World Resources Institute Corporate Standard Market-based accounting. Of these emissions, 0.5 million metric tons are considered to be operations-driven and in more direct control of our employees and processes. The majority of these operations-driven emissions are fugitive emissions from the gas delivery systems of Registrants PECO, BGE, and DPL. The remaining 5.2 million metric tons, approximately 91%, are the indirect emissions associated with the operation and use of the electric distribution and transmission system and primarily consists of losses resulting from the Utility Registrant's delivery of electricity to their customers (line losses). These emissions are driven primarily by customer demand for electricity and the various statemix of generation assets supplying energy to the electric grid. The Registrants do not own generation and must comply with applicable legal and regulatory requirements governing procurement of electricity for delivery to retail customers and use of the system to support other transmission transactions. However, the Registrants do engage in efforts that help to reduce these emissions, including customer programs to drive customer energy efficiency, help to manage peak demands, and enable distributed solar generation.
In August 2021, Exelon announced a Path to Clean goal to collectively reduce their operations-driven GHG emissions 50% by 2030 against a 2015 baseline, and to reach net zero operations-driven GHG emissions by 2050, while also supporting customers and communities to achieve their clean energy and emissions goals. Exelon’s quantitative goals include its Scope 1 and 2 GHG emissions, with the exception of Scope 2 line losses, and builds upon Exelon's long-standing commitment to reducing our GHG emissions. Exelon's activities in support of the Path to Clean goal will include efficiency and clean electricity for operations, vehicle fleet electrification, equipment and processes to reduce sulfur hexafluoride (SF6) leakage, investments in natural gas infrastructure to minimize methane leaks and increase safety and reliability, and investment and collaboration to develop new technologies. Beyond 2030, Exelon recognizes that technology advancement and continued policy support will be needed to ensure achievement of Net-Zero by 2050. Exelon is laying the groundwork by partnering with national labs, universities and research consortia to research, develop, and pilot clean technologies that will be needed, as well as working with our states, jurisdictions and policy makers to understand the scope and scale of energy transformation, and needed policies and incentives, that will be needed to reach local environmental agencies impose restrictions on emissionambitions for GHG emissions reductions. The Utility Registrants are also supporting customers and communities to achieve their clean energy and emissions goals through significant energy efficiency programs. During 2023 - 2026, estimated customer program energy efficiency investments across the Utility Registrants total $3.5 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. As an energy delivery company, Exelon can play a key role in lowering GHG emissions across much of particulates, sulfur dioxide (SO2), nitrogen oxides (NOx), mercurythe economy in its service territories. In connecting end users of energy to electric and gas supply, Exelon can leverage its assets and customer interface to encourage efficient use of lower emitting resources as they become available. 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 have a goal to electrify 30% of their own vehicle fleet by 2025, increasing to 50% by 2030. Clean fuels and other air pollutantsemerging technologies can also support the transition, lessen the strain on electric system expansion, and require permitssupport energy system resiliency. Exelon, and its registrants PECO, BGE, and DPL that own gas distribution assets, are also continuing to explore these other decarbonization opportunities, supporting pilots of emerging energy technologies and clean fuels to support both operational and customer-driven emissions reductions. The energy transition may present challenges for operationthe Utility Registrants and their service territories. Exelon believes its market and business model could be significantly affected by the transition of emitting sources. Such permits have been obtainedthe energy system, such as needed by Exelon’s subsidiaries. However, due to its low emitting generation fleet comprised of nuclear,through an increased electric load and decreased demand for natural gas, hydroelectric, windpotentially accompanied by changes in technology, customer expectations, and/or regulatory structures. See ITEM 1A. RISK FACTORS. The Registrants are potentially affected by emerging technologies that could over time affect or transform the energy industry. Climate Change Adaptation The Registrants' facilities and operations are subject to the impacts of global 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 for additional information related to the Registrants' risks associated with climate change. 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 established 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. 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, but on January 20, 2021, President Biden
accepted the Agreement, which resulted in the United States’ formal re-entry on February 19, 2021. The United States has set an economy-wide target of reducing its net GHG emissions by 50-52% below 2005 levels by 2030. On November 11, 2022 at the UNFCCC Conference of the Parties (COP 27), President Biden recommitted the U.S. to these goals and detailed the significant domestic climate actions the U.S. had taken to spur a new era of clean American manufacturing, enhance energy security, and drive down the costs of clean energy for consumers in the U.S. and around the world. Federal Climate Change Legislation and Regulation.On August 16, 2022, President Biden signed the Inflation Reduction Act (IRA), which aims to reduce U.S. carbon emissions and promote economic development through investments in clean and renewable energy projects. The consumer-facing clean energy tax credits created or expanded by the IRA are intended to drive rapid adoption of energy efficiency, electric transportation, and solar compliance withenergy which would require Exelon's utilities to expand and modernize infrastructure, systems and services to integrate and optimize these resources. Regulation of GHGs from Power Plants under the FederalClean 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, challenging the rescission of the Clean Power Plan and enactment of the Affordable Clean Energy rule as unlawful. On January 19, 2021, the D.C. Circuit held the Affordable Clean Energy Rule (including its rescission of the Clean Power Plan) to be unlawful, vacated the rule, and remanded it to the EPA. The Supreme Court granted certiorari to examine the extent of the EPA's authority to regulate GHGs from power plants and, on June 30, 2022, reversed and remanded the D.C. Circuit's decision. The Supreme Court ruled that the EPA's use of generation shifting for development of standards in the Clean Power Plan went beyond Congress' intended authority under the Clean Air Act. The EPA has indicated that 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, following its separation from Constellation, Exelon no longer owns 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. Certain northeast and mid-Atlantic states (Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Pennsylvania, Rhode Island, Vermont, Virginia) currently participate in the formsRGGI. The program requires most fossil fuel-fired power plant owners and operators 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. Pennsylvania joined RGGI in April 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 expects to meet and exceed the mandate set in the Greenhouse Gas Emissions Reduction Act to reduce statewide GHG emissions 40% (from 2006 levels) by 2030, and the state’s Climate Solutions Now Act of 2022 further updates requirements with a proposal to reduce emissions 60% (from 2006 levels) by 2031. 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. Illinois’ climate bill, CEJA, establishes decarbonization requirements for the state to transition to 100% clean energy by 2050 and supports programs to improve energy efficiency, manage energy demand, attract clean energy investment and accelerate job creation. See Note 3 — Regulatory Matters of the CSAPR, regulationCombined Notes to Consolidated Financial Statements for additional information on CEJA. 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. Each of 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 acquiring sufficient bundled or unbundled credits such as RECs, CMCs, or ZECs, or paying an alternative compliance payment, and/or a combination of these compliance alternatives. The Utility Registrants are permitted to recover from coal- and oil-fired electric generating facilities under MATS, and regulationretail customers the costs of GHG emissions.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. 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 Utility 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 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 2020 for compliance with environmental remediation related to contamination at former MGP sites and other gas purification sites is expected to total $49 million which consists primarily of $45 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, 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, underthese Federal and state environmental laws. Under these laws, the Registrants are generallymay 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, which were operated by ComEd's and PECO's predecessor companies. 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 certain environmental remediation costs of the MGP sites through a provision within customer rates. BGE, Pepco, DPL, and ACE do not have material contingent liabilities relating to MGP sites. The amount to be
expended in 2023 for compliance with environmental remediation related to contamination at former MGP sites and other gas purification sites is estimated to be approximately $52 million which consists primarily of $44 million at ComEd. As of December 31, 2022, the Registrants have established appropriate contingent liabilities for environmental remediation requirements. 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 18 — 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. Global Climate Change17 Exelon has utility and generation assets, and customers, that are and will be further subject to the impacts 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.
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
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, 202014, 2023 Exelon | | | | | | | | | | | | | | | | | | | | | Name | | Age |
| Position | Position | | Period | Crane, Christopher M. | | 61 |
| | Chief Executive Officer, Exelon; | | 2012 - Present | | | | | President, Exelon | | 2008 - Present | | | | | | | | Cornew, Kenneth W. | | 54 |
| | Senior Executive Vice President and Chief Commercial Officer, Exelon; | | 2013 - Present | | | | | President and CEO, Generation | | 2013 - Present | | | | | | | | Butler, Calvin G. Jr. | | 5053 |
| | Senior Executive Vice President, Exelon; Chief Executive Officer, Exelon Utilities | | 2019 - Present | | | | | 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, PECOExelon | | 20182022 - 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 | | 20182021 - 20192022 | | | | | 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 | | 20122019 - Present2022 | | | | | | | | Nigro, Joseph | | 55 |
| | Senior Executive Vice President and Chief Financial Officer, Exelon | | 2018 - Present | | | | | Executive Vice President, Exelon; Chief Executive Officer, ConstellationExelon Utilities | | 20132019 - 20182022 | | | | | Chief Executive Officer, BGE | | 2014 - 2019 | 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
| | | | | | | | | NameJones, Jeanne | | Age43 |
| | Position | | Period | Cornew, Kenneth W. | | 54 |
| | Senior Executive Vice President and Chief CommercialFinancial Officer, Exelon;Exelon | | 20132022 - 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, GenerationCorporate Finance, Exelon | | 20102021 - 20152022 | | | | | | | | 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, GenerationComEd | | 20132018 - 2021 | | | | | | | | Glockner, David | | 62 | | | Executive Vice President, Compliance, Audit and Risk, Exelon | | 2020 - Present | | | | | Chief Compliance Officer, Citadel LLC | | 2017 - 2020 | Bauer, Matthew N. | | 43 |
| | | | Littleton, Gayle E. | | 50 | | | Executive Vice President, and Controller, GenerationGeneral Counsel, Exelon | | 20162020 - Present | | | | | Vice President and Controller, BGEPartner, Jenner & Block LLP | | 20142015 - 20162020 |
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
| | | | | | | | Quiniones, Gil | | 56 | | | Chief Executive Officer, ComEd | | 2021 - Present | | | | | President and Chief Executive Officer, New York Power Authority | | 2011 - 2021 | | | | | | | | Name | | Age |
| | Position | | Period | Innocenzo, Michael A. | | 5457 |
| | President and Chief Executive Officer, PECO | | 2018 - Present | | | | | Senior Vice President and Chief Operations Officer, PECO | | 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 Risk Officer, Exelon | | 2017 - 2020 | | | | | Vice President, Commercial Risk Management, Exelon | | 2015 - 2017 | | | | | | | | Gay, Anthony | | 54 |
| | Vice President and General Counsel, PECO | | 2019 - Present | | | | | Vice President, Governmental and External Affairs, PECO | | 2016 - 2019 | | | | | Associate General Counsel, Exelon | | 2010 - 2016 | | | | | | | | Bailey, Scott A. | | 43 |
| | Vice President and Controller, PECO | | 2012 - Present |
BGE
| | | | | | | | | Name | | Age |
| | Position | | Period | Khouzami, Carim V. | | 4448 |
| | President, BGE | | 2021 - Present | | | | | Chief Executive Officer, BGE | | 2019 - Present | | | | | Senior Vice President Chief Operating Officer,& COO, 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
| | | | | | | | | NameAnthony, J. Tyler | | Age58 |
| | Position | | Period | Velazquez, David M. | | 60 |
| | President and Chief Executive Officer, PHI, | | 2016 - Present | | | | | Executive Vice President, Pepco Holdings, Inc. | | 2009 - 2016 | | | | | President and Chief Executive Officer, Pepco, DPL, and ACE | | 20092021 - Present | | | | | | | | Anthony, J. Tyler | | 55 |
| | Senior Vice President and Chief Operating Officer, PHI, Pepco, DPL, and ACE | | 2016 - Present2021 | | | | | | | | Trpik, Joseph R. | | 53 | | | Senior Vice President Distributionand Corporate Controller, Exelon | | 2022 - Present | | | | | Interim Senior Vice President & CFO, ComEd | | 2021 - 2022 | | | | | Senior Vice President & CFO, Exelon Utilities | | 2018 - 2021 | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
ComEd | | | | | | | | | | | | | | | | | | | | | Name | | Age | | Position | | Period | Quiniones, Gil | | 56 | | | Chief Executive Officer, ComEd | | 2021 - Present | | | | | President and Chief Executive Officer, New York Power Authority | | 2011 - 2021 | | | | | | | | Donnelly, Terence R. | | 62 | | | President and Chief Operating Officer, ComEd | | 2018 - Present | | | | | | | | | | | | | | | Graham, Elisabeth J. | | 44 | | | Senior Vice President, Chief Financial Officer & Treasurer, ComEd | | 2022 - Present | | | | | Treasurer, Exelon | | 2018 - 2022 | | | | | | | | | | | | | | | Rippie, E. Glenn | | 62 | | | Senior Vice President and General Counsel, ComEd | | 2022 - Present | | | | | Senior Vice President and Deputy General Counsel, Energy Regulation, Exelon | | 2022 - Present | | | | | Partner, Jenner & Block LLP | | 2019 - 2021 | | | | | Partner and Chief Financial Officer, Rooney, Rippie & Ratnaswamy, LLP | | 2010 - 2019 | | | | | | | | Washington, Melissa | | 53 | | | Senior Vice President, Customer Operations, ComEd | | 20102021 - 2016Present | | | | | | | | | | | | 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 | | | | | | | | Binswanger, Lewis | | 63 | | | Senior Vice President, Governmental, Regulatory and External Affairs, ComEd | | 2022 - Present | | | | | Vice President, External Affairs, Nicor Gas | | 2013 - 2022 | | | | | | | | | | | | | | | | | | | | | |
PECO | | | | | | | | | | | | | | | | | | | | | Name | | Age | | Position | | Period | Innocenzo, Michael A. | | 57 | | | President and Chief Executive Officer, PECO | | 2018 - Present | | | | | | | | | | | | | | | Levine, Nicole | | 46 | | | Senior Vice President and Chief Operations Officer, PECO | | 2022 - Present | | | | | Vice President, Electrical Operations, PECO | | 2018 - 2022 | Humphrey, Marissa | | 43 | | | Senior Vice President, Chief Financial Officer and Treasurer, PECO | | 2022 - Present | | | | | Vice President, Regulatory Policy and Strategy (NJ/DE), PHI, DPL, and ACE | | 2021 - 2022 | | | | | Vice President, Finance, Exelon Utilities | | 2019 - 2020 | | | | | Vice President, Financial Planning and Analysis, PHI, Pepco, DPL, and ACE | | 2016 - 2019 | | | | | | | | Murphy, Elizabeth A. | | 63 | | | Senior Vice President, Governmental, Regulatory and External Affairs, PECO | | 2016 - Present | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Williamson, Olufunmilayo | | 44 | | | Senior Vice President, Customer Operations, PECO | | 2021 - Present | | | | | Senior Vice President, Chief Commercial Risk Officer, Exelon | | 2017 - 2020 | | | | | | | | | | | | | | | Gay, Anthony | | 57 | | | 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. | | 48 | | | President, BGE | | 2021 - Present | | | | | Chief Executive Officer, BGE | | 2019 - Present | | | | | Senior Vice President & COO, Exelon Utilities | | 2018 - 2019 | | | | | | | | Dickens, Derrick | | 58 | | | Senior Vice President and Chief Operating Officer, BGE | | 2021 - Present | | | | | Senior Vice President, Customer Operations, PHI, Pepco, DPL, and ACE | | 2020 - 2021 | | | | | Vice President, Technical Services, BGE | | 2016 - 2020 | | | | | | | | | | | | | | | Vahos, David M. | | 50 | | | Senior Vice President, Chief Financial Officer and Treasurer, BGE | | 2016 - Present | | | | | | | | | | | | | | | Núñez, Alexander G. | | 51 | | | Senior Vice President, Governmental, Regulatory and External Affairs, BGE | | 2021 - Present | | | | | Senior Vice President, Regulatory Affairs and Strategy, BGE | | 2020 - 2021 | | | | | Senior Vice President, Regulatory and External Affairs, BGE | | 2016 - 2020 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Galambos, Denise | | 60 | | | Senior Vice President, Customer Operations, BGE | | 2021 - Present | | | | | Vice President, Utility Oversight, Exelon Utilities | | 2020 - 2021 | | | | | Vice President, Human Resources, BGE | | 2018 - 2020 | | | | | | | | | | | | | | | Ralph, David | | 56 | | | Vice President and General Counsel, BGE | | 2021 - Present | | | | | Associate General Counsel, BGE | | 2019 - 2021 | | | | | Assistant General Counsel, Exelon | | 2017 - 2019 | | | | | | | |
PHI, Pepco, DPL, and ACE | | | | | | | | | | | | | | | | | | | | | Name | | Age | | Position | | Period | Anthony, J. Tyler | | 58 | | | President and Chief Executive Officer, PHI, Pepco, DPL, and ACE | | 2021 - Present | | | | | Senior Vice President and Chief Operating Officer, PHI, Pepco, DPL, and ACE | | 2016 - 2021 | | | | | | | | Olivier, Tamla | | 50 | | | 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. | | 5659 |
| | 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 | | 5046 |
| | Senior Vice President, Governmental, &Regulatory and 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 | | | | | | | | | | | | | | | Bancroft, Anne | | 56 | | | Vice President and General Counsel, PHI, Pepco, DPL, and ACE | | 20162021 - 2018Present | | | | | DeputyAssociate General Counsel, Pepco Holdings, Inc.Exelon | | 20122017 - 20162021 | | | | | | | | McGowan, Kevin M. | | 58 |
| | Vice President, Regulatory Policy and Strategy, PHI, Pepco, DPL and ACE | | 2016 - Present | Bell-Izzard, Morlon | | 57 | | Vice President, Regulatory Affairs, Pepco Holdings, Inc. | | 2012 - 2016 | | | | | | | | Dickens, Derrick | | 55 |
| | Senior Vice President, Customer Operations, PHI, Pepco, DPL, and ACE | | 20202021 - Present | | | | | Vice President, Technical Services, BGE | | 2016 - 2020 | | | | | Director, Advanced Meter Infrastructure, PECO | | 2012 - 2016 | | | | | | | | Aiken, Robert | | 53 |
| | Vice President and Controller,Customer Operations, PHI, Pepco, DPL, and ACE | | 2019 - 2021 | | | | | Director, Utility Performance Assessment, Exelon | | 2016 - Present2019 | | | | | Vice President and Controller, Generation | | 2012 - 2016 |
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: MarketRisks 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, financial condition or liquidity/cash flows due to public health crises, epidemics or pandemics, such as 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 Constellation 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 technologiesIncreasing pressure from both the private and public sectors to take actions to mitigate climate change could also result in further declines in commodity prices or demand for delivered energy. Eachpush the speed and nature of thesethis transition. These 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 14 — 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 resultbecause 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, 2019,2022, approximately 23%, 19%10%, and 18%16% of the Registrants’ available credit facilities were with European, Canadian, and Asian banks, respectively. Additionally, higher interest rates may put pressure on the Registrants’ overall liquidity profile, financial health and impact financial results. See Note 16 — 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 and Cash Requirements — 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 risksFinancial 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.
Public health crises, epidemics, or pandemics, such as COVID-19 could negatively impact the Registrants' results (All Registrants).
COVID-19 disrupted economic activity in the Registrants’ respective markets and negatively affected the Registrants’ results of operations in 2020. However, the financial impacts were not material for the years ended December 31, 2021 and December 31, 2022, other than the 2022 impairment disclosure within Note 11 — Asset Impairments. 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 our vendors, competitors or customers and customer demand as well as 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 availability of generation and its transmission, limiting Generation’s abilitycontribute to source or send power to where it is sold. In addition, drought-like conditions limiting water usage could impact Generation’s ability to run certain generating assets at full capacity. These conditions, which cannot be accurately predicted, could cause Generation to seek additional capacity at a time when wholesale markets are tight or to seek to sell excess capacity at a time when markets are weak.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 7 — Property, Plant, and Equipment, Note 11 — Asset Impairments, and Note 12 — 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, GenerationConstellation, Constellation 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 GenerationConstellation as part of the restructuring. If the third-party, GenerationConstellation, 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 Constellation'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 thatif 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 exposedRisks 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 electric and gas revenue and earnings 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, transmission, 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, along with adoption of new rate structures and constructs, or establishment of new rate cases, 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.services, adoption of new rate structures and constructs or establishment of new rate cases. 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 whichway 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 ofseveral 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 challenges to tax positions taken, tax law changes and the inherent difficulty in quantifying potential tax effects
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 13 — 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.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. Furthermore,These energy conservation programs, regulated energy consumption reduction targets, and new energy consumption technologies could cause declines in customer energy consumption resulting from the implementation of new energy conservation technologies couldand lead to a decline in the revenues of the Registrants.Registrants' earnings, if timely recovery is not allowed. See ITEM 1. BUSINESS — Environmental Matters and Regulation — Renewable and AlternativeClean Energy Portfolio Standards and "The Registrants are potentially affected by emerging technologies that could over time affect or transform the energy industry" above 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 subjectnegatively affected by challenges to adverse publicitytax positions taken, tax law changes, and reputational risks, which make them vulnerable to negative customer perception and could lead to increased regulatory oversight or other consequencesthe inherent difficulty in quantifying potential tax effects of business decisions. (All Registrants). The Registrants are required to make judgments to estimate their obligations to taxing authorities, which includes general tax positions taken and associated reserves established. Tax obligations include, but are not limited to: income, real estate, sales and use, and employment-related taxes and ongoing appeal issues related to these tax matters. All tax estimates could be subject to challenge by the subjecttax authorities. Additionally, earnings may be impacted due to changes in federal or local/state tax laws, and the inherent difficulty of public criticism. Adverse publicityestimating potential tax effects of this nature could render public service commissionsongoing business decisions. See Note 1 — Significant Accounting Policies and other regulatory and legislative authorities less likelyNote 13 — Income Taxes of the Combined Notes 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).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 18 — 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, existingor disrupt 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 operation of hydroelectric facilities (Exelon and Generation)could 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 operationsThe 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 reputations or relationships with regulatory and legislative authorities, customers, and other stakeholders, as well as their consolidated financial
statements. See Note 18 — 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 U.S. 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 relationshiprelationships with regulatory and legislative authorities, customers and other stakeholders, as well as their consolidated financial statements. See Note 18 — 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 greater riskThe Registrants periodically perform analyses to better understand long-term projections of damage shouldclimate change and how those changes in the global climate produce unusual variations in temperaturephysical environments where they operate could affect their facilities and weather patterns, resulting in more intense, frequent and extreme weather events, unprecedented levels of precipitation and a change in sea level.operations. The Registrants’Registrants primarily operate in the Midwest and East CoastMid-Atlantic 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 at greater risk of electric generation, transmission or distribution systems or natural gas production, transmission, storage or distribution systemsdamage as changes in the eventglobal climate affect temperature and weather patterns, or be placed at greater risk of a hurricane, tornado damage should climate changes result in more intense, frequent and extreme weather events, elevated levels of precipitation, sea level rise, increased surface water temperatures, and/or other severe weather event, or otherwise, could preventeffects. Over time, the Registrants are making 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 are making additional investments to adapt to changes in operational requirements to manage demand changes and customer expectations caused by climate change. Climate Change risks include changes to the normal course. energy systems due to 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 energy system transition pathways to address the effect ofreduce 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 ITEM 1.A. "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 informationinformation.
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 ofseveral 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, including sophisticated nation-state actors, 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. Additionally, the U.S. government has warned that the Ukraine conflict may increase the risks of attacks targeting critical infrastructure in the United States. A security breach of the Registrants' physical assets or information systems or those of the Registrants their competitors, vendors, business partners and interconnected entities in RTOs and ISOs, or regulators could materially impact Registrants by, among other things, impairing the operationavailability of the generation fleetelectricity and gas distributed by Registrants and/or the reliability of the transmission and distribution systemsystems, impairing the availability of vendor services and materials that the Registrants rely on to maintain their operations, or result inby leading to the theft or inappropriate release of certain types of information, including critical infrastructure information, sensitive customer, vendor, andor 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 material 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 security 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. 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 or be impacted by lack of availability of critical parts, 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. Additionally, if critical parts are not available, it may impact the timing of execution of capital projects. The RegistrantsRegistrants' consolidated financial statements could be negatively affected if they were unable to effectively manage their capital projects or raise the necessary capital.capital, or if they are deemed liable for operational failure. 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.operations as well as areas where new technologies are pertinent. The Registrants’ performance could be negatively affected by poor performance of third-party contractors that perform periodic or ongoing work (All Registrants). All Registrants rely on third-party contractors to perform operations, maintenance, and construction work. Performance standards typically are included in all contractual obligations, but poor performance may impact the capital execution plan or operations, or have adverse financial or reputational consequences. 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.and broader beneficial electrification. 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 Constellation, 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 Constellation will indemnify each other for certain liabilities. If Exelon is required to pay under these indemnities to Constellation, Exelon's financial results could be negatively impacted. The Registrants’ future financial performanceConstellation indemnities may not be sufficient to hold Exelon harmless from the full amount of liabilities for which Constellation will be allocated responsibility, and levelConstellation may not be able to satisfy its indemnification obligations in the future. Pursuant to the separation agreement and certain other agreements between Exelon and Constellation, 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 Constellation 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 profitabilitythe liabilities that Constellation has agreed to retain. Any amounts Exelon is dependent,required to pay pursuant to these indemnification obligations and other liabilities could require Exelon to divert cash that would otherwise have been used in part, on various cost reduction initiatives. The Registrantsfurtherance of its operating business. Further, the indemnities from Constellation for Exelon's benefit may encounter challenges in executing these cost reduction initiatives and not achieve the intended cost savings.
sufficient to protect Exelon against the full amount of such liabilities, and Constellation may not be able to fully satisfy its indemnification obligations. Moreover, even if Exelon ultimately succeeds in recovering from Constellation 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:
| | | | | | | | | | | | | 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) | | 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) | | Holyoke Solar | Various, MA | 2 |
| | | Solar | Base-load | 5 |
| | Three Mile Canyon | Boardman, OR | 6 |
| 51 |
| (g) | Wind | Base-load | 5 |
| (e) | Loess Hills | Rock Port, MO | 4 |
| | | Wind | Base-load | 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) | 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 |
| | 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) | 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 |
| | Mystic Jet | Charlestown, MA | 1 |
| | | Oil | Peaking | 9 |
| (j) | Total Other | 4,069 |
| | Total | 31,594 |
| |
__________
| | (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. |
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. 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 in 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, 20192022 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 | | 15 | | — | 345,000 | | 2,716 | — | | — | | — | | — | | — | | 345,000 | 2,678 | | — | | — | | — | | — | | — | 230,000 | | — | 549 | | 358 | | 769 | | 472 | | 274 | | 230,000 | — | | 550 | | 352 | | 770 | | 472 | | 272 | 138,000 | | 2,224 | 135 | | 55 | | 50 | | 586 | | 209 | | 138,000 | 2,257 | | 135 | | 55 | | 61 | | 586 | | 214 | 115,000 | | — | | 705 | | 25 | | — | | — | | 115,000 | — | | — | | 700 | | 25 | | — | | — | 69,000 | | — | 177 | | — | | — | | 569 | | 661 | | 69,000 | — | | 177 | | — | | — | | 567 | | 662 |
___________ | | (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 8 — 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 | | 12,965 | | 9,155 | | 4,130 | | 6,007 | | 7,345 | Underground | | 31,799 | 9,417 | 17,489 | 6,993 | 6,316 | 2,942 | Underground | 32,684 | | 9,590 | | 17,927 | | 7,207 | | 6,513 | | 3,007 |
Gas The following table presents PECO’s, BGE’s, and DPL’s natural gas pipeline miles at December 31, 2019:2022: | | | | | | | 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 | |
| | | | | | | | | | | | | | | | | | | PECO | | BGE | | DPL | Transmission(a) | 9 | | 152 | | 8 | Distribution | 6,990 | | 7,527 | | 2,198 | Service piping | 6,479 | | 6,761 | | 1,486 | Total | 13,478 | | 14,440 | | 3,692 |
___________ | | (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 16 — 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 18 — 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, 2020,2023, there were 974,319,565994,126,931 shares of common stock outstanding and approximately 95,06480,780 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 20152018 through 2019.2022. Cumulative total returns account for the separation of Constellation, as spin-off dividend is assumed to be reinvested as received. This performance chart assumes: •$100 invested on December 31, 20142017 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, | | 2017 | 2018 | 2019 | 2020 | 2021 | 2022 | Exelon Corporation | $100.00 | $118.33 | $123.39 | $118.59 | $167.70 | $181.67 | S&P 500 | $100.00 | $95.62 | $125.72 | $148.85 | $191.58 | $156.88 | S&P Utilities | $100.00 | $104.11 | $131.54 | $132.18 | $155.53 | $157.97 |
ComEd As of January 31, 2020,2023, there were 127,021,349127,021,394 outstanding shares of common stock, $12.50 par value, of ComEd, of which 127,002,904 shares were indirectly held by Exelon. AtAs of January 31, 2020,2023, in addition to Exelon, there were 296283 record holders of ComEd common stock. There is no established market for shares of the common stock of ComEd. PECO As of January 31, 2020,2023, 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, 2020,2023, 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, 2020,2023, Exelon indirectly held the entire membership interest in PHI. Pepco As of January 31, 2020,2023, 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, 2020,2023, 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, 2020,2023, 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 Marylandby the MDPSC and the District of Columbia.DCPSC that prohibit 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 underpursuant to the MDPSC's and DCPSC's 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 Delawareby the DEPSC and Maryland.MDPSC that prohibit 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 underpursuant to the DEPSC's and MDPSC's ratemaking precedents, of the DPSC and MDPSC or (b) DPL’s
corporate issuer or senior unsecured credit rating, or its equivalent, is rated by oneany of the three major credit rating agencies below the generally accepted definition of investment grade. No such event has occurred. ACE is subject to certain dividend restrictions established by settlements approved in New Jersey.by the NJBPU that prohibit ACE is prohibited from paying a dividend on its common shares if (a) after the dividend payment, ACE's common equity ratio would be below 48% as equity levels are calculated underpursuant to the NJBPU's ratemaking precedents, of the NJBPU or (b) ACE's senior corporate issuer or 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 notify and 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 increasefor 2023. The 2023 quarterly dividend will be $0.36 per share. As of 5% each year for the period covering 2018 through 2020, beginning with the March 2018 dividend. At December 31, 2019,2022, Exelon had retained earnings of $16,267$4,597 million, including Generation’s undistributed earnings of $3,950 million, ComEd’sComEd had retained earnings of $1,517$2,030 million, consisting of retained earnings appropriated for future dividends of $3,156 million, partially offset by $1,639 million of unappropriated accumulated deficits, PECO’sPECO had retained earnings of $1,412$1,861 million, BGE’sBGE had retained earnings of $1,776$2,075 million, and PHI'sPHI had undistributed losses of $10$352 million.
The following table sets forth Exelon’s quarterly cash dividends per share paid during 20192022 and 2018:2021: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2022 | | 2021 | (per share) | Fourth Quarter | | Third Quarter | | Second Quarter | | First Quarter | | Fourth Quarter | | Third Quarter | | Second Quarter | | First Quarter | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exelon | $ | 0.3375 | | | $ | 0.3375 | | | $ | 0.3375 | | | $ | 0.3375 | | | $ | 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 | | 2022 | | 2021 | (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 | 144 | | | 145 | | | 145 | | | 144 | | | 127 | | | 127 | | | 126 | | | 127 | | PECO | 90 |
| | 88 |
| | 90 |
| | 90 |
| | 6 |
| | 7 |
| | 6 |
| | 287 |
| PECO | 100 | | | 99 | | | 100 | | | 100 | | | 85 | | | 85 | | | 84 | | | 85 | | BGE | 55 |
| | 57 |
| | 56 |
| | 56 |
| | 52 |
| | 52 |
| | 53 |
| | 52 |
| BGE | 74 | | | 75 | | | 75 | | | 76 | | | 73 | | | 73 | | | 72 | | | 74 | | PHI | 97 |
| | 213 |
| | 88 |
| | 128 |
| | 94 |
| | 123 |
| | 38 |
| | 71 |
| PHI | 125 | | | 230 | | | 293 | | | 102 | | | 98 | | | 191 | | | 333 | | | 81 | | Pepco | 40 |
| | 101 |
| | 48 |
| | 24 |
| | 41 |
| | 78 |
| | 25 |
| | 25 |
| Pepco | 63 | | | 100 | | | 258 | | | 42 | | | 47 | | | 98 | | | 95 | | | 28 | | DPL | 34 |
| | 35 |
| | 29 |
| | 41 |
| | 38 |
| | 18 |
| | 4 |
| | 36 |
| DPL | 48 | | | 39 | | | 15 | | | 41 | | | 41 | | | 43 | | | 23 | | | 40 | | ACE | 24 |
| | 76 |
| | 12 |
| | 12 |
| | 13 |
| | 27 |
| | 10 |
| | 9 |
| ACE | 17 | | | 90 | | | 19 | | | 19 | | | 8 | | | 51 | | | 215 | | | 14 | |
First Quarter 20202023 Dividend On January 28, 2020, the ExelonFebruary 14, 2023, Exelon's Board of Directors declared a first quarter 2020 regular quarterly dividend of $0.3825$0.36 per share on Exelon’s common stock for the first quarter of 2023. The dividend is payable on Friday, March 10, 2020,2023, to shareholders of record of Exelon at the endas of the day5 p.m. Eastern time on Monday, February 20, 2020.27, 2023.
| | | | | | ITEM 6. | SELECTED FINANCIAL DATA[RESERVED] |
Exelon
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 Exelon is a utility services holding company engaged in the generation, delivery, and marketing of energy through Generation and the energy distribution and transmission businesses through ComEd, PECO, BGE, Pepco, DPL, and ACE. Exelon has elevensix reportable segments consisting of Generation’s five reportable segments (Mid-Atlantic, Midwest, New York, ERCOT and Other Power Regions), ComEd, PECO, BGE, Pepco, DPL, and ACE. 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. The following combined Management’s Discussion and Analysis of Financial Condition and Results of Operations summarizes results for the year ended December 31, 2019 compared to the year ended December 31, 2018, 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 Utility Registrants' year ended December 31, 20182021 compared to the year ended December 31, 2017,2020, refer to ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS in the 2018-Form2021 Recast Form 10-K, which was filed with the SEC on February 8, 2019.June 30, 2022. 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. There were no material impacts to Exelon from unfavorable economic conditions due to COVID-19 for the years ended December 31, 2022 and 2021, other than the 2022 impairment discussed below. The Registrants assessed long-lived assets, goodwill, and investments for recoverability. Exelon and BGE recorded a pre-tax impairment charge of $48 million in 2022 as a result of COVID-19 impacts on office use. See Note 12 — Asset Impairments for additional information related to this impairment assessment. None of the other Registrants recorded material impairment charges in 2022 as a result of COVID-19. Additionally, there were no material impairment charges recorded in 2021 as a result of COVID-19. 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 ResultsWater 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 OperationsExelon's facilities discharge water into waterways and are therefore subject to these regulations and operate under NPDES permits. GAAP ResultsUnder 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 Operations. The following table sets forth Exelon's GAAP consolidated Net Income attributablethe United States.
Where Registrants’ facilities are required to common shareholderssecure 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 Registrantthe 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 year ended December 31, 2019 comparedsituation to the same period in 2018do so. Under CERCLA, generators and 2017. For additional information regarding the financial resultstransporters of hazardous substances, as well as past and present owners and operators of hazardous waste sites, are strictly, jointly and severally liable for the years ended December 31, 2019cleanup 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 2018 seesite 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 discussionsRegistrants currently own or operate, or previously owned or operated, facilities, including Delaware, Illinois, Maryland, New Jersey, and Pennsylvania and the District of ResultsColumbia. In addition, RCRA governs treatment, storage and disposal of Operationssolid 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 Registrant.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. | | | | | | | | | | | | | | | | | | | | | | 2019 | | 2018(a) | | Favorable (unfavorable) 2019 vs. 2018 variance | | 2017(a) | | Favorable (unfavorable) 2018 vs. 2017 variance | Exelon | $ | 2,936 |
| | $ | 2,005 |
| | $ | 931 |
| | $ | 3,779 |
| | $ | (1,774 | ) | Generation | 1,125 |
| | 370 |
| | 755 |
| | 2,710 |
| | (2,340 | ) | ComEd | 688 |
| | 664 |
| | 24 |
| | 567 |
| | 97 |
| PECO | 528 |
| | 460 |
| | 68 |
| | 434 |
| | 26 |
| BGE | 360 |
| | 313 |
| | 47 |
| | 307 |
| | 6 |
| 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) | (242 | ) | | (195 | ) | | (47 | ) | | (594 | ) | | 399 |
|
__________
| | (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. |
Year Ended December 31, 2019 ComparedComEd’s and PECO’s environmental liabilities primarily arise from contamination at former MGP sites, which were operated by ComEd's and PECO's predecessor companies. ComEd, pursuant to Year Ended December 31, 2018. Net income attributablean ICC order, and PECO, pursuant to common shareholdersincreased by $931 million and diluted earnings per average common share increasedsettlements of natural gas distribution rate cases with the PAPUC, have an on-going process to $3.01 in 2019 from $2.07 in 2018 primarily due to:
Higher net unrealized and realized gains on NDT funds;
| | • | Decreased accelerated depreciation and amortization due to the early retirementrecover certain environmental remediation costs 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 and maintenance expense at Generation which includes the impacts of previous cost management programs, 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;
Regulatory rate increases at PECO,MGP sites through a provision within customer rates. BGE, Pepco, DPL, and ACE;ACE do not have material contingent liabilities relating to MGP sites. The amount to be
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;
expended in 2023 for compliance with environmental remediation related to contamination at former MGP sites and other gas purification sites is estimated to be approximately $52 million which consists primarily of $44 million at ComEd.
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. As of December 31, 2022, the Registrants have established appropriate contingent liabilities for environmental remediation requirements. In addition, the Registrants may be required 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 andmake significant additional expenditures not presently determinable for 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.environmental remediation costs.
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, 2019 as compared to 2018 and 2017:
| | | | | | | | | | | | | | | | | | | | | | | | | 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 |
|
__________
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 2019 and 2018 ranged from 26.0 percent to 29.0 percent. 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 percent and 46.2 percent for the years ended December 31, 2019 and 2018, respectively.
| | (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) | 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 2019 Transactions and Developments
Utility Rates and Base Rate 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 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. See Note 3 — Regulatory Matters and Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information on other regulatory proceedings.regarding the Registrants’ environmental matters, remediation efforts, and related impacts to the Registrants’ Consolidated Financial Statements.
Completed Utility Distribution Base Rate Case ProceedingsInformation about our Executive Officers as of February 14, 2023
Exelon | | | | | | | | | | | | | | | | | | | | | Name | | Age | | Position | | Period | Butler, Calvin G. Jr. | | 53 | | | President and Chief Executive Officer, Exelon | | 2022 - Present | | | | | Chief Operating Officer, Exelon | | 2021 - 2022 | | | | | Senior Executive Vice President, Exelon | | 2019 - 2022 | | | | | Chief Executive Officer, Exelon Utilities | | 2019 - 2022 | | | | | Chief Executive Officer, BGE | | 2014 - 2019 | | | | | | | | | | | | | | | Jones, Jeanne | | 43 | | | Executive Vice President and Chief Financial Officer, Exelon | | 2022 - Present | | | | | Senior Vice President, Corporate Finance, Exelon | | 2021 - 2022 | | | | | Senior Vice President and Chief Financial Officer, ComEd | | 2018 - 2021 | | | | | | | | Glockner, David | | 62 | | | Executive Vice President, Compliance, Audit and Risk, Exelon | | 2020 - Present | | | | | Chief Compliance Officer, Citadel LLC | | 2017 - 2020 | | | | | | | | Littleton, Gayle E. | | 50 | | | Executive Vice President, General Counsel, Exelon | | 2020 - Present | | | | | Partner, Jenner & Block LLP | | 2015 - 2020 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Quiniones, Gil | | 56 | | | Chief Executive Officer, ComEd | | 2021 - Present | | | | | President and Chief Executive Officer, New York Power Authority | | 2011 - 2021 | | | | | | | | Innocenzo, Michael A. | | 57 | | | President and Chief Executive Officer, PECO | | 2018 - Present | | | | | | | | | | | | | | | Khouzami, Carim V. | | 48 | | | President, BGE | | 2021 - Present | | | | | Chief Executive Officer, BGE | | 2019 - Present | | | | | Senior Vice President & COO, Exelon Utilities | | 2018 - 2019 | | | | | | | | Anthony, J. Tyler | | 58 | | | President and Chief Executive Officer, PHI, Pepco, DPL, and ACE | | 2021 - Present | | | | | Senior Vice President and Chief Operating Officer, PHI, Pepco, DPL, and ACE | | 2016 - 2021 | | | | | | | | Trpik, Joseph R. | | 53 | | | Senior Vice President and Corporate Controller, Exelon | | 2022 - Present | | | | | Interim Senior Vice President & CFO, ComEd | | 2021 - 2022 | | | | | Senior Vice President & CFO, Exelon Utilities | | 2018 - 2021 | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | 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 |
ComEdPending Distribution Base Rate Case Proceedings | | | | | | | | | | | | | | | | | | | | | Name | | Age | | Position | | Period | Quiniones, Gil | | 56 | | | Chief Executive Officer, ComEd | | 2021 - Present | | | | | President and Chief Executive Officer, New York Power Authority | | 2011 - 2021 | | | | | | | | Donnelly, Terence R. | | 62 | | | President and Chief Operating Officer, ComEd | | 2018 - Present | | | | | | | | | | | | | | | Graham, Elisabeth J. | | 44 | | | Senior Vice President, Chief Financial Officer & Treasurer, ComEd | | 2022 - Present | | | | | Treasurer, Exelon | | 2018 - 2022 | | | | | | | | | | | | | | | Rippie, E. Glenn | | 62 | | | Senior Vice President and General Counsel, ComEd | | 2022 - Present | | | | | Senior Vice President and Deputy General Counsel, Energy Regulation, Exelon | | 2022 - Present | | | | | Partner, Jenner & Block LLP | | 2019 - 2021 | | | | | Partner and Chief Financial Officer, Rooney, Rippie & Ratnaswamy, LLP | | 2010 - 2019 | | | | | | | | Washington, Melissa | | 53 | | | Senior Vice President, Customer Operations, 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 | | | | | | | | Binswanger, Lewis | | 63 | | | Senior Vice President, Governmental, Regulatory and External Affairs, ComEd | | 2022 - Present | | | | | Vice President, External Affairs, Nicor Gas | | 2013 - 2022 | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | 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 |
PECO
| | | | | | | | | | | | | | | | | | | | | Name | | Age | | Position | | Period | Innocenzo, Michael A. | | 57 | | | President and Chief Executive Officer, PECO | | 2018 - Present | | | | | | | | | | | | | | | Levine, Nicole | | 46 | | | Senior Vice President and Chief Operations Officer, PECO | | 2022 - Present | | | | | Vice President, Electrical Operations, PECO | | 2018 - 2022 | Humphrey, Marissa | | 43 | | | Senior Vice President, Chief Financial Officer and Treasurer, PECO | | 2022 - Present | | | | | Vice President, Regulatory Policy and Strategy (NJ/DE), PHI, DPL, and ACE | | 2021 - 2022 | | | | | Vice President, Finance, Exelon Utilities | | 2019 - 2020 | | | | | Vice President, Financial Planning and Analysis, PHI, Pepco, DPL, and ACE | | 2016 - 2019 | | | | | | | | Murphy, Elizabeth A. | | 63 | | | Senior Vice President, Governmental, Regulatory and External Affairs, PECO | | 2016 - Present | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Williamson, Olufunmilayo | | 44 | | | Senior Vice President, Customer Operations, PECO | | 2021 - Present | | | | | Senior Vice President, Chief Commercial Risk Officer, Exelon | | 2017 - 2020 | | | | | | | | | | | | | | | Gay, Anthony | | 57 | | | Vice President and General Counsel, PECO | | 2019 - Present | | | | | | | | | | | | Vice President, Governmental and External Affairs, PECO | | 2016 - 2019 | | | | | | | |
BGE
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. | | | | | | | | | | | | | | | | | | | | | Name | | Age | | Position | | Period | Khouzami, Carim V. | | 48 | | | President, BGE | | 2021 - Present | | | | | Chief Executive Officer, BGE | | 2019 - Present | | | | | Senior Vice President & COO, Exelon Utilities | | 2018 - 2019 | | | | | | | | Dickens, Derrick | | 58 | | | Senior Vice President and Chief Operating Officer, BGE | | 2021 - Present | | | | | Senior Vice President, Customer Operations, PHI, Pepco, DPL, and ACE | | 2020 - 2021 | | | | | Vice President, Technical Services, BGE | | 2016 - 2020 | | | | | | | | | | | | | | | Vahos, David M. | | 50 | | | Senior Vice President, Chief Financial Officer and Treasurer, BGE | | 2016 - Present | | | | | | | | | | | | | | | Núñez, Alexander G. | | 51 | | | Senior Vice President, Governmental, Regulatory and External Affairs, BGE | | 2021 - Present | | | | | Senior Vice President, Regulatory Affairs and Strategy, BGE | | 2020 - 2021 | | | | | Senior Vice President, Regulatory and External Affairs, BGE | | 2016 - 2020 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Galambos, Denise | | 60 | | | Senior Vice President, Customer Operations, BGE | | 2021 - Present | | | | | Vice President, Utility Oversight, Exelon Utilities | | 2020 - 2021 | | | | | Vice President, Human Resources, BGE | | 2018 - 2020 | | | | | | | | | | | | | | | Ralph, David | | 56 | | | Vice President and General Counsel, BGE | | 2021 - Present | | | | | Associate General Counsel, BGE | | 2019 - 2021 | | | | | Assistant General Counsel, Exelon | | 2017 - 2019 | | | | | | | |
| | | | | | | | | | | | | | | 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 | % |
PHI, Pepco, DPL, and ACE
| | | | | | | | | | | | | | | | | | | | | Name | | Age | | Position | | Period | Anthony, J. Tyler | | 58 | | | President and Chief Executive Officer, PHI, Pepco, DPL, and ACE | | 2021 - Present | | | | | Senior Vice President and Chief Operating Officer, PHI, Pepco, DPL, and ACE | | 2016 - 2021 | | | | | | | | Olivier, Tamla | | 50 | | | 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. | | 59 | | | Senior Vice President, Chief Financial Officer and Treasurer, PHI, Pepco, DPL, and ACE | | 2018 - Present | | | | | | | | | | | | | | | | | | | | | | Oddoye, Rodney | | 46 | | | Senior Vice President, Governmental, Regulatory and 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 | | | | | | | | | | | | | | | Bancroft, Anne | | 56 | | | Vice President and General Counsel, PHI, Pepco, DPL, and ACE | | 2021 - Present | | | | | Associate General Counsel, Exelon | | 2017 - 2021 | | | | | | | | | | | | | | | Bell-Izzard, Morlon | | 57 | | | Senior Vice President, Customer Operations, PHI, Pepco, DPL, and ACE | | 2021 - Present | | | | | Vice President, Customer Operations, PHI, Pepco, DPL, and ACE | | 2019 - 2021 | | | | | Director, Utility Performance Assessment, Exelon | | 2016 - 2019 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
PECO Transmission Formula Rate
On May 1, 2017, PECO filedEach of the Registrants operates in a request with FERC seeking approvalcomplex 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 update itsmarket 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 rates and distribution assets, their ability to access capital markets, and the impacts on their results of operations, financial condition or liquidity/cash flows due to public health crises, epidemics or pandemics, such as COVID-19, and •emerging technologies and business models, including those related to climate change the manner in which PECO’s transmission rate is determined from a fixed ratemitigation and transition to a formula rate. The formula rate will be updated annuallylow carbon economy. Risks related to ensurelegislative, regulatory, and legal factors primarily include changes to, and compliance with, the laws and regulations that under this rate customers paygovern: •utility regulatory business models, •environmental and climate policy, and •tax policy.
Risks related to operational factors primarily include: •changes in the actual costsglobal 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 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 adderdemand for being a member of a RTO. On June 27, 2017, FERC issued an Order accepting the filingenergy and suspending the proposed rates until December 1, 2017, subject to refund, and set the matter for hearing and settlement judge procedures.related services, 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 memberability of the RTO. The settlement did not have a material impact on PECO's 2017, 2018, or 2019 annualUtility 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 revenue requirements. PECO will update its rates in 2020 and refund estimated overcollections totaling approximately $28 milliondistribution facilities. Risks related to the amounts billedseparation primarilyinclude: •challenges to achieving the benefits of separation and •performance by Exelon and Constellation under the proposed rates in effect since 2017.transaction agreements, including indemnification responsibilities. Pursuant to the transmission formula rate request discussed above, PECO made its annual formula rate updates in May 2018There may be further risks 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 continuesuncertainties that are not presently known or that are not currently believed to be committedmaterial that could negatively affect the Registrants' consolidated financial statements in the future.
Risks Related to managing its costs. On October 31, 2019, Exelon announced additional annual cost savingsMarket 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 approximately $100 million, at Generation,customer self-supply of electricity. Improvements in energy storage technology, including batteries and fuel cells, could also better position customers to be achievedmeet their around-the-clock electricity requirements. Improvements in energy efficiency of lighting, appliances, equipment and building materials will also affect energy consumption by 2022. customers. Changes in power generation, storage, and use technologies could have significant effects on customer behaviors and their energy consumption. These actions are in response todevelopments could affect levels of customer-owned generation, customer expectations, and current business models and make portions of 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 implementedUtility Registrants' transmission and/or distribution facilities uneconomic prior to the next capacity auctionend of their useful lives. Increasing pressure from both the private and public sectors to take actions to mitigate climate change could also push the speed and nature of this transition. 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 PJM. If Generation’s state-supported nuclear plantsthe 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 PJMthe 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 NYISO are subjectedchanges 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 MOPR without compensation under an FRR or similar program, it could have a material adverse impact on Exelon'spension and Generation's financial
statements.OPEB plans. See Note 314 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Early Plant Retirements
Oyster Creek. Generation permanently ceased generation operations at Oyster Creek 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 DispositionsRetirement 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 September 20, 2019. As a result of the decisioncapital markets, particularly for publicly offered debt, as well as the banking and commercial paper markets, to early retire TMI, Exelonmeet their financial commitments and Generation recorded a $176 million incremental pre-tax net charge for the year ended December 31, 2019 primarily due to accelerated depreciation of the plant assets, partially offset by a benefit associated with the remeasurement of the TMI AROshort-term liquidity needs. Disruptions 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, whichcapital and credit markets in the United States or abroad could leadnegatively affect the Registrants’ ability to an early retirement. PSEG isaccess the operator of Salem and also has the decision-making authoritycapital markets or draw on their respective bank revolving credit facilities. The banks may not be able to retire Salem. In 2018, New Jersey enacted legislation that established a ZEC program that provides compensation for nuclear plants that demonstratemeet their funding commitments to the NJBPU thatRegistrants if they meet certain requirements, including thatexperience shortages of capital and liquidity or if they makeexperience excessive volumes of borrowing requests within a significant contributionshort period of time. The inability to air qualityaccess capital markets or credit facilities, and longer-term disruptions in the statecapital and that their revenues are insufficientcredit markets because 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 cover their costsworldwide financial markets, including Europe, Canada, and risks. On April 18, 2019,Asia. Disruptions in these markets could reduce or restrict 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.
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 theirRegistrants’ 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 reformssecure sufficient liquidity or secure liquidity 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 Option
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. Under the terms of the Put Option, the purchase price is to be determined by agreement of the parties, or absent such agreement, by a third-party arbitration process. Any resulting sale would be subject to the approval of the NYPSC, the FERC and the NRC. The process 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 and is estimated to be, on average, $11 million to $14 million per year, including capital and operating 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 of the Combined Notes to Consolidated Financial Statements for additional information.
Pacific Gas & Electric Bankruptcy
Generation’s Antelope Valley, a 242 MW solar facility in Lancaster, CA, 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.reasonable terms. As of December 31, 2019, Generation had2022, approximately $725 million23%, 10%, 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 were with European, Canadian, and Asian banks, respectively. Additionally, higher interest rates may put pressure on the absence of a waiver from the lender foregoing their acceleration rights, the debt was reclassified as current in Exelon’sRegistrants’ overall liquidity profile, financial health 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.
impact financial results. See Note 1116 — 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 and Cash Requirements — 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. Public health crises, epidemics, or pandemics, such as COVID-19 could negatively impact the Registrants' results (All Registrants). COVID-19 disrupted economic activity in the Registrants’ respective markets and negatively affected the Registrants’ results of operations in 2020. However, the financial impacts were not material for the years ended December 31, 2021 and December 31, 2022, other than the 2022 impairment disclosure within Note 11 — Asset Impairments. 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 our vendors, competitors or customers and customer demand as well as 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 7 — Property, Plant, and Equipment, Note 11 — Asset Impairments, and Note 12 — 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 Constellation, Constellation 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 Constellation as part of the restructuring. If the third-party, Constellation, 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 competitiveThe 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 Constellation'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 if 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 provide free cash floware highly regulated and electric and gas revenue and earnings could be negatively affected by legislative and/or regulatory actions (All Registrants). Substantial aspects of the Registrants' businesses are subject to invest primarilycomprehensive 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, transmission, 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 utilitiesUtility Registrants' respective terms and conditions of service, including their respective rates, along with adoption of new rate structures and constructs, or establishment of new rate cases, are subject to reduce debt.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). Exelon believes its strategy provides a platform for optimal success in an energy industry experiencing fundamental and sweeping change.
Exelon’s utility strategy is to improve reliability and operations and enhance the customer experience, while ensuring ratemaking mechanisms provide the utilities fair financial returns. 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, adoption of new rate basestructures and constructs or establishment of new rate cases. 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 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. 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 way 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 several 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' earnings, if timely recovery is not allowed. 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 to estimate their obligations to taxing authorities, which includes general tax positions taken and associated reserves established. Tax obligations include, but are not limited to: income, real estate, sales and use, and employment-related taxes and ongoing appeal issues related to these tax matters. All tax estimates could be subject to challenge by the tax authorities. Additionally, earnings may be impacted due to changes in federal or local/state tax laws, and the inherent difficulty of estimating potential tax effects of ongoing business decisions. See Note 1 — Significant Accounting Policies and Note 13 — 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 18 — 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, or disrupt 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 18 — 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 U.S. 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 18 — 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). The Registrants periodically perform analyses to better understand long-term projections of climate change and how those changes in the physical environments where they operate could affect their facilities and operations. The Registrants primarily operate in the Midwest and Mid-Atlantic 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 at greater risk of damage as changes in the global climate affect temperature and weather patterns, or be placed at greater risk of damage should climate changes result in more intense, frequent and extreme weather events, elevated levels of precipitation, sea level rise, increased surface water temperatures, and/or other effects. Over time, the Registrants are making 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 are making additional investments to adapt to changes in operational requirements to manage demand changes and customer expectations caused by climate change. Climate Change risks include changes to the energy systems due to 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 energy system transition pathways to reduce 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 ITEM 1.A. "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 several 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, including sophisticated nation-state actors, 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. Additionally, the U.S. government has warned that the Ukraine conflict may increase the risks of attacks targeting critical infrastructure in the United States. A security breach of the Registrants' physical assets or information systems or those of the Registrants competitors, vendors, business partners and interconnected entities in RTOs and ISOs, or regulators could materially impact Registrants by, among other things, impairing the availability of electricity and gas distributed by Registrants and/or the reliability of transmission and distribution systems, impairing the availability of vendor services and materials that the Registrants rely on to maintain their operations, or by leading to the theft or inappropriate release of certain types of information, including critical infrastructure information, sensitive customer, vendor, or employee data, or other confidential data. The risk of these 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 material 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 security 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 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. 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 or be impacted by lack of availability of critical parts, 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. Additionally, if critical parts are not available, it may impact the timing of execution of capital projects. The Registrants' consolidated financial statements could be negatively affected if they were unable to effectively manage their capital projects or raise the necessary capital, or if they are deemed liable for operational failure. 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 as well as areas where new technologies are pertinent. The Registrants’ performance could be negatively affected by poor performance of third-party contractors that perform periodic or ongoing work (All Registrants). All Registrants rely on third-party contractors to perform operations, maintenance, and construction work. Performance standards typically are included in all contractual obligations, but poor performance may impact the capital execution plan or operations, or have adverse financial or reputational consequences. 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 and broader beneficial electrification. 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 lowest reasonable costSeparation (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 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,Exelon's expectations. By separating the Utility Registrants anticipate making significant future investments in smart grid technology, transmission projects, gas infrastructure, and electric system improvement projects, providing greater reliability and improved service for ourConstellation, 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 stable returnmaterial adverse effect on Exelon's financial statements and its common stock price. In connection with the separation into two public companies, Exelon and Constellation will indemnify each other for certain liabilities. If Exelon is required to pay under these indemnities to Constellation, Exelon's financial results could be negatively impacted. The Constellation indemnities may not be sufficient to hold Exelon harmless from the full amount of liabilities for which Constellation will be allocated responsibility, and Constellation may not be able to satisfy its indemnification obligations in the future. Pursuant to the separation agreement and certain other agreements between Exelon and Constellation, 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 Constellation 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 Constellation 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 Constellation for Exelon's benefit may not be
sufficient to protect Exelon against the full amount of such liabilities, and Constellation may not be able to fully satisfy its indemnification obligations. Moreover, even if Exelon ultimately succeeds in recovering from Constellation 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.
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, 2022 were as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Voltage | Circuit Miles | (Volts) | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE | 765,000 | 90 | | — | | — | | — | | — | | — | 500,000(a) | — | | 188 | | 216 | | 109 | | 15 | | — | 345,000 | 2,678 | | — | | — | | — | | — | | — | 230,000 | — | | 550 | | 352 | | 770 | | 472 | | 272 | 138,000 | 2,257 | | 135 | | 55 | | 61 | | 586 | | 214 | 115,000 | — | | — | | 700 | | 25 | | — | | — | 69,000 | — | | 177 | | — | | — | | 567 | | 662 |
___________ (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 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 | | 12,965 | | 9,155 | | 4,130 | | 6,007 | | 7,345 | Underground | 32,684 | | 9,590 | | 17,927 | | 7,207 | | 6,513 | | 3,007 |
Gas The following table presents PECO’s, BGE’s, and DPL’s natural gas pipeline miles at December 31, 2022: | | | | | | | | | | | | | | | | | | | PECO | | BGE | | DPL | Transmission(a) | 9 | | 152 | | 8 | Distribution | 6,990 | | 7,527 | | 2,198 | Service piping | 6,479 | | 6,761 | | 1,486 | Total | 13,478 | | 14,440 | | 3,692 |
___________ (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 16 — 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 18 — 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, 2023, there were 994,126,931 shares of common stock outstanding and approximately 80,780 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, compared with the S&P 500 Stock Index and the S&P Utility Index, for the company.period 2018 through 2022. Cumulative total returns account for the separation of Constellation, as spin-off dividend is assumed to be reinvested as received. Generation’s competitive businesses createThis performance chart assumes:
•$100 invested on December 31, 2017 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, | | 2017 | 2018 | 2019 | 2020 | 2021 | 2022 | Exelon Corporation | $100.00 | $118.33 | $123.39 | $118.59 | $167.70 | $181.67 | S&P 500 | $100.00 | $95.62 | $125.72 | $148.85 | $191.58 | $156.88 | S&P Utilities | $100.00 | $104.11 | $131.54 | $132.18 | $155.53 | $157.97 |
ComEd As of January 31, 2023, there were 127,021,394 outstanding shares of common stock, $12.50 par value, of ComEd, of which 127,002,904 shares were indirectly held by Exelon. As of January 31, 2023, in addition to Exelon, there were 283 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, 2023, 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, 2023, 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, 2023, Exelon indirectly held the entire membership interest in PHI. Pepco As of January 31, 2023, 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, 2023, 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, 2023, 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 by the MDPSC and DCPSC that prohibit Pepco from paying a dividend on its common shares if (a) after the dividend payment, Pepco's equity ratio would be below 48% as calculated pursuant to the MDPSC's and DCPSC's ratemaking precedents, 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 by the DEPSC and sufficiencyMDPSC that prohibit DPL from paying a dividend on its common shares if (a) after the dividend payment, DPL's equity ratio would be below 48% as calculated pursuant to the DEPSC's and MDPSC's ratemaking precedents, or (b) DPL’s corporate issuer or senior unsecured credit rating, or its equivalent, is rated by any of the three major credit rating agencies below the generally accepted definition of investment grade. No such event has occurred. ACE is subject to certain dividend restrictions established by settlements approved by the NJBPU that prohibit ACE from paying a dividend on its common shares if (a) after the dividend payment, ACE's common equity ratio would be below 48% as calculated pursuant to the NJBPU's ratemaking precedents, or (b) ACE's senior corporate issuer or 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 notify and 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 2023. The 2023 quarterly dividend will be $0.36 per share. As of December 31, 2022, Exelon had retained earnings of $4,597 million, ComEd had retained earnings of $2,030 million, PECO had retained earnings of $1,861 million, BGE had retained earnings of $2,075 million, and PHI had undistributed losses of $352 million. The following table sets forth Exelon’s quarterly cash dividends per share paid during 2022 and 2021: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2022 | | 2021 | (per share) | Fourth Quarter | | Third Quarter | | Second Quarter | | First Quarter | | Fourth Quarter | | Third Quarter | | Second Quarter | | First Quarter | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exelon | $ | 0.3375 | | | $ | 0.3375 | | | $ | 0.3375 | | | $ | 0.3375 | | | $ | 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: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2022 | | 2021 | (in millions) | 4th Quarter | | 3rd Quarter | | 2nd Quarter | | 1st Quarter | | 4th Quarter | | 3rd Quarter | | 2nd Quarter | | 1st Quarter | ComEd | 144 | | | 145 | | | 145 | | | 144 | | | 127 | | | 127 | | | 126 | | | 127 | | PECO | 100 | | | 99 | | | 100 | | | 100 | | | 85 | | | 85 | | | 84 | | | 85 | | BGE | 74 | | | 75 | | | 75 | | | 76 | | | 73 | | | 73 | | | 72 | | | 74 | | PHI | 125 | | | 230 | | | 293 | | | 102 | | | 98 | | | 191 | | | 333 | | | 81 | | Pepco | 63 | | | 100 | | | 258 | | | 42 | | | 47 | | | 98 | | | 95 | | | 28 | | DPL | 48 | | | 39 | | | 15 | | | 41 | | | 41 | | | 43 | | | 23 | | | 40 | | ACE | 17 | | | 90 | | | 19 | | | 19 | | | 8 | | | 51 | | | 215 | | | 14 | |
First Quarter 2023 Dividend On February 14, 2023, Exelon's Board of Directors declared a raiseregular quarterly dividend of 5% each year$0.36 per share on Exelon’s common stock for the period covering 2018 through 2020, beginning with the March 2018 dividend. Various market, financial, regulatory, legislative and operational factors could affect the Registrants' success in pursuing their strategies. 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 assets in the market, solutions to which Exelon is actively pursuing in a variety of jurisdictions and venues. See ITEM 1A. RISK FACTORS for additional information regarding market and financial factors.
Exelon continues to be committed to managing its costs. In November 2017, Exelon announced a commitment for $250 million 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 Generation 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 efficiency 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 endfirst quarter of 2023. The Utility Registrants investdividend is payable on Friday, March 10, 2023, to shareholders of record of Exelon as of 5 p.m. Eastern time on Monday, February 27, 2023.
| | | | | | Item 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
(Dollars in rate base where beneficial to customersmillions except per share data, unless otherwise noted) Exelon Executive Overview Exelon is a utility services holding company engaged in the energy distribution and the community by increasing reliabilitytransmission businesses through ComEd, PECO, BGE, Pepco, DPL, and the service experience or otherwise meeting customer needs. These investments are made at the lowest reasonable cost to customers.ACE. Exelon has six reportable segments consisting of ComEd, PECO, BGE, Pepco, DPL, and 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 assets as well as explores wholesale and retail opportunities within the power and gas sectors. Generation’s long-term growth strategy is to ensure appropriate valuation of its generation assets, in part through public policy efforts, identify and capitalize on opportunities that provide generation to load matching as a means to provide stable earnings, and identify emerging technologies where strategic investments provide the option for significant future growth or influence in market development.
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.
Power Markets
Price of Fuels
The use of new technologies to recover natural gas from shale deposits is increasing natural gas supply and reserves, which places downward pressure on natural gas prices and, therefore, on wholesale 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 an increase in supply due to strong natural gas production (due to shale gas development).
FERC Inquiry on Resiliency
On August 23, 2017, the DOE staff released its report on the reliability of the electric grid. One aspect of the wide-ranging report is the DOE’s recognition that the electricity markets do not currently value 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 rule in the DOE NOPR, concluding the proposed rule did not sufficiently demonstrate there is a resiliency issue and that it proposed a remedy that did not appear to be just, reasonable and nondiscriminatory as required under the Federal Power Act. At the same time, FERC initiated a new proceeding to consider resiliency challenges 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 participant 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 operations in the U.S. jointly submitted a petition to the U.S. Department of Commerce (DOC) seeking relief under Section 232 of the Trade Expansion Act of 1962, as amended, (the Act) from imports 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% of their uranium needs from domestic mines 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, the Act authorizes the Secretary of Commerce (the Secretary) to conduct investigations to evaluate the effects of imports of any item on the national security of the U.S. The Petition alleges that the loss of a viable U.S. uranium mining industry would have a significant detrimental impact on the national, energy, and economic security of the U.S. and the ability of the country to sustain an independent nuclear fuel cycle.
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 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.
Complaint at FERC Seeking to Alter Capacity Market Default Offer Caps
On February 21, 2019, PJM's Independent Market Monitor (IMM) filed a complaint alleging that the number of performance assessment intervals used 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 for the Utility Registrants.seven separate operating subsidiary registrants, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE, which, along with Exelon, are projecting load volumescollectively referred to increase (decrease)as the Registrants. The following combined Management’s Discussion and Analysis of Financial Condition and Results of Operations is separately filed by (0.3)%, (0.7)%, (1.2)%, (0.4)%, (0.5)%Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL, and (0.4)%, respectively, in 2020ACE. However, none of the Registrants makes any representation as to information related solely to any of the other Registrants. For discussion of the Utility Registrants' year ended December 31, 2021 compared to 2019.the year ended December 31, 2020, refer to ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS in the 2021 Recast Form 10-K, which was filed with the SEC on June 30, 2022.
Retail Competition
Generation’s retail operations compete forCOVID-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 in a competitive environment, which affect the margins that Generation can earn and the volumesmeans that it is ableparamount that we keep our employees who operate our businesses safe and minimize unnecessary risk of exposure to serve. Forward natural gasthe virus by taking extra precautions for employees who work in the field and power pricesin 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 expectedreasonably likely to remain lowmaterially affect, any of the Registrants’ internal control over financial reporting. See ITEM 9A. CONTROLS AND PROCEDURES for additional information. There were no material impacts to Exelon from unfavorable economic conditions due to COVID-19 for the years ended December 31, 2022 and thus we expect retail competitors2021, other than the 2022 impairment discussed below. The Registrants assessed long-lived assets, goodwill, and investments for recoverability. Exelon and BGE recorded a pre-tax impairment charge of $48 million in 2022 as a result of COVID-19 impacts on office use. See Note 12 — Asset Impairments for additional information related to stay aggressivethis impairment assessment. None of the other Registrants recorded material impairment charges in their pursuit2022 as a result of market share, and that wholesale generators (including Generation)COVID-19. Additionally, there were no material impairment charges recorded in 2021 as a result of COVID-19. The Registrants will continue to usemonitor developments affecting 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 reduce the financial impact of market price volatility. Generation is exposed to commodity price risk associated with the unhedged portion of its electricity portfolio. Generation enters into non-derivativeworkforce, customers, 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 beensuppliers and will continuetake additional precautions that they determine to be proactivenecessary in using hedging strategiesorder 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 impacts. 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. InRegistrants cannot predict 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.
See Note 15 — Derivative Financial Instrumentsfull extent of the Combined Notes to Consolidated Financial Statementsimpacts of COVID-19, which will depend on, among other things, the rate, and ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for additional information.
The Utility Registrants mitigate commodity price risk through regulatory mechanisms that allow them to recover procurement costs from retail customers.
Environmental Legislative and Regulatory Developments
Exelon was actively involved in the Obama Administration’s development 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.
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 timingpublic perceptions of the regulatory changes are unknown, as well as the ultimate impact on Exelon’seffectiveness, of vaccinations and its subsidiaries resultsrate 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 topicresumption 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 Qualitybusiness activity.
Mercury and Air Toxics Standard Rule (MATS).
On December 16, 2011, the EPA signed a final rule to reduce emissionsTable 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.ContentsClean 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 Quality 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. 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 underUnder the federal Clean Water Act.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 In October 2015,CERCLA provides for response and removal actions coordinated by the first federal regulationEPA 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 coal combustion residuals (CCR) from power plants became effective. solid and hazardous wastes and cleanup of sites where such activities were conducted.
The rule classifies CCR as non-hazardous waste under RCRA.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 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 thatRegistrants may be asserted underliable for the new federal regulations for coal ash disposal sitescosts of remediating environmental contamination of property now or formerly owned by Generation. For these reasons, Generation is unablethem 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 predict whetherproceedings initiated by the EPA, state agencies, and/or other responsible parties under CERCLA and RCRA or similar state laws with respect to what extent ita number of sites or may ultimatelyundertake to investigate and remediate sites for which they may be held responsiblesubject to enforcement actions by an agency or third-party. ComEd’s and PECO’s environmental liabilities primarily arise from contamination at former MGP sites, which were operated by ComEd's and PECO's predecessor companies. 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 certain environmental remediation costs of the MGP sites through a provision within customer rates. BGE, Pepco, DPL, and ACE do not have material contingent liabilities relating to MGP sites. The amount to be
expended in 2023 for compliance with environmental remediation related to contamination at former MGP sites and other costs relatinggas purification sites is estimated to formerly owned coal ash disposal sites underbe approximately $52 million which consists primarily of $44 million at ComEd. As of December 31, 2022, the new regulations.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 18 — 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 14, 2023 Exelon | | | | | | | | | | | | | | | | | | | | | Name | | Age | | Position | | Period | Butler, Calvin G. Jr. | | 53 | | | President and Chief Executive Officer, Exelon | | 2022 - Present | | | | | Chief Operating Officer, Exelon | | 2021 - 2022 | | | | | Senior Executive Vice President, Exelon | | 2019 - 2022 | | | | | Chief Executive Officer, Exelon Utilities | | 2019 - 2022 | | | | | Chief Executive Officer, BGE | | 2014 - 2019 | | | | | | | | | | | | | | | Jones, Jeanne | | 43 | | | Executive Vice President and Chief Financial Officer, Exelon | | 2022 - Present | | | | | Senior Vice President, Corporate Finance, Exelon | | 2021 - 2022 | | | | | Senior Vice President and Chief Financial Officer, ComEd | | 2018 - 2021 | | | | | | | | Glockner, David | | 62 | | | Executive Vice President, Compliance, Audit and Risk, Exelon | | 2020 - Present | | | | | Chief Compliance Officer, Citadel LLC | | 2017 - 2020 | | | | | | | | Littleton, Gayle E. | | 50 | | | Executive Vice President, General Counsel, Exelon | | 2020 - Present | | | | | Partner, Jenner & Block LLP | | 2015 - 2020 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Quiniones, Gil | | 56 | | | Chief Executive Officer, ComEd | | 2021 - Present | | | | | President and Chief Executive Officer, New York Power Authority | | 2011 - 2021 | | | | | | | | Innocenzo, Michael A. | | 57 | | | President and Chief Executive Officer, PECO | | 2018 - Present | | | | | | | | | | | | | | | Khouzami, Carim V. | | 48 | | | President, BGE | | 2021 - Present | | | | | Chief Executive Officer, BGE | | 2019 - Present | | | | | Senior Vice President & COO, Exelon Utilities | | 2018 - 2019 | | | | | | | | Anthony, J. Tyler | | 58 | | | President and Chief Executive Officer, PHI, Pepco, DPL, and ACE | | 2021 - Present | | | | | Senior Vice President and Chief Operating Officer, PHI, Pepco, DPL, and ACE | | 2016 - 2021 | | | | | | | | Trpik, Joseph R. | | 53 | | | Senior Vice President and Corporate Controller, Exelon | | 2022 - Present | | | | | Interim Senior Vice President & CFO, ComEd | | 2021 - 2022 | | | | | Senior Vice President & CFO, Exelon Utilities | | 2018 - 2021 | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
ComEd | | | | | | | | | | | | | | | | | | | | | Name | | Age | | Position | | Period | Quiniones, Gil | | 56 | | | Chief Executive Officer, ComEd | | 2021 - Present | | | | | President and Chief Executive Officer, New York Power Authority | | 2011 - 2021 | | | | | | | | Donnelly, Terence R. | | 62 | | | President and Chief Operating Officer, ComEd | | 2018 - Present | | | | | | | | | | | | | | | Graham, Elisabeth J. | | 44 | | | Senior Vice President, Chief Financial Officer & Treasurer, ComEd | | 2022 - Present | | | | | Treasurer, Exelon | | 2018 - 2022 | | | | | | | | | | | | | | | Rippie, E. Glenn | | 62 | | | Senior Vice President and General Counsel, ComEd | | 2022 - Present | | | | | Senior Vice President and Deputy General Counsel, Energy Regulation, Exelon | | 2022 - Present | | | | | Partner, Jenner & Block LLP | | 2019 - 2021 | | | | | Partner and Chief Financial Officer, Rooney, Rippie & Ratnaswamy, LLP | | 2010 - 2019 | | | | | | | | Washington, Melissa | | 53 | | | Senior Vice President, Customer Operations, 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 | | | | | | | | Binswanger, Lewis | | 63 | | | Senior Vice President, Governmental, Regulatory and External Affairs, ComEd | | 2022 - Present | | | | | Vice President, External Affairs, Nicor Gas | | 2013 - 2022 | | | | | | | | | | | | | | | | | | | | | |
PECO | | | | | | | | | | | | | | | | | | | | | Name | | Age | | Position | | Period | Innocenzo, Michael A. | | 57 | | | President and Chief Executive Officer, PECO | | 2018 - Present | | | | | | | | | | | | | | | Levine, Nicole | | 46 | | | Senior Vice President and Chief Operations Officer, PECO | | 2022 - Present | | | | | Vice President, Electrical Operations, PECO | | 2018 - 2022 | Humphrey, Marissa | | 43 | | | Senior Vice President, Chief Financial Officer and Treasurer, PECO | | 2022 - Present | | | | | Vice President, Regulatory Policy and Strategy (NJ/DE), PHI, DPL, and ACE | | 2021 - 2022 | | | | | Vice President, Finance, Exelon Utilities | | 2019 - 2020 | | | | | Vice President, Financial Planning and Analysis, PHI, Pepco, DPL, and ACE | | 2016 - 2019 | | | | | | | | Murphy, Elizabeth A. | | 63 | | | Senior Vice President, Governmental, Regulatory and External Affairs, PECO | | 2016 - Present | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Williamson, Olufunmilayo | | 44 | | | Senior Vice President, Customer Operations, PECO | | 2021 - Present | | | | | Senior Vice President, Chief Commercial Risk Officer, Exelon | | 2017 - 2020 | | | | | | | | | | | | | | | Gay, Anthony | | 57 | | | 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. | | 48 | | | President, BGE | | 2021 - Present | | | | | Chief Executive Officer, BGE | | 2019 - Present | | | | | Senior Vice President & COO, Exelon Utilities | | 2018 - 2019 | | | | | | | | Dickens, Derrick | | 58 | | | Senior Vice President and Chief Operating Officer, BGE | | 2021 - Present | | | | | Senior Vice President, Customer Operations, PHI, Pepco, DPL, and ACE | | 2020 - 2021 | | | | | Vice President, Technical Services, BGE | | 2016 - 2020 | | | | | | | | | | | | | | | Vahos, David M. | | 50 | | | Senior Vice President, Chief Financial Officer and Treasurer, BGE | | 2016 - Present | | | | | | | | | | | | | | | Núñez, Alexander G. | | 51 | | | Senior Vice President, Governmental, Regulatory and External Affairs, BGE | | 2021 - Present | | | | | Senior Vice President, Regulatory Affairs and Strategy, BGE | | 2020 - 2021 | | | | | Senior Vice President, Regulatory and External Affairs, BGE | | 2016 - 2020 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Galambos, Denise | | 60 | | | Senior Vice President, Customer Operations, BGE | | 2021 - Present | | | | | Vice President, Utility Oversight, Exelon Utilities | | 2020 - 2021 | | | | | Vice President, Human Resources, BGE | | 2018 - 2020 | | | | | | | | | | | | | | | Ralph, David | | 56 | | | Vice President and General Counsel, BGE | | 2021 - Present | | | | | Associate General Counsel, BGE | | 2019 - 2021 | | | | | Assistant General Counsel, Exelon | | 2017 - 2019 | | | | | | | |
PHI, Pepco, DPL, and ACE | | | | | | | | | | | | | | | | | | | | | Name | | Age | | Position | | Period | Anthony, J. Tyler | | 58 | | | President and Chief Executive Officer, PHI, Pepco, DPL, and ACE | | 2021 - Present | | | | | Senior Vice President and Chief Operating Officer, PHI, Pepco, DPL, and ACE | | 2016 - 2021 | | | | | | | | Olivier, Tamla | | 50 | | | 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. | | 59 | | | Senior Vice President, Chief Financial Officer and Treasurer, PHI, Pepco, DPL, and ACE | | 2018 - Present | | | | | | | | | | | | | | | | | | | | | | Oddoye, Rodney | | 46 | | | Senior Vice President, Governmental, Regulatory and 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 | | | | | | | | | | | | | | | Bancroft, Anne | | 56 | | | Vice President and General Counsel, PHI, Pepco, DPL, and ACE | | 2021 - Present | | | | | Associate General Counsel, Exelon | | 2017 - 2021 | | | | | | | | | | | | | | | Bell-Izzard, Morlon | | 57 | | | Senior Vice President, Customer Operations, PHI, Pepco, DPL, and ACE | | 2021 - Present | | | | | Vice President, Customer Operations, PHI, Pepco, DPL, and ACE | | 2019 - 2021 | | | | | Director, Utility Performance Assessment, Exelon | | 2016 - 2019 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
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, financial condition or liquidity/cash flows due to public health crises, epidemics or pandemics, such as 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 Constellation 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. Increasing pressure from both the private and public sectors to take actions to mitigate climate change could also push the speed and nature of this transition. 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 14 — 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 because 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, 2022, approximately 23%, 10%, and 16% of the Registrants’ available credit facilities were with European, Canadian, and Asian banks, respectively. Additionally, higher interest rates may put pressure on the Registrants’ overall liquidity profile, financial health and impact financial results. See Note 16 — 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 and Cash Requirements — 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. Public health crises, epidemics, or pandemics, such as COVID-19 could negatively impact the Registrants' results (All Registrants). COVID-19 disrupted economic activity in the Registrants’ respective markets and negatively affected the Registrants’ results of operations in 2020. However, the financial impacts were not material for the years ended December 31, 2021 and December 31, 2022, other than the 2022 impairment disclosure within Note 11 — Asset Impairments. 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 our vendors, competitors or customers and customer demand as well as 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 7 — Property, Plant, and Equipment, Note 11 — Asset Impairments, and Note 12 — 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 Constellation, Constellation 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 Constellation as part of the restructuring. If the third-party, Constellation, 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 Constellation'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 if 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 electric and gas revenue and earnings 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, transmission, 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' respective terms and conditions of service, including their respective rates, along with adoption of new rate structures and constructs, or establishment of new rate cases, 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, adoption of new rate structures and constructs or establishment of new rate cases. 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 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. 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 matters.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 way 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 several 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' earnings, if timely recovery is not allowed. 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 to estimate their obligations to taxing authorities, which includes general tax positions taken and associated reserves established. Tax obligations include, but are not limited to: income, real estate, sales and use, and employment-related taxes and ongoing appeal issues related to these tax matters. All tax estimates could be subject to challenge by the tax authorities. Additionally, earnings may be impacted due to changes in federal or local/state tax laws, and the inherent difficulty of estimating potential tax effects of ongoing business decisions. See Note 1 — Significant Accounting Policies and Note 13 — 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 18 — 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, or disrupt 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 18 — 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 U.S. 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 18 — 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). The Registrants periodically perform analyses to better understand long-term projections of climate change and how those changes in the physical environments where they operate could affect their facilities and operations. The Registrants primarily operate in the Midwest and Mid-Atlantic 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 at greater risk of damage as changes in the global climate affect temperature and weather patterns, or be placed at greater risk of damage should climate changes result in more intense, frequent and extreme weather events, elevated levels of precipitation, sea level rise, increased surface water temperatures, and/or other effects. Over time, the Registrants are making 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 are making additional investments to adapt to changes in operational requirements to manage demand changes and customer expectations caused by climate change. Climate Change risks include changes to the energy systems due to 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 energy system transition pathways to reduce 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 ITEM 1.A. "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 several 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, including sophisticated nation-state actors, 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. Additionally, the U.S. government has warned that the Ukraine conflict may increase the risks of attacks targeting critical infrastructure in the United States. A security breach of the Registrants' physical assets or information systems or those of the Registrants competitors, vendors, business partners and interconnected entities in RTOs and ISOs, or regulators could materially impact Registrants by, among other things, impairing the availability of electricity and gas distributed by Registrants and/or the reliability of transmission and distribution systems, impairing the availability of vendor services and materials that the Registrants rely on to maintain their operations, or by leading to the theft or inappropriate release of certain types of information, including critical infrastructure information, sensitive customer, vendor, or employee data, or other confidential data. The risk of these 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 material 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 security 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 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 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. 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 or be impacted by lack of availability of critical parts, 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. Additionally, if critical parts are not available, it may impact the timing of execution of capital projects. The Registrants' consolidated financial statements could be negatively affected if they were unable to effectively manage their capital projects or raise the necessary capital, or if they are deemed liable for operational failure. 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 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 as well as areas where new technologies are pertinent. The Registrants’ performance could be negatively affected by poor performance of third-party contractors that perform periodic or ongoing work (All Registrants). All Registrants rely on third-party contractors to perform operations, maintenance, and construction work. Performance standards typically are included in all contractual obligations, but poor performance may impact the capital execution plan or operations, or have adverse financial or reputational consequences. 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 and broader beneficial electrification. 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 Constellation, 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 Constellation will indemnify each other for certain liabilities. If Exelon is required to pay under these indemnities to Constellation, Exelon's financial results could be negatively impacted. The Constellation indemnities may not be sufficient to hold Exelon harmless from the full amount of liabilities for which Constellation will be allocated responsibility, and Constellation may not be able to satisfy its indemnification obligations in the future. Pursuant to the separation agreement and certain other agreements between Exelon and Constellation, 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 Constellation 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 Constellation 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 Constellation for Exelon's benefit may not be
sufficient to protect Exelon against the full amount of such liabilities, and Constellation may not be able to fully satisfy its indemnification obligations. Moreover, even if Exelon ultimately succeeds in recovering from Constellation 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.
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, 2022 were as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Voltage | Circuit Miles | (Volts) | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE | 765,000 | 90 | | — | | — | | — | | — | | — | 500,000(a) | — | | 188 | | 216 | | 109 | | 15 | | — | 345,000 | 2,678 | | — | | — | | — | | — | | — | 230,000 | — | | 550 | | 352 | | 770 | | 472 | | 272 | 138,000 | 2,257 | | 135 | | 55 | | 61 | | 586 | | 214 | 115,000 | — | | — | | 700 | | 25 | | — | | — | 69,000 | — | | 177 | | — | | — | | 567 | | 662 |
___________ (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 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 | | 12,965 | | 9,155 | | 4,130 | | 6,007 | | 7,345 | Underground | 32,684 | | 9,590 | | 17,927 | | 7,207 | | 6,513 | | 3,007 |
Gas The following table presents PECO’s, BGE’s, and DPL’s natural gas pipeline miles at December 31, 2022: | | | | | | | | | | | | | | | | | | | PECO | | BGE | | DPL | Transmission(a) | 9 | | 152 | | 8 | Distribution | 6,990 | | 7,527 | | 2,198 | Service piping | 6,479 | | 6,761 | | 1,486 | Total | 13,478 | | 14,440 | | 3,692 |
___________ (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 16 — 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 18 — 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, 2023, there were 994,126,931 shares of common stock outstanding and approximately 80,780 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, compared with the S&P 500 Stock Index and the S&P Utility Index, for the period 2018 through 2022. Cumulative total returns account for the separation of Constellation, as spin-off dividend is assumed to be reinvested as received. This performance chart assumes: •$100 invested on December 31, 2017 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, | | 2017 | 2018 | 2019 | 2020 | 2021 | 2022 | Exelon Corporation | $100.00 | $118.33 | $123.39 | $118.59 | $167.70 | $181.67 | S&P 500 | $100.00 | $95.62 | $125.72 | $148.85 | $191.58 | $156.88 | S&P Utilities | $100.00 | $104.11 | $131.54 | $132.18 | $155.53 | $157.97 |
ComEd As of January 31, 2023, there were 127,021,394 outstanding shares of common stock, $12.50 par value, of ComEd, of which 127,002,904 shares were indirectly held by Exelon. As of January 31, 2023, in addition to Exelon, there were 283 record holders of ComEd common stock. There is no established market for shares of the common stock of ComEd. PECO As of January 31, 2023, 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, 2023, 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, 2023, Exelon indirectly held the entire membership interest in PHI. Pepco As of January 31, 2023, 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, 2023, 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, 2023, 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 by the MDPSC and DCPSC that prohibit Pepco from paying a dividend on its common shares if (a) after the dividend payment, Pepco's equity ratio would be below 48% as calculated pursuant to the MDPSC's and DCPSC's ratemaking precedents, 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 by the DEPSC and MDPSC that prohibit DPL from paying a dividend on its common shares if (a) after the dividend payment, DPL's equity ratio would be below 48% as calculated pursuant to the DEPSC's and MDPSC's ratemaking precedents, or (b) DPL’s corporate issuer or senior unsecured credit rating, or its equivalent, is rated by any of the three major credit rating agencies below the generally accepted definition of investment grade. No such event has occurred. ACE is subject to certain dividend restrictions established by settlements approved by the NJBPU that prohibit ACE from paying a dividend on its common shares if (a) after the dividend payment, ACE's common equity ratio would be below 48% as calculated pursuant to the NJBPU's ratemaking precedents, or (b) ACE's senior corporate issuer or 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 notify and 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 2023. The 2023 quarterly dividend will be $0.36 per share. As of December 31, 2022, Exelon had retained earnings of $4,597 million, ComEd had retained earnings of $2,030 million, PECO had retained earnings of $1,861 million, BGE had retained earnings of $2,075 million, and PHI had undistributed losses of $352 million. The following table sets forth Exelon’s quarterly cash dividends per share paid during 2022 and 2021: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2022 | | 2021 | (per share) | Fourth Quarter | | Third Quarter | | Second Quarter | | First Quarter | | Fourth Quarter | | Third Quarter | | Second Quarter | | First Quarter | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exelon | $ | 0.3375 | | | $ | 0.3375 | | | $ | 0.3375 | | | $ | 0.3375 | | | $ | 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: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2022 | | 2021 | (in millions) | 4th Quarter | | 3rd Quarter | | 2nd Quarter | | 1st Quarter | | 4th Quarter | | 3rd Quarter | | 2nd Quarter | | 1st Quarter | ComEd | 144 | | | 145 | | | 145 | | | 144 | | | 127 | | | 127 | | | 126 | | | 127 | | PECO | 100 | | | 99 | | | 100 | | | 100 | | | 85 | | | 85 | | | 84 | | | 85 | | BGE | 74 | | | 75 | | | 75 | | | 76 | | | 73 | | | 73 | | | 72 | | | 74 | | PHI | 125 | | | 230 | | | 293 | | | 102 | | | 98 | | | 191 | | | 333 | | | 81 | | Pepco | 63 | | | 100 | | | 258 | | | 42 | | | 47 | | | 98 | | | 95 | | | 28 | | DPL | 48 | | | 39 | | | 15 | | | 41 | | | 41 | | | 43 | | | 23 | | | 40 | | ACE | 17 | | | 90 | | | 19 | | | 19 | | | 8 | | | 51 | | | 215 | | | 14 | |
First Quarter 2023 Dividend On February 14, 2023, Exelon's Board of Directors declared a regular quarterly dividend of $0.36 per share on Exelon’s common stock for the first quarter of 2023. The dividend is payable on Friday, March 10, 2023, to shareholders of record of Exelon as of 5 p.m. Eastern time on Monday, February 27, 2023.
| | | | | | 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 Exelon is a utility services holding company engaged in the energy distribution and transmission businesses through ComEd, PECO, BGE, Pepco, DPL, and ACE. Exelon has six reportable segments consisting of 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, which, along with Exelon, are collectively referred to as the Registrants. The following combined Management’s Discussion and Analysis of Financial Condition and Results of Operations is separately filed by Exelon, 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 Utility Registrants' year ended December 31, 2021 compared to the year ended December 31, 2020, refer to ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS in the 2021 Recast Form 10-K, which was filed with the SEC on June 30, 2022. 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. There were no material impacts to Exelon from unfavorable economic conditions due to COVID-19 for the years ended December 31, 2022 and 2021, other than the 2022 impairment discussed below. The Registrants assessed long-lived assets, goodwill, and investments for recoverability. Exelon and BGE recorded a pre-tax impairment charge of $48 million in 2022 as a result of COVID-19 impacts on office use. See Note 12 — Asset Impairments for additional information related to this impairment assessment. None of the other Registrants recorded material impairment charges in 2022 as a result of COVID-19. Additionally, there were no material impairment charges recorded in 2021 as a result of COVID-19. 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 from continuing operations and the Utility Registrants' Net income for the year ended December 31, 2022 compared to the same period in 2021. For additional information regarding the financial results for the years ended December 31, 2022 and 2021 see the discussions of Results of Operations by Registrant. | | | | | | | | | | | | | | | | | | | 2022 | | 2021 | | Favorable (Unfavorable) Variance | Exelon | 2,054 | | | 1,616 | | | $ | 438 | | ComEd | 917 | | | 742 | | | 175 | | PECO | 576 | | | 504 | | | 72 | | BGE | 380 | | | 408 | | | (28) | | PHI | 608 | | | 561 | | | 47 | | Pepco | 305 | | | 296 | | | 9 | | DPL | 169 | | | 128 | | | 41 | | ACE | 148 | | | 146 | | | 2 | | Other(a) | (427) | | | (599) | | | 172 | |
__________ (a)Primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities, and other financing and investing activities. The separation of Constellation Energy Corporation, including Generation and its subsidiaries, meets the criteria for discontinued operations and as such, Generation's results of operations are presented as discontinued operations and have been excluded from Exelon's continuing operations for all periods presented. See Note 1 — Significant Accounting Policies and Note 2 — Discontinued Operations for additional information. Accounting rules require that certain BSC costs previously allocated to Generation be presented as part of Exelon’s continuing operations as these costs do not qualify as expenses of the discontinued operations. Such costs are included in Other in the table above and were $28 million and $429 million on a pre-tax basis, for the years ended December 31, 2022 and 2021, respectively. Year Ended December 31, 2022 Compared to Year Ended December 31, 2021. Net income attributable to common shareholders from continuing operationsincreased by $438 million and diluted earnings per average common share from continuing operations increased to $2.08 in 2022 from $1.65 in 2021 primarily due to: •Higher electric distribution earnings and energy efficiency earnings from higher rate base and higher allowed ROE due to an increase in treasury rates at ComEd; •The favorable impacts of rate increases at PECO, BGE, and PHI; •Favorable impacts of decreased storm costs at PECO and BGE; and •Lower BSC costs presented in Exelon’s continuing operations, which were previously allocated to Generation but do not qualify as expenses of the discontinued operation per the accounting rules. The increases were partially offset by: •An income tax expense recorded in connection with the separation primarily due to the long-term marginal state income tax rate change, the recognition of valuation allowances against the net deferred tax assets positions for certain standalone state filing jurisdictions, and nondeductible transaction costs partially offset by a one-time impact associated with a state tax benefit; •An adjustment at PECO to exclude one-time non-cash impacts associated with the remeasurement of deferred income taxes as a result of the reduction in Pennsylvania corporate income tax rate;
•Higher depreciation expense at PECO, BGE, and PHI; •Higher credit loss expense at PECO, BGE, and PHI; •Higher storm costs at PHI; and •Higher interest expense at PECO, BGE, PHI, and Exelon Corporate. Adjusted (non-GAAP) Operating Earnings. In addition to Net income, Exelon evaluates its operating performance using the measure of Adjusted (non-GAAP) operating earnings because management believes it represents earnings directly related to the ongoing operations of the business. Adjusted (non-GAAP) operating earnings exclude certain costs, expenses, gains and losses, and other specified items. This information is intended to enhance an investor’s overall understanding of year-to-year operating results and provide an indication of Exelon’s baseline operating performance excluding items that are considered by management to be not directly related to the ongoing operations of the business. In addition, this information is among the primary indicators management uses as a basis for evaluating performance, allocating resources, setting incentive compensation targets, and planning and forecasting of future periods. Adjusted (non-GAAP) operating earnings is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.
The following table provides a reconciliation between Net income attributable to common shareholders from continuing operations as determined in accordance with GAAP and Adjusted (non-GAAP) operating earnings for the year ended December 31, 2022 compared to 2021: | | | | | | | | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | | 2022 | | 2021 | (In millions, except per share data) | | | Earnings per Diluted Share | | | | Earnings per Diluted Share | Net Income Attributable to Common Shareholders from Continuing Operations | $ | 2,054 | | | $ | 2.08 | | | $ | 1,616 | | | $ | 1.65 | | Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $1 and $3, respectively) | 4 | | | — | | | 4 | | | — | | Asset Impairments (net of taxes of $10)(a) | 38 | | | 0.04 | | | — | | | — | | Cost Management Program (net of taxes of $1)(b) | — | | | — | | | 6 | | | 0.01 | | Asset Retirement Obligation (net of taxes of $2 and $1, respectively) | (4) | | | — | | | 2 | | | — | | COVID-19 Direct Costs (net of taxes of $6)(c) | — | | | — | | | 14 | | | 0.01 | | | | | | | | | | Acquisition Related Costs (net of taxes of $5)(d) | — | | | — | | | 15 | | | 0.02 | | ERP System Implementation Costs (net of taxes of $0 and $4, respectively)(e) | 1 | | | — | | | 13 | | | 0.01 | | Separation Costs (net of taxes of $10 and $21, respectively)(f) | 24 | | | 0.02 | | | 58 | | | 0.06 | | Income Tax-Related Adjustments (entire amount represents tax expense)(g) | 122 | | | 0.12 | | | 62 | | | 0.06 | | Adjusted (non-GAAP) Operating Earnings | $ | 2,239 | | | $ | 2.27 | | | $ | 1,791 | | | $ | 1.83 | |
__________ 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. The marginal statutory income tax rates for 2022 and 2021 ranged from 24.0% to 29.0%.
(a)Reflects costs related to the impairment of an office building at BGE, which are recorded in Operating and maintenance expense. (b)Primarily represents reorganization costs related to cost management programs. (c)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, which are recorded in Operating and maintenance expense. (d)Reflects certain BSC costs related to the acquisition of EDF's interest in CENG, which was completed in the third quarter of 2021, that were historically allocated to Generation but are presented as part of continuing operations in Exelon's results as these costs do not qualify as expenses of the discontinued operations per the accounting rules. (e)Reflects costs related to a multi-year ERP system implementation, which are recorded in Operating and maintenance expense. (f)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 separation, and employee-related severance costs, which are recorded in Operating and maintenance expense. (g)In 2021, for PHI, 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, for Corporate, reflects the adjustment to deferred income taxes due to changes in forecasted apportionment. In 2022, for PECO, primarily reflects an adjustment to exclude one-time non-cash impacts associated with the remeasurement of deferred income taxes as a result of the reduction in Pennsylvania corporate income tax rate. In 2022, for Corporate, in connection with the separation, Exelon recorded an income tax expense primarily due to the long-term marginal state income tax rate change, the recognition of valuation allowances against the deferred tax assets positions for certain standalone state filing jurisdictions, and nondeductible transaction costs partially offset by a one-time impact associated with a state tax benefit.
Significant 2022 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 (“the separation”). Exelon completed the separation on February 1, 2022. Constellation was newly formed and incorporated in Pennsylvania on June 15, 2021 for the purpose of separation and holds Generation. The separation represented a strategic shift that would have a major effect on Exelon’s operations and financial results. Accordingly, the separation meets the criteria for discontinued operations. See Note 2 — Discontinued Operations of the Combined Notes to Consolidated Financial Statements for additional information on the separation and discontinued operations. In connection with the separation, Exelon incurred separation costs impacting continuing operations of $34 million and $79 million on a pre-tax basis for the year ended December 31, 2022 and 2021, respectively, which are recorded in Operating and maintenance expense. These costs are excluded from Adjusted (non-GAAP) Operating Earnings. The separation 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. Equity Securities Offering On August 4, 2022, Exelon entered into an agreement with certain underwriters in connection with an underwritten public offering of 12.995 million shares of its common stock, no par value. The net proceeds were $563 million before expenses paid by Exelon. See Note 19 — Shareholders' Equity 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 2022. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on these and other regulatory proceedings.
Completed Distribution Base Rate Case Proceedings | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Registrant/Jurisdiction | | Filing Date | | Service | | Requested Revenue Requirement Increase | | Approved Revenue Requirement Increase | | Approved ROE | | Approval Date | | Rate Effective Date | ComEd - Illinois | | April 16, 2021 | | Electric | | $ | 51 | | | $ | 46 | | | 7.36 | % | | December 1, 2021 | | January 1, 2022 | | April 15, 2022 | | Electric | | 199 | | | 199 | | | 7.85 | % | | November 17, 2022 | | January 1, 2023 | PECO - Pennsylvania | | March 30, 2021 | | Electric | | 246 | | | 132 | | | N/A | | November 18, 2021 | | January 1, 2022 | | March 31, 2022 | | Natural Gas | | 82 | | | 55 | | | | October 27, 2022 | | January 1, 2023 | BGE - Maryland | | May 15, 2020 (amended September 11, 2020) | | Electric | | 203 | | | 140 | | | 9.50 | % | | December 16, 2020 | | January 1, 2021 | | | Natural Gas | | 108 | | | 74 | | | 9.65 | % | | | Pepco - District of Columbia | | May 30, 2019 (amended June 1, 2020) | | Electric | | 136 | | | 109 | | | 9.275 | % | | June 8, 2021 | | July 1, 2021 | Pepco - Maryland | | October 26, 2020 (amended March 31, 2021) | | Electric | | 104 | | | 52 | | | 9.55 | % | | June 28, 2021 | | June 28, 2021 | DPL - Maryland | | September 1, 2021 (amended December 23, 2021) | | Electric | | 27 | | | 13 | | | 9.60 | % | | March 2, 2022 | | March 2, 2022 | | May 19, 2022 | | Electric | | 38 | | | 29 | | | 9.60 | % | | December 14, 2022 | | January 1, 2023 | DPL - Delaware | | January 14, 2022 (amended August 15, 2022) | | Natural Gas | | 13 | | | 8 | | | 9.60 | % | | October 12, 2022 | | August 14, 2022 | ACE - New Jersey | | December 9, 2020 (amended February 26, 2021) | | Electric | | 67 | | | 41 | | | 9.60 | % | | July 14, 2021 | | January 1, 2022 |
Pending Distribution Base Rate Case Proceedings | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Registrant/Jurisdiction | | Filing Date | | Service | | Requested Revenue Requirement Increase | | Requested ROE | | Expected Approval Timing | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ComEd - Illinois | | January 17, 2023 | | Electric | | $ | 1,472 | | | 10.50% to 10.65% | | Fourth quarter of 2023 | DPL - Delaware | | December 15, 2022 | | Electric | | 60 | | | 10.50 | % | | Second quarter of 2024 | | | | | | | | | | | | | | | | | | | | | | |
Transmission Formula Rates The following total increases/(decreases) were included in the Utility Registrants' 2022 annual electric transmission formula rate updates. All rates are effective June 1, 2022 to May 31, 2023, subject to review by interested parties pursuant to review protocols of each Utility Registrants' tariff. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Registrant | | Initial Revenue Requirement Increase | | Annual Reconciliation (Decrease) Increase | | Total Revenue Requirement Increase | | Allowed Return on Rate Base | | Allowed ROE | ComEd | | $ | 24 | | | $ | (24) | | | $ | — | | | 8.11 | % | | 11.50 | % | PECO | | 23 | | | 16 | | | 39 | | | 7.30 | % | | 10.35 | % | BGE | | 25 | | | (4) | | | 16 | | | 7.30 | % | | 10.50 | % | Pepco | | 16 | | | 15 | | | 31 | | | 7.60 | % | | 10.50 | % | DPL | | 9 | | | 2 | | | 11 | | | 7.09 | % | | 10.50 | % | ACE | | 21 | | | 13 | | | 34 | | | 7.18 | % | | 10.50 | % |
Pennsylvania Corporate Income Tax Rate Change On July 8, 2022, Pennsylvania enacted House Bill 1342, which will permanently reduce the corporate income tax rate from 9.99% to 4.99%. The tax rate will be reduced to 8.99% for the 2023 tax year. Starting with the 2024 tax year, the rate is reduced by 0.50% annually until it reaches 4.99% in 2031. As a result of the rate change, in the third quarter of 2022, Exelon and PECO recorded a one-time decrease to deferred income taxes of $390 million with a corresponding decrease to the deferred income taxes regulatory asset of $428 million for the amounts that are expected to be settled through future customer rates and an increase to income tax expense of $38 million (net of federal taxes), which was excluded from Exelon's Adjusted (non-GAAP) Operating Earnings. The tax rate decrease is not expected to have a material ongoing impact to Exelon’s and PECO’s financial statements. See Note 13 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information. Inflation Reduction Act On August 16, 2022, the Inflation Reduction Act (IRA) was signed into law. The bill extends tax benefits for renewable technologies like solar and wind, and it creates new tax benefits for alternative clean energy sources like nuclear and hydrogen and it focuses on energy efficiency, electrification, and equity. However, the bill also implements a new 15.0% corporate minimum tax based on modified GAAP net income. Exelon estimates the IRA could result in an increase in cash taxes for Exelon of approximately $200 million per year starting in 2023. Exelon is continuing to assess the impacts of the IRA on the financial statements and will update estimates based on guidance to be issued by the U.S. Treasury in the future. Asset Impairment In the third quarter of 2022, a review of the impacts of COVID-19 on office use resulted in plans to cease the renovation and dispose of an office building at BGE before the asset was placed into service. BGE determined that the carrying value was not recoverable and that its fair value was less than carrying value. As a result, Exelon and BGE recorded a pre-tax impairment charge of $48 million in 2022, which was excluded from Exelon's Adjusted (non-GAAP) Operating Earnings. See Note 11 — Asset Impairments of the Combined Notes to Consolidated Financial Statements for additional information. ComEd's FERC Audit The Registrants are subject to periodic audits and investigations by FERC. FERC’s Division of Audits and Accounting initiated a nonpublic audit of ComEd in May 2021 evaluating ComEd’s compliance with (1) approved terms, rates and conditions of its transmission formula rate mechanism; (2) accounting requirements of the Uniform System of Accounts; (3) reporting requirements of the FERC Form 1; and (4) the requirements for record retention. The audit covered the period from January 1, 2017 through August 31, 2022. On January 17, 2023, ComEd was provided with information on a series of potential findings, including concerning ComEd's
methodology regarding the allocation of certain overhead costs to capital under FERC regulations. The final outcome and resolution of the findings or of the audit itself cannot be predicted and the results, while not reasonably estimable at this time, could be material to the Exelon and ComEd financial statements. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. 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 Illinois CleanCity of Chicago Franchise Agreement
The current ComEd Franchise Agreement with the City of Chicago (the City) has been in force 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 become effective. 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. 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. However, the City did not proceed to issue an RFP. Since that time, ComEd and the City continued to negotiate and have arrived at a proposed Chicago Franchise Agreement (CFA) and an Energy Progressand Equity Agreement (EEA). These agreements together are intended to grant ComEd the right to continue providing electric utility services using public ways within the City of Chicago, and to create a new non-profit entity to advance energy and energy-related equity projects. On February 1, 2023, the proposed CFA and EEA were introduced to the City Council. The proposed CFA and EEA remain subject to approval by the City Council and the Exelon Board. While Exelon and ComEd cannot predict the ultimate outcome of these processes, fundamental changes in the agreements 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. Infrastructure Investment and Jobs Act On March 14, 2019,November 15, 2021, President Biden signed the Clean Energy Progress$1.2 trillion Infrastructure Investment and Jobs Act was introduced(IIJA) into law. IIJA provides for approximately $550 billion in the Illinois General Assemblynew federal spending. Categories of funding include funding for a variety of infrastructure needs, including but not limited to: (1) power and grid reliability and resilience, (2) resilience for cybersecurity 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,address critical infrastructure needs, and (3) it implements reformselectric vehicle charging infrastructure for alternative fuel corridors. Federal agencies are developing guidelines to enhance consumer protectionsimplement spending programs under IIJA. The time needed to develop these guidelines will vary with some limited program applications opened as early as the first quarter of 2022. The Registrants are continuing to analyze the legislation and considering possible opportunities to apply for funding, either directly or in the state’s competitive retail electricitypotential collaborations with state and/or local
agencies 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 andkey stakeholders. The Registrants cannot predict the outcomeultimate timing and success of securing funding from programs under IIJA. ComEd and BGE applied for the Middle Mile Grant (MMG), which establishes and funds construction, improvement, or acquisition of middle mile broadband infrastructure which creates high-speed internet services. The MMG addresses inequitable broadband access by expansion and extension of the middle mile infrastructure in underserved communities. ComEd and BGE cannot predict if their applications will be approved as filed or the potential financial impact,timing of receiving any funds if any, onthey are awarded a grant. In December 2022, Exelon or Generation. Nuclear Powers Act of 2019
On April 12, 2019,and the Nuclear Powers America Act of 2019 was introducedUtility Registrants submitted 14 concept papers in response to the United States Congress, which expandsDepartment of Energy's Grid Resilience and Innovation Partnership (GRIP) program. These concept papers are focused on delivering grid resilience and grid benefits to customers and communities across the current investment tax creditExelon footprint. Eleven of the fourteen opportunities received letters of encouragement to existing nuclear power plants. The proposed legislation would providesubmit applications due in the first half of 2023. Exelon cannot predict if their applications will be approved as filed or the timing of receiving any funds if they are awarded 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 begrant.
currently operational and must have applied for an operating license renewal before 2026. Exelon and Generationthe Utility Registrants are working with legislatorssupporting three different Regional Clean Hydrogen Hub opportunities, covering all five states that Exelon operates in plus Washington D.C., that have submitted concept papers to the Department of Energy. All three opportunities have received letters of encouragement from Department of Energy to submit applications due in April 2023. The program will create networks of hydrogen producers, consumers, and stakeholders andlocal connective infrastructure to accelerate the use of hydrogen as a clean energy carrier that can deliver or store energy. Exelon cannot predict the outcomeif their applications will be approved as filed or the potential financial impact,timing of receiving any funds if any, on Exelon or Generation.they are awarded a grant.
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 ofon 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.
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 (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.
The following table illustrates the effects of changing certain ARO assumptions while holding all other assumptions constant (dollars in millions):
| | | | | 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 |
|
__________
| | (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, 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, 2019,2022, Exelon’s $6.7$6.6 billion carrying amount of goodwill consists of $2.6 billion at ComEd and $4 billion at PHI and immaterial amounts at Generation and DPL.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 testedassessed 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 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, and the passing margin from their last quantitative assessments performed. 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, and 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 2022 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 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.
See Note 1 — Significant Accounting Policies and Note 12 — Intangible Assets of 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 well as the estimated useful life of each asset 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 goodwill 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 energyelectricity contracts that Generation has acquired and the electricity contracts Exelon has 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. At Exelonacquisition and PHI, offsettingthe contract value based on the terms of each contract. 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 anythe 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 isare recorded through purchased power and fuel expense or operating revenues, depending on the nature of the underlying contract.expense. 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 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). 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 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 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 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 unitarycomposite 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 ifconducted periodically and as required by a rate regulator or if an event, regulatory action, or changechanges in retirement patterns indicate an update is necessary. For the Utility Registrants, depreciationDepreciation 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 includesinclude 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 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 EmployeeRetirement Benefits (All Registrants)
Exelon sponsors defined benefit pension plans and other postretirement employee benefitOPEB 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 ofExelon's 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 benefitOPEB 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 benefitOPEB 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 benefitOPEB plan assets and certain pension plan assets, Exelon uses fair value to calculate the MRV. Discount Rate. At December 31, 2019 and 2018, theThe discount rates wereare 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 benefitOPEB obligations. The spot rates are used to discount the estimated future benefit distribution amounts under the pension and other postretirement benefitOPEB 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'SOA 2019 base table (Pri-2012) and MP-2019MP-2021 improvement scale adjusted to a 0.75% long-term rate reached in 2035.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 (dollars in millions):constant: | | | | | | | | | | | | | | | | | | | | 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 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Actual Assumption | | | | | | | | | Actuarial Assumption | Pension | | OPEB | | Change in Assumption | | Pension | | OPEB | | Total | Change in 2022 cost: | | | | | | | | | | | | Discount rate(a) | 3.24% | | 3.20% | | 0.5% | | $ | (16) | | | $ | (2) | | | $ | (18) | | | 3.24% | | 3.20% | | (0.5)% | | 31 | | | 7 | | | 38 | | EROA | 7.00% | | 6.44% | | 0.5% | | (54) | | | (7) | | | (61) | | | 7.00% | | 6.44% | | (0.5)% | | 54 | | | 7 | | | 61 | | Change in benefit obligation at December 31, 2022: | | | | | | | | | | | | Discount rate(a) | 5.53% | | 5.51% | | 0.5% | | (508) | | | (83) | | | (591) | | | 5.53% | | 5.51% | | (0.5)% | | 655 | | | 104 | | | 759 | |
__________ | | (a) | (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 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 benefitOPEB plans.
Regulatory Accounting (Exelon and 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) 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, which could be material, would be recognized in the Consolidated Statements of Operations and Comprehensive Income and could be material.Income. The following table illustrates the gains (losses) to be included in net income 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 benefitOPEB plans that are recorded as regulatory assets in Exelon's Consolidated Balance Sheets:Sheets (before taxes) as of December 31, 2022: | | December 31, 2019 | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | | (In millions) | | (In millions) | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Gain (loss) | $ | 887 |
| | $ | 4,981 |
| | $ | 6 |
| | $ | 591 |
| | $ | (696 | ) | | $ | (18 | ) | | $ | 337 |
| | $ | (43 | ) | Gain (loss) | $ | 2,461 | | | $ | 3,697 | | | $ | (387) | | | $ | 159 | | | $ | (978) | | | $ | (211) | | | $ | 142 | | | $ | (442) | | Charge against OCI(a) | $ | 3,864 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| Charge against OCI(a) | (2,590) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
___________ | | (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. |
(a)Exelon's charge against OCI (before taxes) consists of up to $1.9 billion, $347 million, $492 million, $279 million, $113 million, and $59 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 $115 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 tables of Exelon and the Utility Registrants. For each regulatory jurisdiction in which they conduct business, Exelon and the Utility Registrants assess whether the regulatory assets and liabilities continue to meet the criteria for probable future recovery or settlementrefund 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 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 Financial 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 15 — 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 underlyingsunderlying 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 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 hedgingFor derivatives that qualify and for proprietary trading purposes are recorded atdesignated as cash flow hedges, changes in fair value througheach period are initially recorded in AOCI and recognized in earnings when the hedged transaction
affects earnings. For derivatives intended to serve as economic hedges, thatwhich are not designated for hedge accounting, for the Utility Registrants, changes in the fair value each period are generallyrecognized in earnings on the Consolidated Statement of Operations and Comprehensive Income or are recorded withas a corresponding offsetting regulatory asset or liability given likelihood of recoveringwhen there is an ability to recover or return the associated costs through customer rates.or benefits in accordance with regulatory requirements. Normal Purchases and Normal Sales Exception.NPNS. 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 of these contractsContracts that 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. RevenuesFor all NPNS derivative instruments, accounts payable is recorded when derivatives settle and expenses on contracts that qualifyexpense is recognized in earnings as NPNS are recognized when the underlying physical transactioncommodity is completed.consumed. 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 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, theThe Registrants make estimates and assumptions concerning future commodity prices, load requirements, interest rates, and 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, theThe Registrants categorize these derivatives under a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. Derivative contracts arecan be 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’derivative pricing is verified using indicative price quotations available through brokers or over-the-counter, on-lineonline 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, includingand both historical and current market data in itsthe assessment of nonperformance risk, including credit risk. The impacts of nonperformance and credit risk to date have generally not been material to the Registrants’ financial statements. Interest Rate Derivative Instruments. Exelon Corporate utilizes interest rate swaps to manage interest rate risk on existing and planned future debt issuances as well as potential fluctuations in Electric operating revenues at the corporate level in consolidation, which are directly correlated to yields on U.S. Treasury bonds under ComEd's distribution formula rate. The fair value of the swaps is calculated by discounting the future net cash flows to the present value based on the terms and conditions of the agreements and the forward interest rate curves. As these inputs are based on observable data and valuations of similar instruments, the interest rate derivatives are primarily categorized in Level 2 in the fair value hierarchy. 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 Statements for additional information regarding the Registrants’ derivative instruments. TaxationIncome Taxes (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 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.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 into the Registrants’ consolidated financial statements. Revenue RecognitionRevenues (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. markets. 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)accounting guidance to recognize revenuerevenues 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 and 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.tariffs.
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.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’Registrant’s 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 alternatealternative 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 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. 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 UncollectibleCredit Losses on Customer Accounts (UtilityReceivable (All Registrants) UtilityThe Registrants estimate the allowance for uncollectible accountscredit 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.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. UtilityThe Registrants' customer accounts are written off consistent with approved regulatory requirements. UtilityThe Registrants' allowances for uncollectible accountscredit losses will continue to be affected by changes in volume, prices, and economic conditions as well as changes in ICC, PAPUC, MDPSC, DCPSC, DPSCDEPSC, and NJBPU regulations.
Results of Operations by Registrant The Registrants' Results of Operations includes discussion of RNF, which is a financial measure not 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 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. For 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. 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 effect on Operating revenues caused by the volatility in these expenses.
Results of Operations—GenerationComEd | | | 2019 | | 2018 | | Favorable (unfavorable) 2019 vs. 2018 variance | | 2017 | | Favorable (unfavorable) 2018 vs. 2017 variance | | 2022 | | 2021 | | (Unfavorable) Favorable Variance | Operating revenues | $ | 18,924 |
| | $ | 20,437 |
| | $ | (1,513 | ) | | $ | 18,500 |
| | $ | 1,937 |
| Operating revenues | $ | 5,761 | | | $ | 6,406 | | | $ | (645) | | 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 expenses | | Operating expenses | | Purchased power | | Purchased power | 1,109 | | | 2,271 | | | 1,162 | | Operating and maintenance | 4,718 |
| | 5,464 |
| | 746 |
| | 6,299 |
| | 835 |
| Operating and maintenance | 1,412 | | | 1,355 | | | (57) | | Depreciation and amortization | 1,535 |
| | 1,797 |
| | 262 |
| | 1,457 |
| | (340 | ) | Depreciation and amortization | 1,323 | | | 1,205 | | | (118) | | Taxes other than income taxes | 519 |
| | 556 |
| | 37 |
| | 555 |
| | (1 | ) | Taxes other than income taxes | 374 | | | 320 | | | (54) | | 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 | ) | | Total operating expenses | | Total operating expenses | 4,218 | | | 5,151 | | | 933 | | Gain on sales of assets | | Gain on sales of assets | (2) | | | — | | | (2) | | Operating income | 1,323 |
|
| 975 |
|
| 348 |
| | 947 |
| | 28 |
| Operating income | 1,541 | | | 1,255 | | | 286 | | Other income and (deductions) | | | | | | | | |
| Other income and (deductions) | | | | | | Interest expense | (429 | ) | | (432 | ) | | 3 |
| | (440 | ) | | 8 |
| | Interest expense, net | | Interest expense, net | (414) | | | (389) | | | (25) | | Other, net | 1,023 |
| | (178 | ) | | 1,201 |
| | 948 |
| | (1,126 | ) | Other, net | 54 | | | 48 | | | 6 | | Total other income and (deductions) | 594 |
|
| (610 | ) |
| 1,204 |
| | 508 |
| | (1,118 | ) | Total other income and (deductions) | (360) | | | (341) | | | (19) | | Income before income taxes | 1,917 |
|
| 365 |
|
| 1,552 |
| | 1,455 |
| | (1,090 | ) | Income before income taxes | 1,181 | | | 914 | | | 267 | | Income taxes | 516 |
| | (108 | ) | | (624 | ) | | (1,376 | ) | | (1,268 | ) | Income taxes | 264 | | | 172 | | | (92) | | Equity in losses of unconsolidated affiliates | (184 | ) | | (30 | ) | | (154 | ) | | (33 | ) | | 3 |
| | Net income | 1,217 |
|
| 443 |
|
| 774 |
| | 2,798 |
| | (2,355 | ) | Net income | $ | 917 | | | $ | 742 | | | $ | 175 | | 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, 20192022 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 credits2021.
|
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. 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. Further, the following activities are not allocated to a region and are reported in Other: accelerated nuclear fuel amortization associated with nuclear decommissioning; and other miscellaneous revenues.
Generation evaluates 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) See Note 15 — Derivative Financial Instruments for additional information on mark-to-market losses.
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.
| | | | | | | | 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 research and development claims, renewable tax credits and one-time adjustments. 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$175 million primarily due to higherincreases in electric distribution transmission and energy efficiency formula rate earnings (reflecting higher allowed ROE due to an increase in U.S. Treasury rates and the impacts of higher rate base, partially offset by lower allowed electric distribution ROE due to a decrease in treasury rates)base).
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 RNFOperating revenues consisted of the following: | | | | | | | 2022 vs. 2021 | | Increase (Decrease) | Distribution | $ | 310 | | Transmission | 65 | | Energy efficiency | 65 | | Other | 12 | | 452 | | Regulatory required programs | (1,097) | | Total decrease | $ | (645) | |
| | | | | | 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 raterevenue 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. DuringElectric distribution revenue increased during the year ended December 31, 2019, as2022, compared to the same period in 2018, electric distribution revenue increased primarily2021, due to higher allowed ROE due to an increase in U.S. Treasury rates, the impact of a 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 Mattershigher fully recoverable costs.
Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recoveredrecovered, 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. DuringTransmission revenues increased during the year ended December 31, 2019, as2022, compared to the same period in 2018, transmission revenue increased2021, primarily due to the impact of increased peak load,a higher rate base 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. 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 fluctuationsfluctuations in the underlying costs, investments being recovered, and allowed ROE. Energy efficiency revenue increased during the year ended December 31, 2022, compared to the same period in 2021, primarily due to higher allowed ROE due to an increase in U.S. Treasury rates, the impact of a higher rate base, and increased regulatory asset amortization, which is fully recoverable. Other Revenue primarily includes assistance provided to other utilities through mutual assistance programs. Other revenue increased for the year ended December 31, 2019, as2022, compared to the same period in 2018,2021, which primarily duereflects 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 impact of higher rate basecredit loss expense tariff, environmental costs associated with MGP sites, ETAC, and increased regulatory asset amortization.costs related to electricity, ZEC, CMC, and REC procurement. 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. Seeinformation regarding CMCs. ETAC is a retail customer surcharge collected by electric utilities operating in Illinois established by CEJA and remitted to an Illinois state agency for programs to support clean energy jobs and training. The riders are designed to provide full and current cost recovery. The costs of these programs are included in Purchased power expense, Operating and maintenance expense, discussion belowDepreciation 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 additional information on this tariff.
Other revenue includes rental revenue, revenueall 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 late payment charges, mutual assistance revenuesthe electricity. For customers that choose to purchase electric generation from ComEd, ComEd is permitted to recover the electricity, ZEC, CMC, and recoveries of environmentalREC procurement 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 hurricanewithout mark-up and winter storm restoration efforts that occurred in Q1 2018. Antherefore records equal and offsetting amount was includedamounts in Operating revenues and maintenance expense.Purchased power expense related to the electricity, ZECs, CMCs, and RECs.
See Note 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ComEd's revenue disaggregation. The decrease of $1,162 million for the year ended December 31, 2022, compared to the same period in 2021, in Purchased power expense is primarily due to the CMCs from the participating nuclear-powered generating facilities. This favorability is offset by a decrease in Operating revenues as part of regulatory required programs. See Note 3 - Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information regarding CMCs.
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 plans2022 vs. 2021 |
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.Increase (Decrease) |
| | (c)Labor, other benefits, contracting, and materials | ComEd is allowed to recover from or refund to customers the difference between its annual uncollectible accounts$ | 57 | | | | Storm-related costs | 13 | | | | BSC Costs | 13 | | | | Pension and non-pension postretirement benefits 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. | (30) | | | | Other | 5 | | | | | 58 | | | | Regulatory required programs(a) | (1) | | | | Total increase | $ | 57 | | | | | | | | | | | | | | | | | | | |
__________ (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 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 2019.2022 vs. 2021 |
| | (b) | IncludesIncrease | | | Depreciation and amortization of ComEd's energy efficiency formula rate regulatory asset.(a) | $ | 63 | | | | Regulatory asset amortization(b) | 55 | | | | | | | | Total increase | $ | 118 | | | |
__________ (a)Reflects ongoing capital expenditures. (b)Includes amortization of ComEd's energy efficiency formula rate regulatory asset.
Taxes other than income taxes increased by $54 million for the year December 31, 2022, compared to the same period in 2021, primarily due to taxes related to ETAC, which is recovered through Operating revenues. Interest expense, net increased $25 million for the year ended December 31, 2022, compared to the same period in 2021, primarily due to the issuance of debt in 2021 and 2022. Effective income tax rates were 22.4%and 18.8% for the years ended December 31, 20192022 and 2018, were 19.2% and 20.2% ,2021, 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 | | 2022 | | 2021 | | Favorable (Unfavorable) Variance | Operating revenues | $ | 3,100 |
| | $ | 3,038 |
| | $ | 62 |
| | $ | 2,870 |
| | $ | 168 |
| Operating revenues | $ | 3,903 | | | $ | 3,198 | | | $ | 705 | | 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 expenses | | Operating expenses | | Purchased power and fuel | | Purchased power and fuel | 1,535 | | | 1,081 | | | (454) | | Operating and maintenance | 861 |
| | 898 |
| | 37 |
| | 806 |
| | (92 | ) | Operating and maintenance | 992 | | | 934 | | | (58) | | Depreciation and amortization | 333 |
| | 301 |
| | (32 | ) | | 286 |
| | (15 | ) | Depreciation and amortization | 373 | | | 348 | | | (25) | | Taxes other than income taxes | 165 |
| | 163 |
| | (2 | ) | | 154 |
| | (9 | ) | Taxes other than income taxes | 202 | | | 184 | | | (18) | | Total other operating expenses | 1,359 |
| | 1,362 |
| | 3 |
| | 1,246 |
| | (116 | ) | | Gain on sales of assets | 1 |
| | 1 |
| | — |
| | — |
| | 1 |
| | Total operating expenses | | Total operating expenses | 3,102 | | | 2,547 | | | (555) | | | Operating income | 713 |
| | 587 |
| | 126 |
| | 655 |
| | (68 | ) | Operating income | 801 | | | 651 | | | 150 | | Other income and (deductions) | | | | | | | | | | Other income and (deductions) | | | | | | Interest expense, net | (136 | ) | | (129 | ) | | (7 | ) | | (126 | ) | | (3 | ) | Interest expense, net | (177) | | | (161) | | | (16) | | Other, net | 16 |
| | 8 |
| | 8 |
| | 9 |
| | (1 | ) | Other, net | 31 | | | 26 | | | 5 | | Total other income and (deductions) | (120 | ) | | (121 | ) | | 1 |
| | (117 | ) | | (4 | ) | Total other income and (deductions) | (146) | | | (135) | | | (11) | | Income before income taxes | 593 |
| | 466 |
| | 127 |
| | 538 |
| | (72 | ) | Income before income taxes | 655 | | | 516 | | | 139 | | Income taxes | 65 |
| | 6 |
| | (59 | ) | | 104 |
| | 98 |
| Income taxes | 79 | | | 12 | | | (67) | | | Net income | $ | 528 |
| | $ | 460 |
| | $ | 68 |
| | $ | 434 |
| | $ | 26 |
| Net income | $ | 576 | | | $ | 504 | | | $ | 72 | |
Year Ended December 31, 20192022 Compared to Year Ended December 31, 2018.2021. Net income increased by $68$72 million, primarily due to higherincreases in electric distribution rates that became effective January 2019, higher naturaland gas distribution rates and lowera decrease in storm costs, partially offset by unfavorable weather conditionsthe one-time non-cash impacts associated with the Pennsylvania corporate income tax legislation passed in July 2022, and volume. Revenues Net of Purchased Powerincreases in depreciation expense, credit loss expense, and Fuel Expense. interest 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 RNFOperating revenues 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 |
|
| | | | | | | | | | | | | | | | | | | 2022 vs. 2021 | | Increase (Decrease) | | Electric | | Gas | | Total | Weather | $ | 32 | | | $ | 10 | | | $ | 42 | | Volume | (21) | | | 8 | | | (13) | | Pricing | 138 | | | 25 | | | 163 | | Transmission | 15 | | | — | | | 15 | | Other | 15 | | | 6 | | | 21 | | | 179 | | | 49 | | | 228 | | Regulatory required programs | 327 | | | 150 | | | 477 | | Total increase | $ | 506 | | | $ | 199 | | | $ | 705 | |
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, 20192022 compared to the same period in 2018 RNF was decreased by2021, Operating revenues related to weather increased due to the impact of unfavorablefavorable 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, 2019 and December 31, 20182022 compared to the same periodsperiod in 2018 and 2017, respectively,2021 and normal weather consisted of the following:
| | | | | | | | | | | | | For the Years Ended December 31, | | | | % Change | | For the Years Ended December 31, | | | | % Change | | Heating and Cooling Degree-Days | 2019 | | 2018 | | Normal | | 2019 vs. 2018 | | 2019 vs. Normal | | PECO Service Territory | | PECO Service Territory | 2022 | | 2021 | | Normal | | 2022 vs. 2021 | | 2022 vs. Normal | Heating Degree-Days | 4,307 |
| | 4,539 |
| | 4,458 |
| | (5.1 | )% | | (3.4 | )% | Heating Degree-Days | 4,135 | | | 3,946 | | | 4,408 | | | 4.8 | % | | (6.2) | % | Cooling Degree-Days | 1,610 |
| | 1,584 |
| | 1,415 |
| | 1.6 | % | | 13.8 | % | Cooling Degree-Days | 1,743 | | | 1,586 | | | 1,443 | | | 9.9 | % | | 20.8 | % |
Volume. Electric volume, exclusive of the effects of weather, for the year ended December 31, 20192022 compared to the same period in 2018,2021, decreased due to lower customer usages for residential, commercial and industrial electric classes, partially offset by the impact of customer growth.unfavorable load change. Natural gas volume for the year ended December 31, 20192022 compared to the same period in 2018,2021, increased due to customer and economic growth.favorable load change. | | Electric Retail Deliveries to Customers (in GWhs) | 2019 | | 2018 | | % Change 2019 vs. 2018 | | Weather - Normal % Change(b) | Electric Retail Deliveries to Customers (in GWhs) | 2022 | | 2021 | | % Change | | Weather - Normal % Change(b) | Retail Deliveries (a) | | | | | | | | | Residential | 13,650 |
| | 14,005 |
| | (2.5 | )% | | (1.4 | )% | Residential | 14,379 | | | 14,262 | | | 0.8 | % | | (1.8) | % | Small commercial & industrial | 7,983 |
| | 8,177 |
| | (2.4 | )% | | (1.2 | )% | Small commercial & industrial | 7,701 | | | 7,597 | | | 1.4 | % | | 0.4 | % | Large commercial & industrial | 14,958 |
| | 15,516 |
| | (3.6 | )% | | (3.4 | )% | Large commercial & industrial | 14,046 | | | 14,003 | | | 0.3 | % | | — | % | Public authorities & electric railroads | 725 |
| | 761 |
| | (4.7 | )% | | (5.0 | )% | Public authorities & electric railroads | 638 | | | 559 | | | 14.1 | % | | 14.1 | % | Total electric retail deliveries | 37,316 |
| | 38,459 |
| | (3.0 | )% | | (2.3 | )% | | Total electric retail deliveries(a) | | Total electric retail deliveries(a) | 36,764 | | | 36,421 | | | 0.9 | % | | (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. |
(a)Reflects delivery volumes from customers purchasing electricity directly from PECO and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges.
(b)Reflects the change in delivery volumes assuming normalized weather based on the historical 30-year average. | | | | | | | | 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 |
|
| | | | | | | | | | | | | As of December 31, | Number of Electric Customers | 2022 | | 2021 | Residential | 1,525,635 | | | 1,517,806 | | Small commercial & industrial | 155,576 | | | 155,308 | | Large commercial & industrial | 3,121 | | | 3,107 | | Public authorities & electric railroads | 10,393 | | | 10,306 | | Total | 1,694,725 | | | 1,686,527 | |
| | Natural Gas Deliveries to customers (in mmcf) | 2019 | | 2018 | | % Change 2019 vs. 2018 | | Weather - Normal % Change(b) | Natural Gas Deliveries to customers (in mmcf) | 2022 | | 2021 | | % Change | | Weather - Normal % Change(b) | Retail Deliveries (a) | | | | | | | | | Residential | 40,196 |
| | 43,450 |
| | (7.5 | )% | | 0.9 | % | Residential | 42,135 | | | 39,580 | | | 6.5 | % | | 3.0 | % | Small commercial & industrial | 23,828 |
| | 21,997 |
| | 8.3 | % | | 1.4 | % | Small commercial & industrial | 23,449 | | | 21,361 | | | 9.8 | % | | 6.0 | % | Large commercial & industrial | 50 |
| | 65 |
| | (23.1 | )% | | 7.4 | % | Large commercial & industrial | 31 | | | 34 | | | (8.8) | % | | 12.3 | % | Transportation | 25,822 |
| | 26,595 |
| | (2.9 | )% | | (1.3 | )% | Transportation | 25,011 | | | 25,081 | | | (0.3) | % | | (1.8) | % | Total natural gas deliveries | 89,896 |
| | 92,107 |
| | (2.4 | )% | | 0.4 | % | | Total natural gas deliveries(a) | | Total natural gas deliveries(a) | 90,626 | | | 86,056 | | | 5.3 | % | | 2.4 | % |
__________ | | (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. |
(a)Reflects delivery volumes from customers purchasing natural gas directly from PECO and customers purchasing electricity from a competitive natural gas supplier as all customers are assessed distribution charges. | | | | | | | | 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 |
|
(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 | 2022 | | 2021 | Residential | 502,944 | | | 497,873 | | Small commercial & industrial | 44,957 | | | 44,815 | | Large commercial & industrial | 9 | | | 6 | | Transportation | 655 | | | 670 | | Total | 548,565 | | | 543,364 | |
Pricing for the year ended December 31, 20192022 compared to the same period in 20182021 increased primarily due to an increaseincreases in electric and gas distribution rates charged to customers. The increase
Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in electric distribution rates was effective January 1, 2019the 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, 2022 compared to the same period in accordance with the 2018 PAPUC approved electric distribution rate case settlement. Additionally, the increase represents2021, increased primarily due to revenue from higher natural gas distribution rates. See Note 3 — Regulatory Matters of the Combined Notesrelated to Consolidated Financial Statements for additional information.late payment charges. Regulatory Required Programs representrepresents 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. Transmission Revenue. Under 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 FERC approved formula, transmission revenue variesregulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation or natural gas from year to year based upon fluctuations incompetitive suppliers, PECO either acts as the underlying costsbilling agent or the competitive supplier separately bills its own customers and capital investments being recovered. Transmission revenue for the year ended December 31, 2019comparedtherefore PECO does not record Operating revenues or Purchased power and fuel expense related to the same periodelectricity 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 2018 decreased primarily due to lower operatingOperating revenues and maintenance expensesPurchased power 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, revenuefuel expense related to late payment chargesthe electricity, natural gas, and mutual assistance revenues.RECs.
See Note 5—5 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of PECO's revenue disaggregation.
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: | | | | | | | | 2022 vs. 2021 | | | (Decrease) Increase | | Storm-related costs | $ | (34) | | | Pension and non-pension postretirement benefits expense | (9) | | | Credit loss expense | 6 | | | Labor, other benefits, contracting, and materials | 20 | | | BSC costs | 29 | | | Other(a) | 30 | | | | 42 | | | Regulatory Required Programs | 16 | | | Total increase | $ | 58 | | | __________ | | | | | | (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.
Primarily reflects an increase in charitable contributions.
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 |
|
__________ | | | | | | | 2022 vs. 2021 | | Increase | Depreciation and amortization(a) | $ | 24 | | Regulatory asset amortization | 1 | | Total increase | $ | 25 | |
__________ (a)Depreciation and amortization expense increased primarily due to ongoing capital expenditures.
Taxes other than income taxes increased by $18 million for the year ended December 31, 2022, compared to the same period in 2021, primarily due to higher Pennsylvania gross receipts tax, which is offset in Operating revenues, and offset by lower Pennsylvania use tax. Interest expense, net increased $16 million for the year ended December 31, 2022, compared to the same period in 2021, primarily due to the issuance of debt in 2021 and 2022 and increases in interest rates. Effective income tax rates were 11.0%12.1% and 1.3%2.3% for the years ended December 31, 20192022 and 2018,2021, respectively. The change in effective tax rate is primarily related to the one-time non-cash impacts associated with the Pennsylvania corporate income tax legislation passed in July 2022. 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—BGE | | | 2019 | | 2018 | | Favorable (unfavorable) 2019 vs. 2018 variance | | 2017 | | Favorable (unfavorable) 2018 vs. 2017 variance | | 2022 | | 2021 | | Favorable (Unfavorable) Variance | | Operating revenues | $ | 3,106 |
| | $ | 3,169 |
| | $ | (63 | ) | | $ | 3,176 |
| | $ | (7 | ) | Operating revenues | $ | 3,895 | | | $ | 3,341 | | | $ | 554 | | | 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 expenses | | Operating expenses | | | Purchased power and fuel | | Purchased power and fuel | 1,567 | | | 1,175 | | | (392) | | | Operating and maintenance | 760 |
| | 777 |
| | 17 |
| | 716 |
| | (61 | ) | Operating and maintenance | 877 | | | 811 | | | (66) | | | Depreciation and amortization | 502 |
| | 483 |
| | (19 | ) | | 473 |
| | (10 | ) | Depreciation and amortization | 630 | | | 591 | | | (39) | | | Taxes other than income taxes | 260 |
| | 254 |
| | (6 | ) | | 240 |
| | (14 | ) | Taxes other than income taxes | 302 | | | 283 | | | (19) | | | Total other operating expenses | 1,522 |
| | 1,514 |
| | (8 | ) | | 1,429 |
| | (85 | ) | | Gain on sales of assets | — |
| | 1 |
| | (1 | ) | | — |
| | 1 |
| | Total operating expenses | | Total operating expenses | 3,376 | | | 2,860 | | | (516) | | | | Operating income | 532 |
| | 474 |
| | 58 |
| | 614 |
| | (140 | ) | Operating income | 519 | | | 481 | | | 38 | | | Other income and (deductions) | | | | | | | | | | Other income and (deductions) | | | | | | | Interest expense, net | (121 | ) | | (106 | ) | | (15 | ) | | (105 | ) | | (1 | ) | Interest expense, net | (152) | | | (138) | | | (14) | | | Other, net | 28 |
| | 19 |
| | 9 |
| | 16 |
| | 3 |
| Other, net | 21 | | | 30 | | | (9) | | | Total other income and (deductions) | (93 | ) | | (87 | ) | | (6 | ) | | (89 | ) | | 2 |
| Total other income and (deductions) | (131) | | | (108) | | | (23) | | | Income before income taxes | 439 |
| | 387 |
| | 52 |
| | 525 |
| | (138 | ) | Income before income taxes | 388 | | | 373 | | | 15 | | | Income taxes | 79 |
| | 74 |
| | (5 | ) | | 218 |
| | 144 |
| Income taxes | 8 | | | (35) | | | (43) | | | Net income | 360 |
| | 313 |
| | 47 |
| | 307 |
| | 6 |
| Net income | $ | 380 | | | $ | 408 | | | $ | (28) | | | Net income attributable to common shareholder | $ | 360 |
| | $ | 313 |
| | $ | 47 |
| | $ | 307 |
| | $ | 6 |
| | |
Year Ended December 31, 20192022 Compared to Year Ended December 31, 2018.2021. Net income attributable to common shareholder increased by $47decreased $28 million primarily due to higher natural gas distribution rates that became effective January 2019an asset impairment in 2022 and December 2019, higher electric distribution rates that became effective December 2019,an increase in depreciation expense, credit loss expense, and lower storm costs,interest expense, partially offset by an increasefavorable impacts of the multi-year plans and a decrease 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 impactstorm costs. See Note 11 — Asset Impairments for additional information 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 RNFOperating revenues consisted of the following: | | | | | | | | | | | | | | | | | | | | | | | | | 2022 vs. 2021 | | | | Increase | | | | Electric | | Gas | | Total | | | | | | | Distribution | $ | 70 | | | $ | 27 | | | $ | 97 | | | | | | | | Transmission | 14 | | | — | | | 14 | | | | | | | | Other | 10 | | | 10 | | | 20 | | | | | | | | | 94 | | | 37 | | | 131 | | | | | | | | Regulatory required programs | 272 | | | 151 | | | 423 | | | | | | | | Total increase | $ | 366 | | | $ | 188 | | | $ | 554 | | | | | | | |
| | | | | | | | | | | | | | 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 |
|
BGE Revenue Decoupling. The demand for electricity and natural gas is affected by weather and customer usage. However, Operating revenues are not impacted by abnormal weather or usage per customer as a result of a bill stabilizationmonthly rate adjustment (BSA) that provides for a fixed distribution chargerevenue per customer by customer class. While Operating revenues are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers. | | | | | | | | As of 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, compared 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.information on revenue decoupling for BGE.
| | | | | | | | | | | | | | | As of December 31, | | | Number of Electric Customers | 2022 | | 2021 | | | Residential | 1,204,429 | | | 1,195,929 | | | | Small commercial & industrial | 115,524 | | | 115,049 | | | | Large commercial & industrial | 12,839 | | | 12,637 | | | | Public authorities & electric railroads | 266 | | | 268 | | | | Total | 1,333,058 | | | 1,323,883 | | | |
| | | | | | | | | | | | | | | As of December 31, | | | Number of Gas Customers | 2022 | | 2021 | | | Residential | 655,373 | | | 651,589 | | | | Small commercial & industrial | 38,207 | | | 38,300 | | | | Large commercial & industrial | 6,233 | | | 6,179 | | | | Total | 699,813 | | | 696,068 | | | |
Distribution Revenue increased for the year ended December 31, 2022 compared to the same period in 2021, due to favorable impacts of the multi-year plans. Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue increased for the year ended December 31, 2022 compared to the same period in 2021 primarily due to 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, 2022 compared to the same period in 2021, primarily due to an increase in late fees charged to customers. Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as conservation, demand response, STRIDE, and the POLR mechanism. The riders are designed to provide full and current cost recovery, as well as a return in certain instances. The costs of these programs are included in Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Transmission Revenue. Under 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 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,regulated rate for distribution service, which is updated annuallyrecorded in January based onOperating revenues. For customers that choose to purchase electric generation or natural gas from competitive suppliers, BGE acts as 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 comparedbilling agent and therefore does not record Operating revenues or Purchased power and fuel expense related to the same period in 2018, primarily dueelectricity and/or natural gas. For customers that choose to increases in capital investmentpurchase electric generation or natural gas from BGE, BGE is permitted to recover the electricity and operatingnatural gas procurement costs from customers and maintenance expense recoveries. See Operating and maintenance expense below and Note 3 — Regulatory Matters oftherefore records the Combined Notes to Consolidated Financial Statements for additional information.
Other revenue includes revenueamounts related to late payment charges, mutual assistancethe electricity and/or natural gas in Operating revenues off-system sales and service application fees.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 $392 million for the year ended December 31, 2022 compared to the same period in 2021 in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.
The changes in Operating and maintenance expense consisted of the following: | | | | | | (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 restoration2022 vs. 2021 | | | | Increase (Decrease) | | | Asset impairment(a) | $ | 48 | | | | BSC costs due to the March 2018 winter storms. | 14 | | | | Credit loss expense | 7 | | | | Labor, other benefits, contracting, and materials | 4 | | | | Storm-related costs | (11) | | | | Pension and non-pension postretirement benefits expense | (12) | | | | Other | 12 | | | | | 62 | | | | Regulatory required programs | 4 | | | | Total increase | $ | 66 | | | |
__________ (a)See Note 11 — Asset Impairments for additional information on the asset impairment. 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) | 2022 vs. 2021 | | | | Increase | | | Depreciation expense increased due to ongoing capital expenditures.and amortization(a) | $ | 35 | | | | Regulatory required programs | 3 | | | | Regulatory asset amortization | 1 | | | | Total increase | $ | 39 | | | |
__________ Interest expense, net(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.
Taxes other than income taxes increased duringby $19 million for the year ended December 31, 20192022 compared to the same period in 2018,2021, primarily due to the issuances of debt in September 2018 and September 2019.increased property taxes. Other,Interest expense, net increased during$14 million for the year ended December 31, 20192022 compared to the same period in 2018, primarily2021, due to higher AFUDC equity.the issuance of debt in 2021 and 2022 and increases in interest rates.
Effective income tax rates were 18%2.1% and 19.1%(9.4)% for the years ended December 31, 20192022 and 2018,2021, respectively. The change is primarily due to decreases in the multi-year plans' accelerated income tax benefits in 2022 compared to 2021. 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 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 resultsResults of operationsOperations 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, 2022 compared to the same period in 2021. See the resultsResults of operationsOperations for Pepco, DPL, and ACE for additional information. | | | | | | | | | | | | | | | | | | | 2022 | | 2021 | | Favorable (Unfavorable) Variance | PHI | $ | 608 | | | $ | 561 | | | $ | 47 | | Pepco | 305 | | | 296 | | | 9 | | DPL | 169 | | | 128 | | | 41 | | ACE | 148 | | | 146 | | | 2 | | Other(a) | (14) | | | (9) | | | (5) | |
| | | | | | | | | | | | | | | | | | | | | | | | 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)Primarily includes eliminating and consolidating adjustments, PHI's corporate operations, shared service entities, and other financing and investing activities.
| | (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, 20192022 Compared to Year Ended December 31, 2018.2021. Net income increased by $84$47 million primarily due to higher electricfavorable impacts as a result of Pepco's Maryland and natural gasDistrict of Columbia multi-year plans, higher distribution rates (not reflecting the impact of TCJA), higher transmission revenues due to an increase in transmission ratesat DPL and the highest daily peak load, lower contracting costs,ACE, and the absence of the charge associated withrecognition of a remeasurement of the Buzzard Point ARO, lower uncollectible accounts expense, and lower write-offs of construction workvaluation allowance against a deferred tax asset due to a change in progress,Delaware tax law in 2021 at DPL, partially offset by an increase in environmental liabilitiesdepreciation expense, interest expense, credit loss expense and various expenses.storm costs at Pepco and DPL.
Results of Operations—Pepco | | | | | | | | | | | | | | | | | | | 2022 | | 2021 | | Favorable (Unfavorable) Variance | Operating revenues | $ | 2,531 | | | $ | 2,274 | | | $ | 257 | | Operating expenses | | | | | | Purchased power | 834 | | | 624 | | | (210) | | Operating and maintenance | 507 | | | 471 | | | (36) | | Depreciation and amortization | 417 | | | 403 | | | (14) | | Taxes other than income taxes | 382 | | | 373 | | | (9) | | Total operating expenses | 2,140 | | | 1,871 | | | (269) | | | | | | | | Operating income | 391 | | | 403 | | | (12) | | Other income and (deductions) | | | | | | Interest expense, net | (150) | | | (140) | | | (10) | | Other, net | 55 | | | 48 | | | 7 | | Total other income and (deductions) | (95) | | | (92) | | | (3) | | Income before income taxes | 296 | | | 311 | | | (15) | | Income taxes | (9) | | | 15 | | | 24 | | Net income | $ | 305 | | | $ | 296 | | | $ | 9 | |
| | | | | | | | | | | | | | | | | | | | | | 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, 20192022 Compared to Year Ended December 31, 2018.2021. Net income increased by $38$9 million primarily due to higher electric distribution rates infavorable impacts of the 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,multi-year plans, 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 by their impact on Purchased powercredit loss expense, such as commoditydepreciation expense, interest expense 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.storm costs.
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 RNFOperating revenues 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 |
|
| | | | | | | | | 2022 vs. 2021 | | | | Increase (Decrease) | | | Distribution | $ | 44 | | | | Transmission | 1 | | | | Other | (3) | | | | | 42 | | | | Regulatory required programs | 215 | | | | Total increase | $ | 257 | | | |
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)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.information on revenue decoupling for Pepco Maryland and District of Columbia.
| | | | | | | | | | | | | | | As of December 31, | | | Number of Electric Customers | 2022 | | 2021 | | | Residential | 856,037 | | | 841,831 | | | | Small commercial & industrial | 54,339 | | | 54,216 | | | | Large commercial & industrial | 22,841 | | | 22,568 | | | | Public authorities & electric railroads | 197 | | | 181 | | | | Total | 933,414 | | | 918,796 | | | |
Distribution Revenue increased for the year ended December 31, 2022 compared to the same period in 2021, primarily due to favorable impacts of the Maryland and District of Columbia multi-year plans. Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue remained relatively consistent for the year ended December 31, 2022 compared to the same period in 2021. 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. 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 impactas 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, Pepco does not record Operating revenues or Purchased power expense related to suppliedthe 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 $210 million for the year ended December 31, 2022 compared to the same period in 2021, in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs.
The changes in RNFOperating and maintenance expense consisted of the following: | | | | | | | | | 2022 vs. 2021 | | | | Increase (Decrease) | | | | | | | | | | | Credit loss expense | $ | 17 | | | | BSC and PHISCO costs | 13 | | | | Storm-related costs | 8 | | | | Labor, other benefits, contracting, and materials | (2) | | | | | | | | | | | | | | | | Other | (6) | | | | | 30 | | | | Regulatory required programs | 6 | | | | Total increase | $ | 36 | | | |
The changes in Depreciation and amortizationexpense consisted of the following: | | | | | | | | | 2022 vs. 2021 | | | | Increase (Decrease) | | | Depreciation and amortization(a) | $ | 14 | | | | Regulatory asset amortization | (3) | | | | Regulatory required programs | 3 | | | | Total increase | $ | 14 | | | |
__________ (a)Depreciation and amortization increased primarily due to ongoing capital expenditures. Taxes other than income taxes increased $9 million for the year ended December 31, 2022 compared to the same period in 2021, primarily due to an increase in property taxes and gross receipts taxes. Interest expense, net increased $10 million for the year ended December 31, 2022 compared to the same period in 2021 primarily due to the issuance of debt in 2021 and 2022 and increases in interest rates. Other, net increased $7 million for the year ended December 31, 2022 compared to the same period in 2021, primarily due to higher AFUDC equity. Effective income tax rates were (3.0)% and 4.8% for the years ended December 31, 2022 and 2021, respectively. The change is primarily due to the acceleration of certain income tax benefits as a result of the Maryland and District of Columbia multi-year plans. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on the three-year electric distribution multi-year plans and Note 13 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
| | | | | | | | | | | | | | 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 |
|
Results of Operations—DPL | | | | | | | | | | | | | | | | | | | 2022 | | 2021 | | Favorable (Unfavorable) Variance | Operating revenues | $ | 1,595 | | | $ | 1,380 | | | $ | 215 | | Operating expenses | | | | | | Purchased power and fuel | 706 | | | 539 | | | (167) | | Operating and maintenance | 349 | | | 345 | | | (4) | | Depreciation and amortization | 232 | | | 210 | | | (22) | | Taxes other than income taxes | 72 | | | 67 | | | (5) | | Total operating expenses | 1,359 | | | 1,161 | | | (198) | | | | | | | | Operating income | 236 | | | 219 | | | 17 | | Other income and (deductions) | | | | | | Interest expense, net | (66) | | | (61) | | | (5) | | Other, net | 13 | | | 12 | | | 1 | | Total other income and (deductions) | (53) | | | (49) | | | (4) | | Income before income taxes | 183 | | | 170 | | | 13 | | Income taxes | 14 | | | 42 | | | 28 | | Net income | $ | 169 | | | $ | 128 | | | $ | 41 | |
Year Ended December 31, 2022 Compared to Year Ended December 31, 2021.Net income increased by $41 million primarily due to higher distribution rates and the absence of the recognition of a valuation allowance against a deferred tax asset due to a change in Delaware tax law in 2021, partially offset by an increase in depreciation expense, interest expense, storm costs, and credit loss expense. The changes in Operating revenues consisted of the following: | | | | | | | | | | | | | | | | | | | | | | | | | 2022 vs. 2021 | | | | Increase (Decrease) | | | | Electric | | Gas | | Total | | | | | | | Weather | $ | — | | | $ | 3 | | | $ | 3 | | | | | | | | Volume | 2 | | | 2 | | | 4 | | | | | | | | Distribution | 23 | | | 9 | | | 32 | | | | | | | | Transmission | 6 | | | — | | | 6 | | | | | | | | Other | (2) | | | — | | | (2) | | | | | | | | | 29 | | | 14 | | | 43 | | | | | | | | Regulatory required programs | 116 | | | 56 | | | 172 | | | | | | | | Total increase | $ | 145 | | | $ | 70 | | | $ | 215 | | | | | | | |
Revenue Decoupling.The demand for electricity is affected by weather and customer usage. However, Operating revenues from electric distribution customers in Maryland are not affectedimpacted by unseasonably warmerabnormal weather or colder weather becauseusage per customer as a bill stabilization adjustment (BSA)result of a 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. 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, 20192022 compared to the same period in 2018, RNF2021, Operating revenues related to weather decreased primarilyincreased due to unfavorablefavorable weather conditions in DPL's Delaware natural gas service territoryterritory.
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, 20192022 compared to same period in 20182021 and normal weather consisted of the following: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | | | | % Change | Delaware Electric Service Territory | 2022 | | 2021 | | Normal | | 2022 vs. 2021 | | 2022 vs. Normal | Heating Degree-Days | 4,428 | | | 4,239 | | | 4,593 | | | 4.5 | % | | (3.6) | % | Cooling Degree-Days | 1,382 | | | 1,380 | | | 1,272 | | | 0.1 | % | | 8.6 | % | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | 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 | % |
| | | | | | | | | | | | | For the Years Ended December 31, | | % Change | Delaware Natural Gas Service Territory | For the Years Ended December 31, | | | | % Change | Delaware Natural Gas Service Territory | 2022 | | 2021 | | Normal | | 2022 vs. 2021 | | 2022 vs. Normal | Heating Degree-Days | 2019 | | 2018 | | Normal | | 2019 vs. 2018 | | 2019 vs. Normal | Heating Degree-Days | 4,428 | | | 4,239 | | | 4,676 | | | 4.5 | % | | (5.3) | % | Heating Degree-Days | 4,475 |
| | 4,713 |
| | 4,698 |
| | (5.0 | )% | | (4.7 | )% | | | | |
Volume, exclusive of the effects of weather, remained relatively consistentincreased for the year ended December 31, 20192022 compared to the same period in 2018.2021 primarily due to customer growth and usage. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Electric Retail Deliveries to Delaware Customers (in GWhs) | 2022 | | 2021 | | % Change | | Weather - Normal % Change (b) | | | | | | | Residential | 3,242 | | | 3,214 | | | 0.9 | % | | (0.1) | % | | | | | | | Small commercial & industrial | 1,443 | | | 1,452 | | | (0.6) | % | | (1.0) | % | | | | | | | Large commercial & industrial | 3,162 | | | 3,149 | | | 0.4 | % | | 0.4 | % | | | | | | | Public authorities & electric railroads | 33 | | | 34 | | | (2.9) | % | | (4.4) | % | | | | | | | Total electric retail deliveries(a) | 7,880 | | | 7,849 | | | 0.4 | % | | (0.1) | % | | | | | | |
| | | | | | | | | | | | | | | As of December 31, | | | Number of Total Electric Customers (Maryland and Delaware) | 2022 | | 2021 | | | Residential | 481,688 | | | 476,260 | | | | Small commercial & industrial | 63,738 | | | 63,195 | | | | Large commercial & industrial | 1,235 | | | 1,218 | | | | Public authorities & electric railroads | 597 | | | 604 | | | | Total | 547,258 | | | 541,277 | | | |
__________ (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) | 2022 | | 2021 | | % Change | | Weather - Normal % Change(b) | | | | | | | Residential | 8,709 | | | 7,914 | | | 10.0 | % | | 4.2 | % | | | | | | | Small commercial & industrial | 4,176 | | | 3,747 | | | 11.4 | % | | 7.0 | % | | | | | | | Large commercial & industrial | 1,697 | | | 1,679 | | | 1.1 | % | | 1.1 | % | | | | | | | Transportation | 6,696 | | | 6,778 | | | (1.2) | % | | (2.3) | % | | | | | | | Total natural gas deliveries(a) | 21,278 | | | 20,118 | | | 5.8 | % | | 2.4 | % | | | | | | |
| | | | | | | | | | | | | 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, | | | As of December 31, | | Number of Total Electric Customers (Maryland and Delaware) | 2019 | | 2018 | | Number of Delaware Natural Gas Customers | | Number of Delaware Natural Gas Customers | 2022 | | 2021 | | Residential | 468,162 |
| | 463,670 |
| Residential | 129,502 | | | 128,121 | | | Small commercial & industrial | 61,721 |
| | 61,381 |
| Small commercial & industrial | 10,144 | | | 10,027 | | | Large commercial & industrial | 1,411 |
| | 1,406 |
| Large commercial & industrial | 17 | | | 20 | | | Public authorities & electric railroads | 613 |
| | 621 |
| | Transportation | | Transportation | 156 | | | 158 | | | Total | 531,907 |
| | 527,078 |
| Total | 139,819 | | | 138,326 | | |
__________ | | (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. |
(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. | | | | | | | | | | | | | 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 | % |
(b)Reflects the change in delivery volumes assuming normalized weather based on the historical 30-year average. | | | | | | | | 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, 20192022 compared to the same period in 20182021 primarily due to higher electric distribution rates (not reflecting the impact of TCJA) in Maryland andthat became effective in March 2022, higher DSIC rates in Delaware that became effective throughout 2018in January and July 2022, and higher natural gas distribution rates (not reflecting the impact of TCJA) in Delaware that became effective throughout 2018, partially offset byin August 2022. Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the accelerated amortizationunderlying costs and capital investments being recovered. Transmission revenue increased for the year ended December 31, 2022 compared to the same period in 2021 primarily due to increases in underlying costs. Other Revenue includes rental revenue, revenue related to late payment charges, mutual assistance revenues, and recoveries 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.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. Transmission Revenues. Under 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 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,regulated rate for distribution service, which is updated annuallyrecorded in January based onOperating revenues. For customers that choose to purchase electric generation or natural gas from competitive suppliers, DPL either acts as the prior calendar years. Generally, increases/decreases inbilling agent or the highest daily peak load will result in higher/lower transmission revenue. Transmission revenue increased for the year ended December 31, 2019 comparedcompetitive supplier separately bills its own customers, and therefore does not record Operating revenues or Purchased power and fuel expense related to the same period in 2018 dueelectricity and/or natural gas. For customers that choose to rate increasespurchase electric generation or natural gas from DPL, DPL is permitted to recover the electricity, natural gas, and an increase inREC procurement costs from customers and therefore records the highest daily peak load.
Other revenue includes revenueamounts related to late payment charges, mutual assistancethe electricity, natural gas, and RECs in Operating revenues off-system sales and service application fees.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 forof the Combined Notes to Consolidated Financial Statements for the presentation of DPL's revenue disaggregation. The increase of $167 million for the year ended December 31, 2022 compared to the same period in 2021, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.
The changes in Operating and maintenance expense consisted of the following: | | | | | | (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 | ) |
| | | | | | | | | 2022 vs. 2021 | | | | Increase (Decrease) | | | Credit loss expense | $ | 5 | | | | Storm-related costs | 5 | | | | BSC and PHISCO costs | 5 | | | | | | | | Labor, other benefits, contracting, and materials | (13) | | | | Other | (3) | | | | | (1) | | | | Regulatory required programs | 5 | | | | Total increase | $ | 4 | | | |
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) | 2022 vs. 2021 | | | | Increase (Decrease) | | | Depreciation and amortization increased primarily due to ongoing capital expenditures.(a) | $ | 23 | | | | Regulatory asset amortization | (3) | | | | Regulatory required programs | 2 | | | | Total increase | $ | 22 | | | |
__________
Interest expense, net(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.
Taxes other than income taxes increased by $5 million for the year ended December 31, 20192022 compared to the same period in 2018 increased2021, primarily due to higher outstanding debt.an increase in property taxes and gross receipts taxes.
Effective income tax rateswere 7.7%and24.7% for the years ended December 31, 20192022 and 2018 were 13.0%and and 15.5%,2021, respectively. The decrease for the year ended December 31, 2022 is primarily related to the absence of the recognition of a valuation allowance against a deferred tax asset due to a change in Delaware tax law in 2021. 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 ratesrates.
Results of Operations—ACE | | | 2019 | | 2018 | | Favorable (unfavorable) 2019 vs. 2018 variance | | 2017 | | Favorable (unfavorable) 2018 vs. 2017 variance | | 2022 | | 2021 | | Favorable (Unfavorable) Variance | Operating revenues | $ | 1,240 |
| | $ | 1,236 |
| | $ | 4 |
| | $ | 1,186 |
| | $ | 50 |
| Operating revenues | $ | 1,431 | | | $ | 1,388 | | | $ | 43 | | Purchased power expense | 608 |
| | 616 |
| | 8 |
| | 570 |
| | (46 | ) | | Revenues net of purchased power expense | 632 |
| | 620 |
| | 12 |
| | 616 |
| | 4 |
| | Other operating expenses | | | | |
| | | |
| | Operating expenses | | Operating expenses | | Purchased power | | Purchased power | 624 | | | 694 | | | 70 | | Operating and maintenance | 320 |
| | 330 |
| | 10 |
| | 307 |
| | (23 | ) | Operating and maintenance | 331 | | | 320 | | | (11) | | Depreciation and amortization | 157 |
| | 136 |
| | (21 | ) | | 146 |
| | 10 |
| Depreciation and amortization | 261 | | | 179 | | | (82) | | Taxes other than income taxes | 4 |
| | 5 |
| | 1 |
| | 6 |
| | 1 |
| Taxes other than income taxes | 9 | | | 8 | | | (1) | | Total other operating expenses | 481 |
| | 471 |
| | (10 | ) | | 459 |
| | (12 | ) | | Gain on sales of assets | — |
| | — |
| | — |
| | — |
| | — |
| | Total operating expenses | | Total operating expenses | 1,225 | | | 1,201 | | | (24) | | | Operating income | 151 |
| | 149 |
| | 2 |
| | 157 |
| | (8 | ) | Operating income | 206 | | | 187 | | | 19 | | Other income and (deductions) | | | | |
| | | |
| Other income and (deductions) | | | | | | Interest expense, net | (58 | ) | | (64 | ) | | 6 |
| | (61 | ) | | (3 | ) | Interest expense, net | (66) | | | (58) | | | (8) | | Other, net | 6 |
| | 2 |
| | 4 |
| | 7 |
| | (5 | ) | Other, net | 11 | | | 4 | | | 7 | | Total other income and (deductions) | (52 | ) | | (62 | ) | | 10 |
| | (54 | ) | | (8 | ) | Total other income and (deductions) | (55) | | | (54) | | | (1) | | Income (loss) before income taxes | 99 |
| | 87 |
| | 12 |
| | 103 |
| | (16 | ) | | Income before income taxes | | Income before income taxes | 151 | | | 133 | | | 18 | | Income taxes | — |
| | 12 |
| | 12 |
| | 26 |
| | 14 |
| Income taxes | 3 | | | (13) | | | (16) | | Net income | $ | 99 |
| | $ | 75 |
| | $ | 24 |
| | $ | 77 |
| | $ | (2 | ) | Net income | $ | 148 | | | $ | 146 | | | $ | 2 | |
Year Ended December 31, 20192022 Compared to Year Ended December 31, 20182021. Net income increased $24$2 million primarily due to higher electricincreases in distribution rates, that became effective April 2019 and higher transmission revenues due topartially offset by an increase in depreciation expense, the transmission ratesabsence of favorable weather and volume as a result of 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 commodityCIP, and REC procurement costs and participationan increase 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.interest expense.
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 RNFOperating revenues, 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 |
|
| | | | | | | | | 2022 vs. 2021 | | | | (Decrease) Increase | | | Weather | $ | (3) | | | | Volume | (11) | | | | Distribution | 48 | | | | | | | | Transmission | 9 | | | | | | | | | | | | | | | | Other | (1) | | | | | 42 | | | | Regulatory required programs | 1 | | | | Total increase | $ | 43 | | | |
Weather.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 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. During the year ended December 31, 20192022 compared to the same period in 2018, RNF2021, Operating revenues related to weather was lowerdecreased due to the impactabsence of unfavorable weather conditionsfavorable impacts in ACE's service territory.the first and second quarter of 2022 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, 20192022 compared to same period in 2018,2021 and normal weather consisted of the following: | | | For the Years Ended December 31, | | Normal | | % Change | | For the Years Ended December 31, | | Normal | | % Change | Heating and Cooling Degree-Days | 2019 | | 2018 | | 2019 vs. 2018 | | 2019 vs. Normal | Heating and Cooling Degree-Days | 2022 | | 2021 | | 2022 vs. 2021 | | 2022 vs. Normal | Heating Degree-Days | 4,467 |
| | 4,523 |
| | 4,676 |
| | (1.2 | )% | | (4.5 | )% | Heating Degree-Days | 4,629 | | | 4,256 | | | 4,589 | | | 8.8 | % | | 0.9 | % | Cooling Degree-Days | 1,374 |
| | 1,535 |
| | 1,158 |
| | (10.5 | )% | | 18.7 | % | Cooling Degree-Days | 1,243 | | | 1,284 | | | 1,210 | | | (3.2) | % | | 2.7 | % | | | | |
Volume, exclusive of the effects of weather, decreased for the year ended December 31, 20192022 compared to the same period in 2018,2021, primarily due to lower average residentialthe absence of favorable impacts in the first and commercial usage.second quarter of 2022 as a result of the CIP. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Electric Retail Deliveries to Customers (in GWhs) | 2022 | | 2021 | | % Change | | Weather - Normal % Change(b) | | | | | | | Residential | 4,131 | | | 4,220 | | | (2.1) | % | | (2.4) | % | | | | | | | Small commercial & industrial | 1,499 | | | 1,409 | | | 6.4 | % | | 6.2 | % | | | | | | | Large commercial & industrial | 3,103 | | | 3,146 | | | (1.4) | % | | (1.5) | % | | | | | | | Public authorities & electric railroads | 47 | | | 46 | | | 2.2 | % | | 1.8 | % | | | | | | | Total electric retail deliveries(a) | 8,780 | | | 8,821 | | | (0.5) | % | | (0.7) | % | | | | | | |
| | | | | | | | | | | | | 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, | | As of December 31, | | Number of Electric Customers | 2019 | | 2018 | Number of Electric Customers | 2022 | | 2021 | | Residential | 494,596 |
| | 490,975 |
| Residential | 502,247 | | | 499,628 | | | Small commercial & industrial | 61,497 |
| | 61,386 |
| Small commercial & industrial | 62,246 | | | 61,900 | | | Large commercial & industrial | 3,392 |
| | 3,515 |
| Large commercial & industrial | 3,051 | | | 3,156 | | | Public authorities & electric railroads | 679 |
| | 656 |
| Public authorities & electric railroads | 734 | | | 717 | | | Total | 560,164 |
| | 556,532 |
| Total | 568,278 | | | 565,401 | | |
__________ | | (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. |
(a)Reflects delivery volumes from customers purchasing electricity directly from ACE and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. (b)Reflects the change in delivery volumes assuming normalized weather based on the historical 20-year average. Distribution Revenue increased for the year ended December 31, 20192022 compared to the same period in 2018 primarily2021 due to higher electric distribution base rates that became effective in April 2019, partially offset byJanuary 2022. Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the accelerated amortization of certain deferred income tax regulatory liabilities established uponunderlying costs and capital investments being recovered. Transmission revenue increased for the enactment of TCJA asyear ended December 31, 2022 compared to the result of regulatory settlements. See Note 3 — Regulatory Matters of the Combined Notessame period in 2021 primarily due to Consolidated Financial Statements for additional information.increases in capital investment and underlying costs. 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. RevenuesCustomers have the choice to purchase electricity from regulatorycompetitive electric generation suppliers. Customer choice programs decreaseddo 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 year ended December 31, 2019 compared
billing agent and therefore, ACE does not record Operating revenues or Purchased power expense related to the same periodelectricity. 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 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 recoveredOperating revenues 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 comparedPurchased power expense related to the same period in 2018 primarily due to rate increaseselectricity, ZECs, 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.RECs.
See Note 5 - Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ACE's revenue disaggregation. The decrease of $70 million for the year ended December 31, 2022 compared to same period in 2021, 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: | | | | | | (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 expense2022 vs. 2021 | | | | (Decrease) Increase | | | Labor, other benefits, contracting and the amounts collected in rates annually through a rider mechanism. An equalmaterials | $ | (5) | | | | | | | | Storm-related costs | 1 | | | | BSC and offsetting amount has been recognized in Operating revenues for the periods presented.PHISCO costs | 1 | | | | | | | | | | | | Other | 9 | | | | | 6 | | | | Regulatory required programs(a) | 5 | | | | Total increase | $ | 11 | | | |
__________ (a)ACE is allowed to recover from or refund to customers the difference between its annual credit loss expense and the amounts collected in rates annually through the Societal Benefits Charge. The changes in Depreciation and amortization expense consisted of the following: | | | | | | Increase (Decrease) 2019 vs. 2018 | Depreciation expense(a) | $ | 29 |
| Regulatory asset amortization | 6 |
| Regulatory required programs | (14 | ) | Total increase | $ | 21 |
|
__________
| | | | | | | | (a) | 2022 vs. 2021 | | | | Increase | | | Depreciation and amortization increased primarily due to ongoing capital expenditures.(a) | $ | 18 | | | | Regulatory asset amortization | 2 | | | | Regulatory required programs(b) | 62 | | | | | | | | Total increase | $ | 82 | | | |
__________ (a)Depreciation and amortization increased primarily due to ongoing capital expenditures. (b)Regulatory required programs increased primarily due to the regulatory asset amortization of the PPA termination obligation which is fully offset in Operating revenues. Interest expense, net increased $8 million for the year ended December 31, 20192022 compared to the same period in 2018 decreased2021 primarily due to lower outstanding debt.the issuance of debt in 2021 and 2022. Other, net increased $7 million for the year ended December 31, 20192022 compared to the same period in 2018 increased2021 primarily due to higher AFUDC equity. Effective income tax rates were 0.0%2.0% and 13.8%(9.8)% for the years ended December 31, 20192022 and 2018,2021, respectively. The change is primarily related to the absence of impacts of the July 14, 2021 settlement, which allowed ACE to retain certain tax benefits in 2021. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information regarding the July 14, 2021 settlement agreement and 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. Each of the Registrants annually evaluates its financing plan, dividend practices, and credit line sizing, focusing on maintaining its investment grade ratings while meeting its cash needs to fund capital requirements, including construction expenditures, retire debt, pay dividends, and fund pension and OPEB obligationsobligations. The Registrants spend a significant amount of cash on capital improvements and investconstruction projects that have a long-term return on investment. Additionally, the Utility Registrants operate in rate-regulated environments in which the amount of new investment recovery may be delayed or limited and existing ventures. A broad spectrumwhere such recovery takes place over an extended period of financing alternatives beyond the core financing options can be used to meet its needs and fund growth including monetizing assets in the portfolio via project financing, asset sales, and the use of other financing structures (e.g., joint ventures, minority partners, etc.).time. Each Registrant’s access to external financing on reasonable terms depends on its credit ratings and current overall capital market business conditions, including that of the utility industry in general. If these conditions deteriorate to the extent that the Registrants no longer have access to the capital markets at reasonable terms, the
Registrants have access to credit facilities with aggregate bank commitments of $10.6$4.0 billion,. as of December 31, 2022. The Registrants utilize their credit facilities to support their commercial paper programs, provide for other short-term borrowings, and to issue letters of credit. See the “Credit Matters”Matters and Cash Requirements” section below for additional information. The Registrants expect cash flows to be sufficient to meet operating expenses, financing costs, and capital expenditure requirements. The Registrants primarily use their capital resources, including cash, to fund capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and 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 investment 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.the Registrants’ debt and credit agreements.
Cash flows related to Generation have not been presented as discontinued operations and are included in the Consolidated Statements of Cash Flows for all periods presented. The Exelon Consolidated Statement of Cash Flows for the year ended December 31, 2022 includes one month of cash flows from Generation. The Exelon Consolidated Statement of Cash Flows for the year ended December 31, 2021 includes twelve months of cash flows from Generation. This is the primary reason for the changes in cash flows as shown in the tables unless otherwise noted below. 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. Additionally, ComEd is required to purchase CMCs from participating nuclear-powered generating facilities for a five-year period, and all of its costs of doing so will be recovered through a new rider. The price to be paid for each CMC is established through a competitive bidding process. ComEd will provide net payments to, or collect net payments from, customers for the difference between customer credits issued and the credit to be received from the participating nuclear-powered generating facilities. ComEd’s cash flows are affected by the establishment of CMC prices and the timing of recovering costs through the CMC regulatory asset. See Note 3 — Regulatory Matters and Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information ofon regulatory and legal proceedings and proposed legislation.
The following table provides a summary of the change in cash provided by (used in)flows from operating activities for the years ended December 31, 2019, 20182022 and 2017:2021 by Registrant: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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 | | Increase (decrease) in cash flows from operating activities | | Increase (decrease) in cash flows from operating activities | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Net income | $ | (1,790 | ) | | $ | (2,355 | ) | | $ | 97 |
| | $ | 26 |
| | $ | 6 |
| | $ | 38 |
| | $ | 7 |
| | $ | (1 | ) | | $ | (2 | ) | Net income | $ | 342 | | | $ | 175 | | | $ | 72 | | | $ | (28) | | | $ | 47 | | | $ | 9 | | | $ | 41 | | | $ | 2 | | Add (subtract): | | | | | | | | | | | | | | | | | | | Adjustments to reconcile net income to cash: | | Adjustments to reconcile net income to cash: | | Non-cash operating activities | 2,133 |
| | 3,116 |
| | (232 | ) | | (12 | ) | | (73 | ) | | (124 | ) | | (17 | ) | | (41 | ) | | (17 | ) | Non-cash operating activities | (2,382) | | | (176) | | | 124 | | | 173 | | | 259 | | | 93 | | | 25 | | | 141 | | Option premiums paid, net | | Option premiums paid, net | 299 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Collateral received (posted), net | | Collateral received (posted), net | 1,322 | | | 51 | | | — | | | 16 | | | 99 | | | 22 | | | 35 | | | 42 | | Income taxes | | Income taxes | (331) | | | — | | | (25) | | | (37) | | | (18) | | | (30) | | | (13) | | | 11 | | Pension and non-pension postretirement benefit contributions | 22 |
| | 9 |
| | (1 | ) | | (4 | ) | | (1 | ) | | 25 |
| | 55 |
| | 2 |
| | 14 |
| Pension and non-pension postretirement benefit contributions | 49 | | | 12 | | | — | | | 13 | | | (30) | | | — | | | — | | | (4) | | Income taxes | 41 |
| | (689 | ) | | 370 |
| | (19 | ) | | (80 | ) | | (45 | ) | | (94 | ) | | (24 | ) | | 9 |
| | Regulatory assets and liabilities, net | | Regulatory assets and liabilities, net | (692) | | | (645) | | | (24) | | | (8) | | | (37) | | | 12 | | | 9 | | | (43) | | Changes in working capital and other noncurrent assets and liabilities | 589 |
| | 359 |
| | (49 | ) | | (7 | ) | | 112 |
| | 288 |
| | 116 |
| | 95 |
| | 18 |
| Changes in working capital and other noncurrent assets and liabilities | 3,251 | | | 185 | | | (79) | | | (98) | | | (227) | | | (97) | | | (64) | | | (60) | | 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 |
| | Increase (decrease) in cash flows from operating activities | | Increase (decrease) in cash flows from operating activities | $ | 1,858 | | | $ | (398) | | | $ | 68 | | | $ | 31 | | | $ | 93 | | | $ | 9 | | | $ | 33 | | | $ | 89 | |
Changes in the 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, andby changes in working capital in the normal course of business. In addition, significantbusiness, except as discussed below. See above for additional information related to cash flows from Generation. Significant operating cash flow impacts for the Registrants and Generation for 2019, 20182022 and 20172021 were as follows:
•See Note 22 —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.
| | • | 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•Changes in collateral depended upon whether Generation was 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, contributionscollateral may have been required to avoid benefit restrictionsbe posted with or collected from its counterparties. In addition, the collateral posting and at-risk status as defined bycollection requirements differed depending on whether the Pension Protection Acttransactions were on an exchange or in the over-the-counter markets. Changes in collateral for the Utility Registrants are dependent upon the credit exposure of 2006 (the Act), managementprocurement contracts that may require suppliers to post collateral. The amount of cash collateral received from external counterparties increased due to rising energy prices. See Note 15 — Derivative Financial Instruments for additional information.
•See Note 13 — Income Taxes of the pension obligationCombined Notes to Consolidated Financial Statements and the Registrants' Consolidated Statements of Cash Flows for additional information on income taxes. •Changes in 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),assets 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, whichliabilities, net, 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 contributionsdue to the qualified pension plans, planned benefittiming of cash payments for costs recoverable, or cash receipts for costs recovered, under our regulatory mechanisms differs from the recovery period of those costs. Included within the changes is energy efficiency spend for ComEd of $394 million and $343 million for the years ended December 31, 2022 and 2021, respectively. Also included within the changes is energy efficiency and demand response programs spend for BGE, Pepco, DPL, and ACE of $113 million, $71 million, $28 million, and $11 million for the year ended December 31, 2022, respectively, and $107 million, $72 million, $29 million, and $4 million for the year ended December 31, 2021, respectively. PECO had no energy efficiency and demand response programs spend recorded to a regulatory asset for the years ended December 31, 2022 and 2021. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
•Changes in working capital and other noncurrent assets and liabilities for the Utility Registrants and Exelon Corporate total $(304) million and for Generation total $3,555 million. The change for Generation primarily relates to the revolving accounts receivable financing arrangement. See the Collection of DPP discussion below for additional information. The change in working capital and other noncurrent assets and liabilities for Exelon Corporate and the Utility Registrants is dependent upon the normal course of operations for all Registrants. For ComEd, it is also
dependent upon whether the participating nuclear-powered generating facilities owe money to ComEd as a result of the established pricing for CMCs. In 2022, the established pricing resulted in a receivable from nuclear-powered generating facilities, which is reported within the cash flows from operations as a change in accounts receivable. In future periods the established pricing could result in ComEd owing payments to non-qualified pension plans,nuclear-powered generating facilities, which would be reported within cash flows from operations as a change in accounts payable and planned contributions to other postretirement plans in 2020: | | | | | | | | | | | | | | 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.
accrued expenses.
Cash Flows from Investing Activities The following table provides a summary of the change in cash provided by (used in)flows from investing activities for the years ended December 31, 2019, 20182022 and 2017:2021 by Registrant: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Increase (decrease) in cash flows from investing activities | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Capital expenditures | $ | 834 | | | $ | (119) | | | $ | (109) | | | $ | (36) | | | $ | 11 | | | $ | (31) | | | $ | (1) | | | $ | 47 | | Investment in NDT fund sales, net | 113 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Collection of DPP | (3,733) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Proceeds from sales of assets and businesses | (861) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | | | | | | | | | | | | | | | | Other investing activities | (26) | | | 2 | | | (1) | | | (7) | | | 4 | | | 4 | | | (1) | | | — | | (Decrease) increase in cash flows from investing activities | $ | (3,673) | | | $ | (117) | | | $ | (110) | | | $ | (43) | | | $ | 15 | | | $ | (27) | | | $ | (2) | | | $ | 47 | |
Significant investing cash flow impacts for the Registrants for 2019, 20182022 and 20172021 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 additionscapital projects. See the "Credit Matters and improvementsCash Requirements" section below 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 |
|
Projectedadditional information on 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 areexpenditure spending 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 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 such as the Utility Registrants' construction commitments under PJM’s RTEP.
The Utility Registrants as transmission owners are subject to NERC compliance requirements. NERC provides guidance to transmission owners regarding assessments of transmission lines. The results of these assessments could require the Utility Registrants to incur incremental capital or operating and maintenance expenditures to ensure their transmission lines meet NERC standards. In 2010, NERC provided guidance to transmission owners that recommended the Utility Registrants perform assessments of their transmission lines. 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 completionRegistrants. See Note 2 — Discontinued Operations 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 spendingCombined Notes to Consolidated Financial Statements for remediation to be completed through 2020. BGE, DPL and ACE are complete with their assessments and Pepco has substantially completed its assessment and thus do not expect significant capital expenditures related to this guidanceGeneration prior to the separation.
•Collection of DPP relates to Generation's revolving accounts receivable financing agreement which Generation entered into in April 2020. Generation received $400 million of additional funding related to the DPP in February and March of 2021. The Utility Registrants anticipate that they will fund their capital expenditures with•Proceeds from sales of assets and businesses decreased primarily due to the sale of a combinationsignificant portion of internally generated fundsGeneration's solar business and borrowings and additional capital contributions from parent.
a biomass facility in 2021.
Cash Flows from Financing Activities The following tablestable provides a summary of the change in cash provided by (used in)flows from financing activities for the years ended December 31, 2019, 20182022 and 2017:2021 by Registrant: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (Decrease) increase in cash flows from financing activities | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Changes in short-term borrowings, net | $ | (513) | | | $ | 900 | | | $ | 239 | | | $ | 148 | | | $ | (154) | | | $ | (16) | | | $ | (37) | | | $ | (101) | | Long-term debt, net | 2,395 | | | (50) | | | (25) | | | (50) | | | 50 | | | 40 | | | — | | | 10 | | Changes in intercompany money pool | — | | | — | | | 40 | | | — | | | 51 | | | — | | | — | | | — | | Issuance of common stock | 563 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Dividends paid on common stock | 163 | | | (71) | | | (60) | | | (8) | | | — | | | (195) | | | 4 | | | 143 | | Acquisition of noncontrolling interest | 885 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Distributions to member | — | | | — | | | — | | | — | | | (47) | | | — | | | — | | | — | | Contributions from parent/member | — | | | (121) | | | (140) | | | 29 | | | 104 | | | 221 | | | 27 | | | (144) | | Transfer of cash, restricted cash, and cash equivalents to Constellation | (2,594) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Other financing activities | (66) | | | 5 | | | (6) | | | (5) | | | (5) | | | (4) | | | — | | | — | | Increase (decrease) in cash flows from financing activities | $ | 833 | | | $ | 663 | | | $ | 48 | | | $ | 114 | | | $ | (1) | | | $ | 46 | | | $ | (6) | | | $ | (92) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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 |
|
Significant investingfinancing cash flow impacts for the Registrants for 2019, 20182022 and 20172021 were as follows: | | • | Changes in short-term borrowings, net, 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.
|
| | • | Long-term debt, net, varies due to debt issuances and redemptions each year. Refer to debt issuances and redemptions tables below for more information.
|
| | • | Changes in intercompany money pool are driven by short-term borrowing needs. Refer to more information regarding the intercompany money pool below.
|
| | • | 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.
|
| | • | 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.
|
•Changes in short-term borrowings, net, are driven by repayments on and issuances of notes due in less than 365 days. Refer to Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on short-term borrowings for the Registrants. These changes also included repayments of $552 million in commercial paper and term loans by Generation prior to the separation.
•Long-term debt, net, varies due to debt issuances and redemptions each year. Refer to the debt issuances and redemptions tables below for additional information for the Registrants. •Changes inintercompany money pool are driven by short-term borrowing needs. Refer below for more information regarding the intercompany money pool. •Issuance of common stock relates to the August 2022 underwritten public offering of Exelon common stock. See Note 19 — Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for additional information. •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. •Acquisition of noncontrolling interest relates to Generation's acquisition of CENG noncontrolling interest in 2021. •Refer to Note 2 — Discontinued Operations for the transfer of cash, restricted cash, and cash equivalents to Constellation related to the separation. •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.
|
Debt Issuances and Redemptions See Note 16 — 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, 20182022 and 20172021 by Registrant was as follows: During 2019,2022, the following long-term debt was issued: | | Company | | Type | | Interest Rate | | Maturity | | Amount | | Use of Proceeds | 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. | | Exelon | | Exelon | | SMBC Term Loan Agreement | | SOFR plus 0.65% | | July 21, 2023(a) | | $300 | | Fund a cash payment to Constellation and for general corporate purposes. | Exelon | | Exelon | | U.S. Bank Term Loan Agreement | | SOFR plus 0.65% | | July 21, 2023(a) | | 300 | | Fund a cash payment to Constellation and for general corporate purposes. | Exelon | | Exelon | | PNC Term Loan Agreement | | SOFR plus 0.65% | | July 24, 2023(a) | | 250 | | Fund a cash payment to Constellation and for general corporate purposes. | Exelon | | Exelon | | Notes(b) | | 2.75% | | March 15, 2027 | | 650 | | Repay existing indebtedness and for general corporate purposes. | Exelon | | Exelon | | Notes(b) | | 3.35% | | March 15, 2032 | | 650 | | Repay existing indebtedness and for general corporate purposes. | Exelon | | Exelon | | Notes(b) | | 4.10% | | March 15, 2052 | | 700 | | Repay existing indebtedness and for general corporate purposes. | Exelon | | Exelon | | Long-Term Software License Agreements | | 2.30% | | December 1, 2025 | | 17 | | Procurement of software licenses | Exelon | | Exelon | | Long-Term Software License Agreements | | 3.70% | | August 9, 2025 | | 8 | | Procurement of software licenses | Exelon | | Exelon | | SMBC Term Loan Agreement | | SOFR plus 0.85% | | April 7, 2024 | | 500 | | Repay existing indebtedness and for general corporate purposes. | ComEd(c) | | ComEd(c) | | First Mortgage Bonds, Series 132 | | 3.15% | | March 15, 2032 | | 300 | | Repay outstanding commercial paper obligations and to fund other general corporate purposes. | ComEd | | First Mortgage Bonds, Series 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 133 | | 3.85% | | March 15, 2052 | | 450 | | Repay outstanding commercial paper obligations 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. | | PECO | | PECO | | First and Refunding Mortgage Bonds | | 4.60% | | May 15, 2052 | | 350 | | Refinance existing indebtedness and 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 | | 4.375% | | August 15, 2052 | | 425 | | Refinance outstanding commercial paper and for general corporate purposes. | BGE | | Senior Notes | | 3.20 | % | | September 15, 2049 | | $ | 400 |
| | Repay commercial paper obligations and for general corporate purposes. | BGE | | Notes | | 4.55% | | June 1, 2052 | | 500 | | Repay outstanding commercial paper obligations, repay existing indebtedness, and for general corporate purposes. | Pepco | | First Mortgage Bonds | | 3.45 | % | | June 13, 2029 | | $ | 150 |
| | Repay existing indebtedness and for general corporate purposes. | Pepco | | First Mortgage Bonds | | 3.97% | | March 24, 2052 | | 400 | | 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 | | 3.35% | | September 15, 2032 | | 225 | | 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 | | First Mortgage Bonds | | 3.06% | | February 15, 2052 | | 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 | | 2.27% | | February 15, 2032 | | 25 | | Repay existing indebtedness and for general corporate purposes. | ACE | | First Mortgage Bonds | | 4.14 | % | | May 21, 2049 | | $ | 50 |
| | Repay existing indebtedness and for general corporate purposes. | ACE | | First Mortgage Bonds | | 3.06% | | February 15, 2052 | | 150 | | Repay existing indebtedness and for general corporate purposes. |
__________ | | (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)During the third quarter of 2022, the SMBC Term Loan, U.S. Bank Term Loan, and PNC Term Loan were all reclassified to Long-term debt due within one year on the Exelon Consolidated Balance Sheet, given that the Term Loans have maturity dates of July 21, 2023 , and July 24, 2023, respectively.
(b)In connection with the issuance and sale of the Notes, Exelon entered into a Registration Rights Agreement with the representatives of the initial purchasers of the Notes and other parties. Pursuant to the Registration Rights Agreement,
Exelon filed a registration statement on August 3, 2022, with respect to an offer to exchange the Notes for substantially similar notes of Exelon that are registered under the Securities Act. An exchange offer of registered notes for the Notes was completed on January 12, 2023. The registered notes issued in exchange for Notes in the exchange offer have terms identical in all respects to the Notes, except that their issuance was registered under the Securities Act.
(c)On January 3, 2023, ComEd entered into a purchase agreement of First Mortgage Bonds of $400 million and $575 million at 4.90% and 5.30% due on February 1, 2033 and February 1, 2053, respectively. The closing date of the issuance occurred on January 10, 2023. During 2018,2021, the following long termlong-term debt was issued: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Company | | Type | | Interest Rate | | Maturity | | Amount | | Use of Proceeds | Exelon | | Long-Term Software License Agreements | | 3.62% | | December 1, 2025 | | $4 | | Procurement of software licenses. | ComEd | | First Mortgage Bonds, Series 130 | | 3.13% | | March 15, 2051 | | 700 | | Repay a portion of outstanding commercial paper obligations and two outstanding term loans, and to fund other general corporate purposes. | ComEd | | First Mortgage Bonds, Series 131 | | 2.75% | | September 1, 2051 | | 450 | | Refinance existing indebtedness and for general corporate purposes. | PECO | | First and Refunding Mortgage Bonds | | 3.05% | | March 15, 2051 | | 375 | | Funding for general corporate purposes. | PECO | | First and Refunding Mortgage Bonds | | 2.85% | | September 15, 2051 | | 375 | | Refinance existing indebtedness and for general corporate purposes. | BGE | | Senior Notes | | 2.25% | | June 15, 2031 | | 600 | | Repay a portion of outstanding commercial paper obligations, repay existing indebtedness, and to fund other general corporate purposes. | Pepco | | First Mortgage Bonds | | 2.32% | | March 30, 2031 | | 150 | | Repay existing indebtedness and for general corporate purposes. | Pepco | | First Mortgage Bonds | | 3.29% | | September 28, 2051 | | 125 | | Repay existing indebtedness and for general corporate purposes. | DPL | | First Mortgage Bonds | | 3.24% | | March 30, 2051 | | 125 | | Repay existing indebtedness and for general corporate purposes. | 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 | | 2.27% | | February 15, 2032 | | 75 | | Repay existing indebtedness and for general corporate purposes. |
| | | | | | | | | | | | | | | 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. | 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 125 | | 3.70 | % | | August 15, 2028 | | $ | 550 |
| | Repay a portion of ComEd’s outstanding commercial paper obligations and for 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. | BGE | | Senior Notes | | 4.25 | % | | September 15, 2048 | | $ | 300 |
| | 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 | | 4.31 | % | | November 1, 2048 | | $ | 100 |
| | Repay outstanding commercial paper and for general corporate purposes. | DPL | | First Mortgage Bonds | | 4.27 | % | | June 15, 2048 | | $ | 200 |
| | Repay outstanding commercial paper and for general corporate purposes. | 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. |
__________
| | (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. |
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 2019,2022, the following long-term debt was retired and/or redeemed:
| | | | | | | | | | | | | | | | | | | | | | | | | | | Company | | Type | | Interest Rate | | Maturity | | Amount | Exelon | | Junior Subordinated Notes | | 3.50% | | May 2, 2022 | | $ | 1,150 | | Exelon | | Long-Term Software License Agreement | | 3.96% | | May 1, 2024 | | 2 | Exelon | | Long-Term Software License Agreement | | 2.30% | | December 1, 2025 | | 4 | | Exelon | | Long-Term Software License Agreement | | 3.70% | | August 9, 2025 | | 1 | | PECO | | First Mortgage Bonds | | 2.375% | | September 15, 2022 | | 350 | | BGE | | Notes | | 2.80% | | August 15, 2022 | | 250 | Pepco | | First Mortgage Bonds | | 3.05% | | April 1, 2022 | | 200 | Pepco | | Tax-Exempt Bonds | | 1.70% | | September 1, 2022 | | 110 |
Additionally, in connection with the separation, on January 31, 2022, Exelon Corporate received cash from Generation of $258 million to settle an intercompany loan that mirrored the terms and amounts of the third-party debt obligations. The loan agreements were entered into as part of the 2012 Constellation merger. See Note 16
| | | | | | | | | | | | Company(a) | | Type | | Interest Rate | | Maturity | | Amount | Exelon | | Long-Term Software License Agreement | | 3.95% | | May 1, 2024 | | $ | 18 |
| Generation | | Antelope Valley DOE Nonrecourse Debt(b) | | 2.33% - 3.56% | | January 5, 2037 | | $ | 23 |
| Generation | | Kennett Square Capital Lease | | 7.83% | | September 20, 2020 | | $ | 5 |
| Generation | | Continental Wind Nonrecourse Debt(b) | | 6.00% | | February 28, 2033 | | $ | 32 |
| Generation | | Pollution control notes | | 2.50% | | March 1, 2019 | | $ | 23 |
| Generation | | Renewable Power Generation Nonrecourse Debt(b) | | 4.11% | | March 31, 2035 | | $ | 10 |
| Generation | | Energy Efficiency Project Financing | | 3.46% | | April 30, 2019 | | $ | 39 |
| 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 |
|
__________
| | (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 and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the mirror debt. |
During 2018,2021, the following long-term debt was retired and/or redeemed: | | | | | | | | | | | | | | | | | | | | | | | | | | | Company | | Type | | Interest Rate | | Maturity | | Amount | Exelon | | Senior Notes | | 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 |
| | | | | | | | | | | | Company | | Type | | Interest Rate | | Maturity | | Amount | Exelon Corporate | | Long-Term Software License Agreement | | 3.95% | | May 1, 2024 | | $ | 6 |
| Generation | | Naval Station Great Lakes Project Financing | | 3.90% | | June 30, 2018 | | $ | 41 |
| Generation | | Smithsonian Zoo Project Financing | | 3.72% | | March 31, 2019 | | $ | 1 |
| Generation | | Pensacola Project Financing | | 2.61% | | September 30, 2018 | | $ | 21 |
| Generation | | Fort Detrick Project Financing | | 3.55% | | June 30, 2019 | | $ | 19 |
| Generation | | Holyoke Nonrecourse Debt(a) | | 5.25% | | December 31, 2031 | | $ | 1 |
| Generation | | SolGen Nonrecourse Debt(a) | | 3.93% | | September 30, 2036 | | $ | 10 |
| Generation | | Antelope Valley DOE Nonrecourse Debt(a) | | 2.29% - 3.56% | | January 5, 2037 | | $ | 22 |
| Generation | | Continental Wind Nonrecourse Debt(a) | | 6.00% | | February 28, 2033 | | $ | 33 |
| Generation | | Renewable Power Generation Nonrecourse Debt(a) | | 4.11% | | March 31, 2035 | | $ | 11 |
| Generation | | Kennett Square Capital Lease | | 7.83% | | September 20, 2020 | | $ | 4 |
| Generation | | ExGen Renewables IV Nonrecourse Debt(a) | | 3mL+300 bps | | November 30, 2024 | | $ | 16 |
| Generation | | NUKEM | | 3.15% - 3.35% | | 2018 - 2020 | | $ | 43 |
| 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. |
During 2017, 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 | | $ | 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, 20192022 and for the first quarter of 20202023 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 2022 | | February 8, 2022 | | February 25, 2022 | | March 2018 dividend.10, 2022 | | $ | 0.3375 | | Second Quarter 2022 | | April 26, 2022 | | May 13, 2022 | | June 10, 2022 | | $ | 0.3375 | | Third Quarter 2022 | | July 26, 2022 | | August 15, 2022 | | September 9, 2022 | | $ | 0.3375 | | Fourth Quarter 2022 | | October 28, 2022 | | November 15, 2022 | | December 9, 2022 | | $ | 0.3375 | | First Quarter 2023 | | February 14, 2023 | | February 27, 2023 | | March 10, 2023 | | $ | 0.3600 | |
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 Agreements of the Combined Notes to Consolidated Financial Statements’Directors approved an updated dividend policy for additional information.2023. The 2023 quarterly dividend will be $0.36 per share. Credit Matters Market Conditions and Cash Requirements
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$4.0 billion in aggregate total commitments of which $7.4$2.1 billion was available to support additional commercial paper as of December 31, 2019,2022, and of which no financial institution has more than 7%6% 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 16 — 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 20192022 to fund their short-term liquidity needs, when necessary. 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 lostliquidity to support the estimated future cash requirements discussed below.
On August 4, 2022, Exelon entered into an agreement with certain underwriters in connection with an underwritten public offering of 12.995 million shares of its investment gradecommon stock, no par value. The net proceeds were $563 million before expenses paid. Exelon used the proceeds, together with available cash balances, to repay $575 million in borrowings under a $1.15 billion term loan credit rating asfacility. See Note 19 — Shareholders' Equity and Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. On August 4, 2022, Exelon executed an equity distribution agreement (“Equity Distribution Agreement”) with certain sales agents and forward sellers and certain forward purchasers establishing an ATM equity distribution program under which it may offer and sell shares of its common stock, having an aggregate gross sales price of up to $1.0 billion. Exelon has no obligation to offer or sell any shares of common stock under the Equity Distribution Agreement and may at any time suspend or terminate offers and sales under the Equity Distribution Agreement. As of December 31, 2019, it would have been required2022, Exelon has not issued any shares of common stock under the ATM program and has not entered into any forward sale agreements. Pursuant to provide incremental collateralthe Separation Agreement between Exelon and Constellation Energy Corporation, Exelon made a cash payment 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 2 — Discontinued Operations 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, 20192022 and available credit facility capacity prior to any incremental collateral at December 31, 2019:2022: | | | | | | | | | | | | | | | | | | | PJM Credit Policy Collateral | | Other Incremental Collateral Required(a) | | Available Credit Facility Capacity Prior to Any Incremental Collateral | ComEd | $ | 31 | | | $ | — | | | $ | 568 | | PECO | 1 | | | 71 | | | 361 | | BGE | 3 | | | 119 | | | 191 | | Pepco | 5 | | | — | | | 1 | | DPL | 6 | | | 15 | | | 185 | | ACE | 2 | | | — | | | 300 | | __________(a)Represents incremental collateral related to natural gas procurement contracts.
Capital Expenditures As of December 31, 2022, estimates of capital expenditures for plant additions and improvements are as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (in millions)(a) | 2023 Transmission | | 2023 Distribution | | 2023 Gas | | Total 2023 | | Beyond 2023(b) | Exelon | N/A | | N/A | | N/A | | $ | 7,175 | | | $ | 24,100 | | ComEd | 475 | | | 2,075 | | | N/A | | 2,550 | | | 8,575 | | PECO | 75 | | | 975 | | | 325 | | | 1,375 | | | 4,825 | | BGE | 325 | | | 525 | | | 475 | | | 1,325 | | | 4,700 | | PHI | 550 | | | 1,225 | | | 125 | | | 1,900 | | | 6,000 | | Pepco | 250 | | | 650 | | | N/A | | 900 | | | 2,825 | | DPL | 175 | | | 275 | | | 125 | | | 575 | | | 1,800 | | ACE | 150 | | | 300 | | | N/A | | 425 | | | 1,400 | |
___________ (a)Numbers rounded to the nearest $25M and may not sum due to rounding. (b)Includes estimated capital expenditures for the Utility Registrants from 2024 and 2026. 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
| | | | | | | | | | | | | | PJM Credit Policy Collateral | | Other Incremental Collateral Required(a) | | Available Credit Facility Capacity Prior to Any Incremental Collateral | ComEd | $ | 11 |
| | $ | — |
| | $ | 868 |
| PECO | — |
| | 44 |
| | 600 |
| BGE | 11 |
| | 50 |
| | 524 |
| Pepco | 11 |
| | — |
| | 218 |
| DPL | 4 |
| | 11 |
| | 244 |
| ACE | — |
| | — |
| | 230 |
|
expenditures with a combination of internally generated funds and borrowings and additional capital contributions from parent.Retirement 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 annual contributions with the objective of achieving 100% funded status on an ABO basis over time. This funding strategy helps minimize volatility of future period required pension contributions. Exelon’s estimated annual qualified pension contributions will be $20 million in 2023. 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 2023: | | | | | | | | | | | | | | | | | | | Qualified Pension Plans | | Non-Qualified Pension Plans | | OPEB | Exelon | $ | 20 | | | $ | 48 | | | $ | 47 | | ComEd | 20 | | | 3 | | | 19 | | PECO | — | | | 1 | | | — | | BGE | — | | | 1 | | | 15 | | | | | | | | PHI | — | | | 9 | | | 11 | | Pepco | — | | | 1 | | | 11 | | DPL | — | | | — | | | — | | ACE | — | | | — | | | — | | | | | | | |
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 14 — 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, 2022 under existing financial commitments:
Exelon | | | | | | | | | | | | | | | | | | | | | | | | | 2023 | | Beyond 2023 | | Total | | Time Period | Long-term debt(a) | $ | 1,788 | | | $ | 35,289 | | | $ | 37,077 | | | 2023 - 2053 | Interest payments on long-term debt(b) | 1,476 | | | 23,645 | | | 25,121 | | | 2023 - 2052 | Operating leases(c) | 52 | | | 327 | | | 379 | | | 2023 - 2106 | Fuel purchase agreements(d) | 321 | | | 1,076 | | | 1,397 | | | 2023 - 2038 | | | | | | | | | Electric supply procurement | 4,041 | | | 2,407 | | | 6,448 | | | 2023 - 2026 | Long-term renewable energy and REC commitments | 348 | | | 1,483 | | | 1,831 | | | 2023 - 2038 | Other purchase obligations(c)(e) | 4,816 | | | 3,070 | | | 7,886 | | | 2023 - 2032 | DC PLUG obligation | 34 | | | 3 | | | 37 | | | 2023 - 2024 | ZEC commitments | 99 | | | 676 | | | 775 | | | 2023 - 2027 | Pension contributions(f) | 20 | | | 704 | | | 724 | | | 2023 - 2028 | Total cash requirements | $ | 12,995 | | | $ | 68,680 | | | $ | 81,675 | | | |
__________ (a)Includes amounts from ComEd and PECO financing trusts. (b)Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2022 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, 2022. Includes estimated interest payments due to ComEd and PECO financing trusts. (c)These amounts exclude payments and obligations related to the Baltimore City Conduit system lease. In January 2023, BGE signed an agreement to extend its use of the Baltimore City Conduit system through December 2026. Over the term of the new agreement, BGE has committed to pay the City of Baltimore approximately $19 million and also incur $120 million of capital improvements to the Conduit system. However, the agreement is still pending approval by Baltimore City which is expected to occur in the first quarter of 2023. Once approved, the agreement would be effective immediately. (d)Represents commitments to purchase natural gas and related transportation, storage capacity, and services. (e)Represents the future estimated value at December 31, 2022 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. (f)These amounts represent Exelon’s expected contributions to its qualified pension plans. Qualified pension contributions for years after 2028 are not included.
ComEd | | | | | | | | | | | | | | | | | | | | | | | | | 2023 | | Beyond 2023 | | Total | | Time Period | Long-term debt(a) | $ | — | | | $ | 10,835 | | | $ | 10,835 | | | 2023 - 2053 | Interest payments on long-term debt(b) | 421 | | | 7,640 | | | 8,061 | | | 2023 - 2052 | Operating leases | 2 | | | — | | | 2 | | | 2023 - 2026 | | | | | | | | | Electric supply procurement | 955 | | | 450 | | | 1,405 | | | 2023 - 2025 | Long-term renewable energy and REC commitments | 318 | | | 1,299 | | | 1,617 | | | 2023 - 2038 | Other purchase obligations(c) | 1,124 | | | 488 | | | 1,612 | | | 2023 - 2032 | ZEC commitments | 99 | | | 676 | | | 775 | | | 2023 - 2027 | Total cash requirements | $ | 2,919 | | | $ | 21,388 | | | $ | 24,307 | | | |
__________ (a)Includes amounts from ComEd financing trust. (b)Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2022 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, as of December 31, 2022, 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 | | | | | | | | | | | | | | | | | | | | | | | | | 2023 | | Beyond 2023 | | Total | | Time Period | Long-term debt(a) | $ | 50 | | | $ | 4,809 | | | $ | 4,859 | | | 2023 - 2052 | Interest payments on long-term debt(b) | 194 | | | 4,053 | | | 4,247 | | | 2023 - 2052 | Operating leases | — | | | 1 | | | 1 | | | 2023 - 2034 | Fuel purchase agreements(c) | 172 | | | 307 | | | 479 | | | 2023 - 2029 | Electric supply procurement | 767 | | | 313 | | | 1,080 | | | 2023 - 2024 | Other purchase obligations(d) | 835 | | | 593 | | | 1,428 | | | 2023 - 2030 | Total cash requirements | $ | 2,018 | | | $ | 10,076 | | | $ | 12,094 | | | |
__________ (a)Includes amounts from PECO financing trusts. (b)Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2022 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, as of December 31, 2022, 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 | | | | | | | | | | | | | | | | | | | | | | | | | 2023 | | Beyond 2023 | | Total | | Time Period | Long-term debt | $ | 300 | | | $ | 3,950 | | | $ | 4,250 | | | 2023 - 2052 | Interest payments on long-term debt(a) | 151 | | | 2,836 | | | 2,987 | | | 2023 - 2052 | Operating leases(b) | 1 | | | 18 | | | 19 | | | 2023 - 2106 | Fuel purchase agreements(c) | 116 | | | 573 | | | 689 | | | 2023 - 2038 | Electric supply procurement | 1,003 | | | 755 | | | 1,758 | | | 2023 - 2025 | Other purchase obligations(b)(d) | 966 | | | 299 | | | 1,265 | | | 2023 - 2028 | Total cash requirements | $ | 2,537 | | | $ | 8,431 | | | $ | 10,968 | | | |
__________ (a)Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2022 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. (b)These amounts exclude payments and obligations related to the Baltimore City Conduit system lease. In January 2023, BGE signed an agreement to extend its use of the Baltimore City Conduit system through December 2026. Over the term of the new agreement, BGE has committed to pay the City of Baltimore approximately $19 million and also incur $120 million of capital improvements to the Conduit system. However, the agreement is still pending approval by Baltimore City which is expected to occur in the first quarter of 2023. Once approved, the agreement would be effective immediately. (c)Represents commitments to purchase natural gas and related transportation, storage capacity, and services. (d)Represents the future estimated value, as of December 31, 2022, 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 | | | | | | | | | | | | | | | | | | | | | | | | | 2023 | | Beyond 2023 | | Total | | Time Period | Long-term debt | $ | 577 | | | $ | 7,042 | | | $ | 7,619 | | | 2023 - 2052 | Interest payments on long-term debt(a) | 314 | | | 4,438 | | | 4,752 | | | 2023 - 2052 | Finance leases | 14 | | | 68 | | | 82 | | | 2023 - 2030 | Operating leases | 37 | | | 195 | | | 232 | | | 2023 - 2032 | Fuel purchase agreements(b) | 33 | | | 196 | | | 229 | | | 2023 - 2028 | Electric supply procurement | 1,316 | | | 889 | | | 2,205 | | | 2023 - 2026 | Long-term renewable energy and REC commitments | 30 | | | 184 | | | 214 | | | 2023 - 2033 | Other purchase obligations(c) | 1,335 | | | 710 | | | 2,045 | | | 2023 - 2031 | DC PLUG obligation | 34 | | | 3 | | | 37 | | | 2023 - 2024 | Total cash requirements | $ | 3,690 | | | $ | 13,725 | | | $ | 17,415 | | | |
__________ (a)Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2022 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, 2022. (b)Represents commitments to purchase natural gas and related transportation, storage capacity, and services. (c)Represents the future estimated value, as of December 31, 2022, 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 | | | | | | | | | | | | | | | | | | | | | | | | | 2023 | | Beyond 2023 | | Total | | Time Period | Long-term debt | $ | — | | | $ | 3,773 | | | $ | 3,773 | | | 2023 - 2052 | Interest payments on long-term debt(a) | 170 | | | 2,659 | | | 2,829 | | | 2023 - 2052 | Finance leases | 5 | | | 23 | | | 28 | | | 2023 - 2030 | Operating leases | 7 | | | 41 | | | 48 | | | 2023 - 2032 | Electric supply procurement | 597 | | | 453 | | | 1,050 | | | 2023 - 2026 | Other purchase obligations(b) | 696 | | | 334 | | | 1,030 | | | 2023 - 2027 | DC PLUG obligation | 34 | | | 3 | | | 37 | | | 2023 - 2024 | Total cash requirements | $ | 1,509 | | | $ | 7,286 | | | $ | 8,795 | | | |
__________ (a)Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2022 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. (b)Represents the future estimated value, as of December 31, 2022, 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 | | | | | | | | | | | | | | | | | | | | | | | | | 2023 | | Beyond 2023 | | Total | | Time Period | Long-term debt | $ | 578 | | | $ | 1,337 | | | $ | 1,915 | | | 2023 - 2052 | Interest payments on long-term debt(a) | 68 | | | 1,061 | | | 1,129 | | | 2023 - 2052 | Finance leases | 6 | | | 28 | | | 34 | | | 2023 - 2030 | Operating leases | 10 | | | 52 | | | 62 | | | 2023 - 2032 | Fuel purchase agreements(b) | 33 | | | 196 | | | 229 | | | 2023 - 2028 | Electric supply procurement | 358 | | | 220 | | | 578 | | | 2023 - 2025 | Long-term renewable energy and REC commitments | 30 | | | 184 | | | 214 | | | 2023 - 2033 | Other purchase obligations(c) | 270 | | | 158 | | | 428 | | | 2023 - 2031 | Total cash requirements | $ | 1,353 | | | $ | 3,236 | | | $ | 4,589 | | | |
__________ (a)Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2022 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, 2022. (b)Represents commitments to purchase natural gas and related transportation, storage capacity, and services. (c)Represents the future estimated value, as of December 31, 2022, 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 | | | | | | | | | | | | | | | | | | | | | | | | | 2023 | | Beyond 2023 | | Total | | Time Period | Long-term debt | $ | — | | | $ | 1,747 | | | $ | 1,747 | | | 2023 - 2052 | Interest payments on long-term debt(a) | 62 | | | 598 | | | 660 | | | 2023 - 2052 | Finance leases | 3 | | | 17 | | | 20 | | | 2023 - 2030 | Operating leases | 4 | | | 7 | | | 11 | | | 2023 - 2028 | Electric supply procurement | 361 | | | 216 | | | 577 | | | 2023 - 2025 | Other purchase obligations(b) | 323 | | | 168 | | | 491 | | | 2023 - 2027 | Total cash requirements | $ | 753 | | | $ | 2,753 | | | $ | 3,506 | | | |
__________ (a)Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2022 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. (b)Represents the future estimated value, as of December 31, 2022, 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 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 16 — Debt and Credit Agreements | Interest payments on long-term debt | Note 16 — Debt and Credit Agreements | Finance leases | Note 10 — Leases | Operating leases | Note 10 — Leases | | | (a)REC commitments | Represents incremental collateral related to natural gas procurement contracts.Note 3 — Regulatory Matters | ZEC commitments | Note 3 — Regulatory Matters | DC PLUG obligation | Note 3 — Regulatory Matters | Pension contributions | Note 14 — Retirement Benefits |
Exelon Credit Facilities
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 16 — 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 As of December 31, 2019,2022, the capital structures of the Registrants consisted of the following: | |
| Exelon |
| Generation |
| ComEd |
| PECO |
| BGE | | PHI | | Pepco | | DPL | | ACE | | Exelon(a) | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Long-term debt | 50 | % | | 31 | % | | 44 | % | | 44 | % | | 47 | % | | 40 | % | | 49 | % | | 49 | % | | 50 | % | Long-term debt | 57 | % | | 43 | % | | 44 | % | | 44 | % | | 41 | % | | 48 | % | | 48 | % | | 50 | % | Long-term debt to affiliates(a) | 1 | % | | 4 | % | | — | % | | 2 | % | | — | % | | — | % | | — | % | | — | % | | — | % | | Long-term debt to affiliates(b) | | Long-term debt to affiliates(b) | 1 | % | | 1 | % | | 2 | % | | — | % | | — | % | | — | % | | — | % | | — | % | Common equity | 47 | % | | — | % | | 55 | % | | 54 | % | | 52 | % | | — |
| | 50 | % | | 49 | % | | 47 | % | Common equity | 38 | % | | 54 | % | | 52 | % | | 52 | % | | — | % | | 48 | % | | 49 | % | | 50 | % | 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 | % | | 2 | % | | 4 | % | | 2 | % | | 4 | % | | 3 | % | | — | % |
__________ | | (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)As of December 31, 2021, Exelon's Long-term debt and Common equity capital structure percentages were 50% and 45%, respectively. The change in capital structure percentages above is a result of a decrease in common equity due to the separation of Constellation in addition to an increase in long-term debt issuances. See Note 2 — Discontinued Operations for additional information regarding the separation. (b)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. Security Ratings 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 15 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on collateral provisions. The credit ratings for ComEd, PECO, BGE, and DPL did not change for the year ended December 31, 2022. On January 14, 2022, Fitch lowered Exelon Corporate's long-term and senior unsecured ratings 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 PoolLiquidity and Capital Resources
To provideAll 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. Each of the Registrants annually evaluates its financing plan, dividend practices, and credit line sizing, focusing on maintaining its investment grade ratings while meeting its cash needs to fund capital requirements, including construction expenditures, retire debt, pay dividends, and fund pension and OPEB obligations. 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 additional short-term borrowing optionextended period of time. Each Registrant’s access to external financing on reasonable terms depends on its credit ratings and current overall capital market business conditions, including that will generally be more favorableof the utility industry in general. If these conditions deteriorate to the borrowing participants thanextent that the costRegistrants no longer have access to the capital markets at reasonable terms, the Registrants have access to credit facilities with aggregate bank commitments 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$4.0 billion, as of December 31, 2019,2022. 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 and Cash Requirements” section below for additional information. The Registrants expect cash flows to be sufficient to meet operating expenses, financing costs, and capital expenditure requirements. See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ debt and credit agreements. Cash flows related to Generation have not been presented as discontinued operations and are presentedincluded in the following tables:Consolidated Statements of Cash Flows for all periods presented. The Exelon Consolidated Statement of Cash Flows for the year ended December 31, 2022 includes one month of cash flows from Generation. The Exelon Consolidated Statement of Cash Flows for the year ended December 31, 2021 includes twelve months of cash flows from Generation. This is the primary reason for the changes in cash flows as shown in the tables unless otherwise noted below. Cash Flows from Operating Activities 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. Additionally, ComEd is required to purchase CMCs from participating nuclear-powered generating facilities for a five-year period, and all of its costs of doing so will be recovered through a new rider. The price to be paid for each CMC is established through a competitive bidding process. ComEd will provide net payments to, or collect net payments from, customers for the difference between customer credits issued and the credit to be received from the participating nuclear-powered generating facilities. ComEd’s cash flows are affected by the establishment of CMC prices and the timing of recovering costs through the CMC regulatory asset. See Note 3 — Regulatory Matters and Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information on regulatory and legal proceedings and proposed legislation.
| | | | | | | | | | | | | 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 |
|
The following table provides a summary of the change in cash flows from operating activities for the years ended December 31, 2022 and 2021 by Registrant: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Increase (decrease) in cash flows from operating activities | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Net income | $ | 342 | | | $ | 175 | | | $ | 72 | | | $ | (28) | | | $ | 47 | | | $ | 9 | | | $ | 41 | | | $ | 2 | | Adjustments to reconcile net income to cash: | | | | | | | | | | | | | | | | Non-cash operating activities | (2,382) | | | (176) | | | 124 | | | 173 | | | 259 | | | 93 | | | 25 | | | 141 | | Option premiums paid, net | 299 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Collateral received (posted), net | 1,322 | | | 51 | | | — | | | 16 | | | 99 | | | 22 | | | 35 | | | 42 | | Income taxes | (331) | | | — | | | (25) | | | (37) | | | (18) | | | (30) | | | (13) | | | 11 | | Pension and non-pension postretirement benefit contributions | 49 | | | 12 | | | — | | | 13 | | | (30) | | | — | | | — | | | (4) | | Regulatory assets and liabilities, net | (692) | | | (645) | | | (24) | | | (8) | | | (37) | | | 12 | | | 9 | | | (43) | | Changes in working capital and other noncurrent assets and liabilities | 3,251 | | | 185 | | | (79) | | | (98) | | | (227) | | | (97) | | | (64) | | | (60) | | Increase (decrease) in cash flows from operating activities | $ | 1,858 | | | $ | (398) | | | $ | 68 | | | $ | 31 | | | $ | 93 | | | $ | 9 | | | $ | 33 | | | $ | 89 | |
| | | | | | | | | | | | | 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 | ) | | — |
|
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. See above for additional information related to cash flows from Generation. Significant operating cash flow impacts for the Registrants and Generation for 2022 and 2021 were as follows:
Shelf Registration Statements. •Exelon,See Note 22 —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.
•Changes in collateral depended upon whether Generation was in a net mark-to-market liability or asset position, and collateral may have been required to be posted with or collected from its counterparties. In addition, the collateral posting and collection requirements differed depending on whether the transactions were on an exchange or in the over-the-counter markets. Changes in collateral for the Utility Registrants are dependent upon the credit exposure of procurement contracts that may require suppliers to post collateral. The amount of cash collateral received from external counterparties increased due to rising energy prices. See Note 15 — Derivative Financial Instruments for additional information. •See Note 13 — 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 regulatory assets and liabilities, net, are due to the timing of cash payments for costs recoverable, or cash receipts for costs recovered, under our regulatory mechanisms differs from the recovery period of those costs. Included within the changes is energy efficiency spend for ComEd PECO,of $394 million and $343 million for the years ended December 31, 2022 and 2021, respectively. Also included within the changes is energy efficiency and demand response programs spend for BGE, Pepco, DPL, and ACE of $113 million, $71 million, $28 million, and $11 million for the year ended December 31, 2022, respectively, and $107 million, $72 million, $29 million, and $4 million for the year ended December 31, 2021, respectively. PECO had no energy efficiency and demand response programs spend recorded to a regulatory asset for the years ended December 31, 2022 and 2021. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. •Changes in working capital and other noncurrent assets and liabilities for the Utility Registrants and Exelon Corporate total $(304) million and for Generation total $3,555 million. The change for Generation primarily relates to the revolving accounts receivable financing arrangement. See the Collection of DPP discussion below for additional information. The change in working capital and other noncurrent assets and liabilities for Exelon Corporate and the Utility Registrants is dependent upon the normal course of operations for all Registrants. For ComEd, it is also
dependent upon whether the participating nuclear-powered generating facilities owe money to ComEd as a result of the established pricing for CMCs. In 2022, the established pricing resulted in a receivable from nuclear-powered generating facilities, which is reported within the cash flows from operations as a change in accounts receivable. In future periods the established pricing could result in ComEd owing payments to nuclear-powered generating facilities, which would be reported within cash flows from operations as a change in accounts payable and accrued expenses. Cash Flows from Investing Activities The following table provides a summary of the change in cash flows from investing activities for the years ended December 31, 2022 and 2021 by Registrant: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Increase (decrease) in cash flows from investing activities | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Capital expenditures | $ | 834 | | | $ | (119) | | | $ | (109) | | | $ | (36) | | | $ | 11 | | | $ | (31) | | | $ | (1) | | | $ | 47 | | Investment in NDT fund sales, net | 113 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Collection of DPP | (3,733) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Proceeds from sales of assets and businesses | (861) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | | | | | | | | | | | | | | | | Other investing activities | (26) | | | 2 | | | (1) | | | (7) | | | 4 | | | 4 | | | (1) | | | — | | (Decrease) increase in cash flows from investing activities | $ | (3,673) | | | $ | (117) | | | $ | (110) | | | $ | (43) | | | $ | 15 | | | $ | (27) | | | $ | (2) | | | $ | 47 | |
Significant investing cash flow impacts for the Registrants for 2022 and 2021 were as follows: •Variances in capital expenditures are primarily due to the timing of cash expenditures for capital projects. See the "Credit Matters and Cash Requirements" section below for additional information on projected capital expenditure spending for the Utility Registrants. See Note 2 — Discontinued Operations of the Combined Notes to Consolidated Financial Statements for capital expenditures related to Generation prior to the separation. •Collection of DPP relates to Generation's revolving accounts receivable financing agreement which Generation entered into in April 2020. Generation received $400 million of additional funding related to the DPP in February and March of 2021. •Proceeds from sales of assets and businesses decreased primarily due to the sale of a significant portion of Generation's solar business and a biomass facility in 2021. Cash Flows from Financing Activities The following table provides a summary of the change in cash flows from financing activities for the years ended December 31, 2022 and 2021 by Registrant: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (Decrease) increase in cash flows from financing activities | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Changes in short-term borrowings, net | $ | (513) | | | $ | 900 | | | $ | 239 | | | $ | 148 | | | $ | (154) | | | $ | (16) | | | $ | (37) | | | $ | (101) | | Long-term debt, net | 2,395 | | | (50) | | | (25) | | | (50) | | | 50 | | | 40 | | | — | | | 10 | | Changes in intercompany money pool | — | | | — | | | 40 | | | — | | | 51 | | | — | | | — | | | — | | Issuance of common stock | 563 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Dividends paid on common stock | 163 | | | (71) | | | (60) | | | (8) | | | — | | | (195) | | | 4 | | | 143 | | Acquisition of noncontrolling interest | 885 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Distributions to member | — | | | — | | | — | | | — | | | (47) | | | — | | | — | | | — | | Contributions from parent/member | — | | | (121) | | | (140) | | | 29 | | | 104 | | | 221 | | | 27 | | | (144) | | Transfer of cash, restricted cash, and cash equivalents to Constellation | (2,594) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Other financing activities | (66) | | | 5 | | | (6) | | | (5) | | | (5) | | | (4) | | | — | | | — | | Increase (decrease) in cash flows from financing activities | $ | 833 | | | $ | 663 | | | $ | 48 | | | $ | 114 | | | $ | (1) | | | $ | 46 | | | $ | (6) | | | $ | (92) | |
Significant financing cash flow impacts for the Registrants for 2022 and 2021 were as follows: •Changes in short-term borrowings, net, are driven by repayments on and issuances of notes due in less than 365 days. Refer to Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on short-term borrowings for the Registrants. These changes also included repayments of $552 million in commercial paper and term loans by Generation prior to the separation. •Long-term debt, net, varies due to debt issuances and redemptions each year. Refer to the debt issuances and redemptions tables below for additional information for the Registrants. •Changes inintercompany money pool are driven by short-term borrowing needs. Refer below for more information regarding the intercompany money pool. •Issuance of common stock relates to the August 2022 underwritten public offering of Exelon common stock. See Note 19 — Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for additional information. •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. •Acquisition of noncontrolling interest relates to Generation's acquisition of CENG noncontrolling interest in 2021. •Refer to Note 2 — Discontinued Operations for the transfer of cash, restricted cash, and cash equivalents to Constellation related to the separation. •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 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of the Registrants’ long-term debt. Debt activity for 2022 and 2021 by Registrant was as follows: During 2022, the following long-term debt was issued: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Company | | Type | | Interest Rate | | Maturity | | Amount | | Use of Proceeds | Exelon | | SMBC Term Loan Agreement | | SOFR plus 0.65% | | July 21, 2023(a) | | $300 | | Fund a cash payment to Constellation and for general corporate purposes. | Exelon | | U.S. Bank Term Loan Agreement | | SOFR plus 0.65% | | July 21, 2023(a) | | 300 | | Fund a cash payment to Constellation and for general corporate purposes. | Exelon | | PNC Term Loan Agreement | | SOFR plus 0.65% | | July 24, 2023(a) | | 250 | | Fund a cash payment to Constellation and for general corporate purposes. | Exelon | | Notes(b) | | 2.75% | | March 15, 2027 | | 650 | | Repay existing indebtedness and for general corporate purposes. | Exelon | | Notes(b) | | 3.35% | | March 15, 2032 | | 650 | | Repay existing indebtedness and for general corporate purposes. | Exelon | | Notes(b) | | 4.10% | | March 15, 2052 | | 700 | | Repay existing indebtedness and for general corporate purposes. | Exelon | | Long-Term Software License Agreements | | 2.30% | | December 1, 2025 | | 17 | | Procurement of software licenses | Exelon | | Long-Term Software License Agreements | | 3.70% | | August 9, 2025 | | 8 | | Procurement of software licenses | Exelon | | SMBC Term Loan Agreement | | SOFR plus 0.85% | | April 7, 2024 | | 500 | | Repay existing indebtedness and for general corporate purposes. | ComEd(c) | | First Mortgage Bonds, Series 132 | | 3.15% | | March 15, 2032 | | 300 | | Repay outstanding commercial paper obligations and to fund other general corporate purposes. | ComEd | | First Mortgage Bonds, Series 133 | | 3.85% | | March 15, 2052 | | 450 | | Repay outstanding commercial paper obligations and to fund other general corporate purposes. | PECO | | First and Refunding Mortgage Bonds | | 4.60% | | May 15, 2052 | | 350 | | Refinance existing indebtedness and for general corporate purposes. | PECO | | First and Refunding Mortgage Bonds | | 4.375% | | August 15, 2052 | | 425 | | Refinance outstanding commercial paper and for general corporate purposes. | BGE | | Notes | | 4.55% | | June 1, 2052 | | 500 | | Repay outstanding commercial paper obligations, repay existing indebtedness, and for general corporate purposes. | Pepco | | First Mortgage Bonds | | 3.97% | | March 24, 2052 | | 400 | | Repay existing indebtedness and for general corporate purposes. | Pepco | | First Mortgage Bonds | | 3.35% | | September 15, 2032 | | 225 | | Repay existing indebtedness and for general corporate purposes. | DPL | | First Mortgage Bonds | | 3.06% | | February 15, 2052 | | 125 | | Repay existing indebtedness and for general corporate purposes. | ACE | | First Mortgage Bonds | | 2.27% | | February 15, 2032 | | 25 | | Repay existing indebtedness and for general corporate purposes. | ACE | | First Mortgage Bonds | | 3.06% | | February 15, 2052 | | 150 | | Repay existing indebtedness and for general corporate purposes. |
__________ (a)During the third quarter of 2022, the SMBC Term Loan, U.S. Bank Term Loan, and PNC Term Loan were all reclassified to Long-term debt due within one year on the Exelon Consolidated Balance Sheet, given that the Term Loans have maturity dates of July 21, 2023 , and July 24, 2023, respectively. (b)In connection with the issuance and sale of the Notes, Exelon entered into a currently effective combined shelfRegistration Rights Agreement with the representatives of the initial purchasers of the Notes and other parties. Pursuant to the Registration Rights Agreement,
Exelon filed a registration statement unlimitedon August 3, 2022, with respect to an offer to exchange the Notes for substantially similar notes of Exelon that are registered under the Securities Act. An exchange offer of registered notes for the Notes was completed on January 12, 2023. The registered notes issued in amount, filedexchange for Notes in the exchange offer have terms identical in all respects to the Notes, except that their issuance was registered under the Securities Act. (c)On January 3, 2023, ComEd entered into a purchase agreement of First Mortgage Bonds of $400 million and $575 million at 4.90% and 5.30% due on February 1, 2033 and February 1, 2053, respectively. The closing date of the issuance occurred on January 10, 2023. During 2021, the following long-term debt was issued: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Company | | Type | | Interest Rate | | Maturity | | Amount | | Use of Proceeds | Exelon | | Long-Term Software License Agreements | | 3.62% | | December 1, 2025 | | $4 | | Procurement of software licenses. | ComEd | | First Mortgage Bonds, Series 130 | | 3.13% | | March 15, 2051 | | 700 | | Repay a portion of outstanding commercial paper obligations and two outstanding term loans, and to fund other general corporate purposes. | ComEd | | First Mortgage Bonds, Series 131 | | 2.75% | | September 1, 2051 | | 450 | | Refinance existing indebtedness and for general corporate purposes. | PECO | | First and Refunding Mortgage Bonds | | 3.05% | | March 15, 2051 | | 375 | | Funding for general corporate purposes. | PECO | | First and Refunding Mortgage Bonds | | 2.85% | | September 15, 2051 | | 375 | | Refinance existing indebtedness and for general corporate purposes. | BGE | | Senior Notes | | 2.25% | | June 15, 2031 | | 600 | | Repay a portion of outstanding commercial paper obligations, repay existing indebtedness, and to fund other general corporate purposes. | Pepco | | First Mortgage Bonds | | 2.32% | | March 30, 2031 | | 150 | | Repay existing indebtedness and for general corporate purposes. | Pepco | | First Mortgage Bonds | | 3.29% | | September 28, 2051 | | 125 | | Repay existing indebtedness and for general corporate purposes. | DPL | | First Mortgage Bonds | | 3.24% | | March 30, 2051 | | 125 | | Repay existing indebtedness and for general corporate purposes. | 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 | | 2.27% | | February 15, 2032 | | 75 | | Repay existing indebtedness and for general corporate purposes. |
During 2022, the following long-term debt was retired and/or redeemed: | | | | | | | | | | | | | | | | | | | | | | | | | | | Company | | Type | | Interest Rate | | Maturity | | Amount | Exelon | | Junior Subordinated Notes | | 3.50% | | May 2, 2022 | | $ | 1,150 | | Exelon | | Long-Term Software License Agreement | | 3.96% | | May 1, 2024 | | 2 | Exelon | | Long-Term Software License Agreement | | 2.30% | | December 1, 2025 | | 4 | | Exelon | | Long-Term Software License Agreement | | 3.70% | | August 9, 2025 | | 1 | | PECO | | First Mortgage Bonds | | 2.375% | | September 15, 2022 | | 350 | | BGE | | Notes | | 2.80% | | August 15, 2022 | | 250 | Pepco | | First Mortgage Bonds | | 3.05% | | April 1, 2022 | | 200 | Pepco | | Tax-Exempt Bonds | | 1.70% | | September 1, 2022 | | 110 |
Additionally, in connection with the SEC,separation, on January 31, 2022, Exelon Corporate received cash from Generation of $258 million to settle an intercompany loan that will expire in August 2022. The ability of each Registrant to sell securities offmirrored the shelf registration statement or to access the private placement markets will depend on a number of factors at the timeterms and amounts of the proposed sale, including other required regulatory approvals,third-party debt obligations. The loan agreements were entered into as applicable, the current financial conditionpart of the Registrant, its securities ratings2012 Constellation merger. See Note 16
— Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the mirror debt. During 2021, the following long-term debt was retired and/or redeemed: | | | | | | | | | | | | | | | | | | | | | | | | | | | Company | | Type | | Interest Rate | | Maturity | | Amount | Exelon | | Senior Notes | | 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 |
From time to time and as market conditions.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. Regulatory Authorizations. ComEd, PECO, BGE, Pepco, DPLDividends
Quarterly dividends declared by the Exelon Board of Directors during the year ended December 31, 2022 and ACE are required to obtain short-term and long-term financing authority from Federal and State Commissionsfor the first quarter of 2023 were as follows: | | | | | | | | | | | | | | | | | | | | 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 |
|
__________
| | | | | | | | | | | | | | | | | | | | | | | | | | | (a)Period | Generation currently has blanket financing authority it received from FERC in connection with its market-based rate authority. | Declaration Date | | Shareholder of Record Date | | Dividend Payable Date | | Cash per Share(a) |
First Quarter 2022 | | February 8, 2022 | | February 25, 2022 | | March 10, 2022 | | $ | 0.3375 | | (b)Second Quarter 2022 | 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 | April 26, 2022 | | May 13, 2019 and ACE received approval on December 6, 2019.2022 |
| June 10, 2022 | | $ | 0.3375 | | (c)Third Quarter 2022 | | As of July 26, 2022 | | August 15, 2022 | | September 9, 2022 | | $ | 0.3375 | | Fourth Quarter 2022 | | October 28, 2022 | | November 15, 2022 | | December 31, 20199, 2022 | | , 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 $ | 0.3375 | | First Quarter 2023 | | February 1, 2020 and an expiration date of 14, 2023 | | February 1, 2023.27, 2023 | | March 10, 2023 | | $ | 0.3600 | |
___________
(a)Exelon's Board of Directors approved an updated dividend policy for 2023. The 2023 quarterly dividend will be $0.36 per share. Credit Matters and Cash Requirements 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 $4.0 billion in aggregate total commitments of which $2.1 billion was available to support additional commercial paper as of December 31, 2022, and of which no financial institution has more than 6% 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 16 — 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 2022 to fund their short-term liquidity needs, when necessary. 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.
On August 4, 2022, Exelon entered into an agreement with certain underwriters in connection with an underwritten public offering of 12.995 million shares of its common stock, no par value. The net proceeds were $563 million before expenses paid. Exelon used the proceeds, together with available cash balances, to repay $575 million in borrowings under a $1.15 billion term loan credit facility. See Note 19 — Shareholders' Equity and Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.
Contractual ObligationsOn August 4, 2022, Exelon executed an equity distribution agreement (“Equity Distribution Agreement”) with certain sales agents and Off-Balance Sheet Arrangementsforward sellers and certain forward purchasers establishing an ATM equity distribution program under which it may offer and sell shares of its common stock, having an aggregate gross sales price of up to $1.0 billion. Exelon has no obligation to offer or sell any shares of common stock under the Equity Distribution Agreement and may at any time suspend or terminate offers and sales under the Equity Distribution Agreement. As of December 31, 2022, Exelon has not issued any shares of common stock under the ATM program and has not entered into any forward sale agreements.
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 2 — Discontinued Operations of the Combined Notes to Consolidated Financial Statements for additional information on the separation. The following table presents the incremental collateral that each Utility Registrant would have been required to provide in the event each Utility Registrant lost its investment grade credit rating at December 31, 2022 and available credit facility capacity prior to any incremental collateral at December 31, 2022: | | | | | | | | | | | | | | | | | | | PJM Credit Policy Collateral | | Other Incremental Collateral Required(a) | | Available Credit Facility Capacity Prior to Any Incremental Collateral | ComEd | $ | 31 | | | $ | — | | | $ | 568 | | PECO | 1 | | | 71 | | | 361 | | BGE | 3 | | | 119 | | | 191 | | Pepco | 5 | | | — | | | 1 | | DPL | 6 | | | 15 | | | 185 | | ACE | 2 | | | — | | | 300 | | __________(a)Represents incremental collateral related to natural gas procurement contracts.
Capital Expenditures As of December 31, 2022, estimates of capital expenditures for plant additions and improvements are as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (in millions)(a) | 2023 Transmission | | 2023 Distribution | | 2023 Gas | | Total 2023 | | Beyond 2023(b) | Exelon | N/A | | N/A | | N/A | | $ | 7,175 | | | $ | 24,100 | | ComEd | 475 | | | 2,075 | | | N/A | | 2,550 | | | 8,575 | | PECO | 75 | | | 975 | | | 325 | | | 1,375 | | | 4,825 | | BGE | 325 | | | 525 | | | 475 | | | 1,325 | | | 4,700 | | PHI | 550 | | | 1,225 | | | 125 | | | 1,900 | | | 6,000 | | Pepco | 250 | | | 650 | | | N/A | | 900 | | | 2,825 | | DPL | 175 | | | 275 | | | 125 | | | 575 | | | 1,800 | | ACE | 150 | | | 300 | | | N/A | | 425 | | | 1,400 | |
___________ (a)Numbers rounded to the nearest $25M and may not sum due to rounding. (b)Includes estimated capital expenditures for the Utility Registrants from 2024 and 2026. 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. Retirement 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 annual contributions with the objective of achieving 100% funded status on an ABO basis over time. This funding strategy helps minimize volatility of future period required pension contributions. Exelon’s estimated annual qualified pension contributions will be $20 million in 2023. 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 2023: | | | | | | | | | | | | | | | | | | | Qualified Pension Plans | | Non-Qualified Pension Plans | | OPEB | Exelon | $ | 20 | | | $ | 48 | | | $ | 47 | | ComEd | 20 | | | 3 | | | 19 | | PECO | — | | | 1 | | | — | | BGE | — | | | 1 | | | 15 | | | | | | | | PHI | — | | | 9 | | | 11 | | Pepco | — | | | 1 | | | 11 | | DPL | — | | | — | | | — | | ACE | — | | | — | | | — | | | | | | | |
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 14 — 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’Registrants' future estimated cash payments as of December 31, 20192022 under existing contractualfinancial commitments:
Exelon | | | | | | | | | | | | | | | | | | | | | | | | | 2023 | | Beyond 2023 | | Total | | Time Period | Long-term debt(a) | $ | 1,788 | | | $ | 35,289 | | | $ | 37,077 | | | 2023 - 2053 | Interest payments on long-term debt(b) | 1,476 | | | 23,645 | | | 25,121 | | | 2023 - 2052 | Operating leases(c) | 52 | | | 327 | | | 379 | | | 2023 - 2106 | Fuel purchase agreements(d) | 321 | | | 1,076 | | | 1,397 | | | 2023 - 2038 | | | | | | | | | Electric supply procurement | 4,041 | | | 2,407 | | | 6,448 | | | 2023 - 2026 | Long-term renewable energy and REC commitments | 348 | | | 1,483 | | | 1,831 | | | 2023 - 2038 | Other purchase obligations(c)(e) | 4,816 | | | 3,070 | | | 7,886 | | | 2023 - 2032 | DC PLUG obligation | 34 | | | 3 | | | 37 | | | 2023 - 2024 | ZEC commitments | 99 | | | 676 | | | 775 | | | 2023 - 2027 | Pension contributions(f) | 20 | | | 704 | | | 724 | | | 2023 - 2028 | Total cash requirements | $ | 12,995 | | | $ | 68,680 | | | $ | 81,675 | | | |
__________ (a)Includes amounts from ComEd and PECO financing trusts. (b)Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2022 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. Variable rate interest obligations includingare estimated based on rates as of December 31, 2022. Includes estimated interest payments due to ComEd and PECO financing trusts. (c)These amounts exclude payments and obligations related to the Baltimore City Conduit system lease. In January 2023, BGE signed an agreement to extend its use of the Baltimore City Conduit system through December 2026. Over the term of the new agreement, BGE has committed to pay the City of Baltimore approximately $19 million and also incur $120 million of capital improvements to the Conduit system. However, the agreement is still pending approval by period.Baltimore City which is expected to occur in the first quarter of 2023. Once approved, the agreement would be effective immediately. Exelon(d)Represents commitments to purchase natural gas and related transportation, storage capacity, and services.
(e)Represents the future estimated value at December 31, 2022 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. (f)These amounts represent Exelon’s expected contributions to its qualified pension plans. Qualified pension contributions for years after 2028 are not included.
| | | | | | | | | | | | | | | | | | | | | | | | 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 |
|
ComEd | | | | | | | | | | | | | | | | | | | | | | | | | 2023 | | Beyond 2023 | | Total | | Time Period | Long-term debt(a) | $ | — | | | $ | 10,835 | | | $ | 10,835 | | | 2023 - 2053 | Interest payments on long-term debt(b) | 421 | | | 7,640 | | | 8,061 | | | 2023 - 2052 | Operating leases | 2 | | | — | | | 2 | | | 2023 - 2026 | | | | | | | | | Electric supply procurement | 955 | | | 450 | | | 1,405 | | | 2023 - 2025 | Long-term renewable energy and REC commitments | 318 | | | 1,299 | | | 1,617 | | | 2023 - 2038 | Other purchase obligations(c) | 1,124 | | | 488 | | | 1,612 | | | 2023 - 2032 | ZEC commitments | 99 | | | 676 | | | 775 | | | 2023 - 2027 | Total cash requirements | $ | 2,919 | | | $ | 21,388 | | | $ | 24,307 | | | |
__________ | | (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 (a)Includes amounts from ComEd financing trust.
(b)Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2022 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, as of December 31, 2022, 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.
| | | | | | | | | | | | | | | | | | | | | | | | 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 | | 2023 | | Beyond 2023 | | Total | | Time Period | Long-term debt(a) | $ | 3,634 |
| | $ | — |
| | $ | 650 |
| | $ | 50 |
| | $ | 2,934 |
| Long-term debt(a) | $ | 50 | | | $ | 4,809 | | | $ | 4,859 | | | 2023 - 2052 | Interest payments on long-term debt(b) | 2,721 |
| | 141 |
| | 274 |
| | 254 |
| | 2,052 |
| Interest payments on long-term debt(b) | 194 | | | 4,053 | | | 4,247 | | | 2023 - 2052 | Operating leases | 1 |
| | — |
| | 1 |
| | — |
| | — |
| Operating leases | — | | | 1 | | | 1 | | | 2023 - 2034 | Fuel purchase agreements(c) | 335 |
| | 116 |
| | 154 |
| | 31 |
| | 34 |
| Fuel purchase agreements(c) | 172 | | | 307 | | | 479 | | | 2023 - 2029 | Electric supply procurement | 552 |
| | 441 |
| | 111 |
| | — |
| | — |
| Electric supply procurement | 767 | | | 313 | | | 1,080 | | | 2023 - 2024 | Other purchase obligations(d) | 834 |
| | 727 |
| | 107 |
| | — |
| | — |
| Other purchase obligations(d) | 835 | | | 593 | | | 1,428 | | | 2023 - 2030 | Total contractual obligations | $ | 8,077 |
| | $ | 1,425 |
|
| $ | 1,297 |
|
| $ | 335 |
|
| $ | 5,020 |
| | Total cash requirements | | Total cash requirements | $ | 2,018 | | | $ | 10,076 | | | $ | 12,094 | | |
__________ | | (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. |
(a)Includes amounts from PECO financing trusts. (b)Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2022 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, as of December 31, 2022, 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 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | 2023 | | Beyond 2023 | | Total | | Time Period | Long-term debt | $ | 300 | | | $ | 3,950 | | | $ | 4,250 | | | 2023 - 2052 | Interest payments on long-term debt(a) | 151 | | | 2,836 | | | 2,987 | | | 2023 - 2052 | Operating leases(b) | 1 | | | 18 | | | 19 | | | 2023 - 2106 | Fuel purchase agreements(c) | 116 | | | 573 | | | 689 | | | 2023 - 2038 | Electric supply procurement | 1,003 | | | 755 | | | 1,758 | | | 2023 - 2025 | Other purchase obligations(b)(d) | 966 | | | 299 | | | 1,265 | | | 2023 - 2028 | Total cash requirements | $ | 2,537 | | | $ | 8,431 | | | $ | 10,968 | | | |
__________ | | (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. |
(a)Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2022 and do not reflect anticipated future refinancing, early redemptions, or debt issuances.(b)These amounts exclude payments and obligations related to the Baltimore City Conduit system lease. In January 2023, BGE signed an agreement to extend its use of the Baltimore City Conduit system through December 2026. Over the term of the new agreement, BGE has committed to pay the City of Baltimore approximately $19 million and also incur $120 million of capital improvements to the Conduit system. However, the agreement is still pending approval by Baltimore City which is expected to occur in the first quarter of 2023. Once approved, the agreement would be effective immediately. (c)Represents commitments to purchase natural gas and related transportation, storage capacity, and services. (d)Represents the future estimated value, as of December 31, 2022, 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 | | 2023 | | Beyond 2023 | | Total | | Time Period | Long-term debt | $ | 5,967 |
| | $ | 98 |
| | $ | 571 |
| | $ | 1,049 |
| | $ | 4,249 |
| Long-term debt | $ | 577 | | | $ | 7,042 | | | $ | 7,619 | | | 2023 - 2052 | Interest payments on long-term debt(a) | 4,150 |
| | 269 |
| | 512 |
| | 463 |
| | 2,906 |
| Interest payments on long-term debt(a) | 314 | | | 4,438 | | | 4,752 | | | 2023 - 2052 | Finance leases | 28 |
| | 5 |
| | 8 |
| | 8 |
| | 7 |
| Finance leases | 14 | | | 68 | | | 82 | | | 2023 - 2030 | Operating leases | 346 |
| | 42 |
| | 79 |
| | 72 |
| | 153 |
| Operating leases | 37 | | | 195 | | | 232 | | | 2023 - 2032 | Fuel purchase agreements(b) | 304 |
| | 34 |
| | 68 |
| | 68 |
| | 134 |
| Fuel purchase agreements(b) | 33 | | | 196 | | | 229 | | | 2023 - 2028 | Electric supply procurement | | Electric supply procurement | 1,316 | | | 889 | | | 2,205 | | | 2023 - 2026 | Long-term renewable energy and REC commitments | 298 |
| | 32 |
| | 64 |
| | 64 |
| | 138 |
| Long-term renewable energy and REC commitments | 30 | | | 184 | | | 214 | | | 2023 - 2033 | Electric supply procurement | 1,787 |
| | 1,040 |
| | 730 |
| | 17 |
| | — |
| | Other purchase obligations(c) | 1,181 |
| | 959 |
| | 184 |
| | 6 |
| | 32 |
| Other purchase obligations(c) | 1,335 | | | 710 | | | 2,045 | | | 2023 - 2031 | DC PLUG obligation | 130 |
| | 30 |
| | 60 |
| | 40 |
| | — |
| DC PLUG obligation | 34 | | | 3 | | | 37 | | | 2023 - 2024 | Total contractual obligations | $ | 14,219 |
| | $ | 2,514 |
| | $ | 2,284 |
| | $ | 1,795 |
| | $ | 7,626 |
| | Total cash requirements | | Total cash requirements | $ | 3,690 | | | $ | 13,725 | | | $ | 17,415 | | |
__________ | | (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. |
(a)Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2022 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, 2022. (b)Represents commitments to purchase natural gas and related transportation, storage capacity, and services. (c)Represents the future estimated value, as of December 31, 2022, 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 | | | | | Payment due within | | | | | | | | | | | | | | | | | | | | | | Total | | 2020 | | 2021 - 2022 | | 2023 - 2024 | | 2025 and beyond | | 2023 | | Beyond 2023 | | Total | | Time Period | Long-term debt | $ | 2,886 |
| | $ | 1 |
| | $ | 311 |
| | $ | 399 |
| | $ | 2,175 |
| Long-term debt | $ | — | | | $ | 3,773 | | | $ | 3,773 | | | 2023 - 2052 | Interest payments on long-term debt(a) | 2,385 |
| | 138 |
| | 271 |
| | 249 |
| | 1,727 |
| Interest payments on long-term debt(a) | 170 | | | 2,659 | | | 2,829 | | | 2023 - 2052 | Finance leases | 11 |
| | 1 |
| | 2 |
| | 3 |
| | 5 |
| Finance leases | 5 | | | 23 | | | 28 | | | 2023 - 2030 | Operating leases | 70 |
| | 8 |
| | 16 |
| | 12 |
| | 34 |
| Operating leases | 7 | | | 41 | | | 48 | | | 2023 - 2032 | Electric supply procurement | 803 |
| | 445 |
| | 341 |
| | 17 |
| | — |
| Electric supply procurement | 597 | | | 453 | | | 1,050 | | | 2023 - 2026 | Other purchase obligations(b) | 663 |
| | 489 |
| | 145 |
| | 4 |
| | 25 |
| Other purchase obligations(b) | 696 | | | 334 | | | 1,030 | | | 2023 - 2027 | DC PLUG obligation | 130 |
| | 30 |
| | 60 |
| | 40 |
| | — |
| DC PLUG obligation | 34 | | | 3 | | | 37 | | | 2023 - 2024 | Total contractual obligations | $ | 6,959 |
| | $ | 1,113 |
| | $ | 1,148 |
| | $ | 727 |
| | $ | 3,971 |
| | Total cash requirements | | Total cash requirements | $ | 1,509 | | | $ | 7,286 | | | $ | 8,795 | | |
__________ | | (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. |
(a)Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2022 and do not reflect anticipated future refinancing, early redemptions, or debt issuances.(b)Represents the future estimated value, as of December 31, 2022, 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 | | 2023 | | Beyond 2023 | | Total | | Time Period | Long-term debt | $ | 1,568 |
| | $ | 78 |
| | $ | — |
| | $ | 500 |
| | $ | 990 |
| Long-term debt | $ | 578 | | | $ | 1,337 | | | $ | 1,915 | | | 2023 - 2052 | Interest payments on long-term debt(a) | 1,087 |
| | 60 |
| | 120 |
| | 99 |
| | 808 |
| Interest payments on long-term debt(a) | 68 | | | 1,061 | | | 1,129 | | | 2023 - 2052 | Finance leases | 10 |
| | 2 |
| | 4 |
| | 3 |
| | 1 |
| Finance leases | 6 | | | 28 | | | 34 | | | 2023 - 2030 | Operating leases | 91 |
| | 11 |
| | 21 |
| | 18 |
| | 41 |
| Operating leases | 10 | | | 52 | | | 62 | | | 2023 - 2032 | Fuel purchase agreements(b) | 304 |
| | 34 |
| | 68 |
| | 68 |
| | 134 |
| Fuel purchase agreements(b) | 33 | | | 196 | | | 229 | | | 2023 - 2028 | Long-term renewable energy and associated REC commitments | 298 |
| | 32 |
| | 64 |
| | 64 |
| | 138 |
| | Electric supply procurement | 458 |
| | 288 |
| | 170 |
| | — |
| | — |
| Electric supply procurement | 358 | | | 220 | | | 578 | | | 2023 - 2025 | Long-term renewable energy and REC commitments | | Long-term renewable energy and REC commitments | 30 | | | 184 | | | 214 | | | 2023 - 2033 | Other purchase obligations(c) | 280 |
| | 262 |
| | 18 |
| | — |
| | — |
| Other purchase obligations(c) | 270 | | | 158 | | | 428 | | | 2023 - 2031 | Total contractual obligations | $ | 4,096 |
| | $ | 767 |
| | $ | 465 |
| | $ | 752 |
| | $ | 2,112 |
| | Total cash requirements | | Total cash requirements | $ | 1,353 | | | $ | 3,236 | | | $ | 4,589 | | |
__________ | | (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. |
(a)Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2022 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, 2022. (b)Represents commitments to purchase natural gas and related transportation, storage capacity, and services. (c)Represents the future estimated value, as of December 31, 2022, 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 | | 2023 | | Beyond 2023 | | Total | | Time Period | Long-term debt | $ | 1,327 |
| | $ | 19 |
| | $ | 260 |
| | $ | 150 |
| | $ | 898 |
| Long-term debt | $ | — | | | $ | 1,747 | | | $ | 1,747 | | | 2023 - 2052 | Interest payments on long-term debt (a) | 503 |
| | 57 |
| | 93 |
| | 87 |
| | 266 |
| Interest payments on long-term debt(a) | 62 | | | 598 | | | 660 | | | 2023 - 2052 | Finance leases | 8 |
| | 1 |
| | 2 |
| | 2 |
| | 3 |
| Finance leases | 3 | | | 17 | | | 20 | | | 2023 - 2030 | Operating leases | 20 |
| | 5 |
| | 8 |
| | 5 |
| | 2 |
| Operating leases | 4 | | | 7 | | | 11 | | | 2023 - 2028 | Electric supply procurement | 526 |
| | 307 |
| | 219 |
| | — |
| | — |
| Electric supply procurement | 361 | | | 216 | | | 577 | | | 2023 - 2025 | Other purchase obligations(b) | 200 |
| | 185 |
| | 15 |
| | — |
| | — |
| Other purchase obligations(b) | 323 | | | 168 | | | 491 | | | 2023 - 2027 | Total contractual obligations | $ | 2,584 |
| | $ | 574 |
| | $ | 597 |
| | $ | 244 |
| | $ | 1,169 |
| | Total cash requirements | | Total cash requirements | $ | 753 | | | $ | 2,753 | | | $ | 3,506 | | |
__________ | | (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. |
(a)Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2022 and do not reflect anticipated future refinancing, early redemptions, or debt issuances.
(b)Represents the future estimated value, as of December 31, 2022, 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 obligationsthe financial commitments in the tables above 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 contributionsFinance leases | Note 1410 — Retirement BenefitsLeases | SNF obligationOperating leases | Note 1810 — Commitments and Contingencies |
Leases | | | ITEM 7A.REC commitments | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKNote 3 — Regulatory Matters | ZEC commitments | Note 3 — Regulatory Matters | DC PLUG obligation | Note 3 — Regulatory Matters | Pension contributions | Note 14 — Retirement Benefits |
The Registrants are exposed to market risks associated with adverse changes in commodity prices, counterparty credit, interest ratesCredit Facilities
Exelon Corporate, ComEd, and equity prices. Exelon’s RMC approves risk management policiesBGE 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 objectives for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of risk exposures. The RMC is chaired by the chief executive officer and includes the chief risk officer, chief strategy officer, chief executive officer of Exelon Utilities, chief commercial officer, chief financial officer and chief executive officer of Constellation. The RMC reports to the Finance and Risk Committee ofborrowings from the Exelon Board of Directors on the scope of the risk management activities. 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 expects the settlement of the majority of its economic hedges will occur during 2020 through 2022.
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's hedging program involves the hedging of commodity price risk for Exelon's expected generation, typically on a 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%and61%-64% for 2020and2021, 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 Generation’s sales to ComEd, PECO and BGE to serve their retail load.
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 reduction in the annual average around-the-clock energy price based on December 31, 2019 market conditions and hedged position would be decreases in pre-tax net income of approximately $25 million and $331 million, respectively, for 2020 and 2021. 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 15 — 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. 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 concentrates can be obtained, although at prices that may be unfavorable when compared to the prices under the current supply agreements. Non-performance by these counterparties could have a material adverse impact on Exelon’s and Generation’s financial statements.
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,intercompany money pool. Pepco, DPL, and ACE have contracts to procure electric supply that are executedmeet their short-term liquidity requirements primarily through a competitive procurement process. BGE, Pepco, DPLthe issuance of commercial paper and ACE have certain fullborrowings from the PHI intercompany money pool. PHI Corporate meets its short-term liquidity requirements contracts,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.
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 or proprietary trading purposes.
For additional information on these contracts, see Note 3 — Regulatory Matters and Note 15 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements.
Trading and Non-Trading Marketing Activities
The following table detailing Exelon’s, Generation’s and ComEd’s trading and non-trading marketing activities 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 asset 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. See Note 1516 — Derivative Financial InstrumentsDebt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the balance sheet classificationRegistrants’ credit facilities and short term borrowing activity.
| | | | | | | | | | | | | | 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 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 | | 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 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 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 purchases 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.Capital Structure
As of December 31, 2019, ComEd, PECO, BGE, Pepco, DPL2022, the capital structures of the Registrants consisted of the following: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exelon(a) | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Long-term debt | 57 | % | | 43 | % | | 44 | % | | 44 | % | | 41 | % | | 48 | % | | 48 | % | | 50 | % | Long-term debt to affiliates(b) | 1 | % | | 1 | % | | 2 | % | | — | % | | — | % | | — | % | | — | % | | — | % | Common equity | 38 | % | | 54 | % | | 52 | % | | 52 | % | | — | % | | 48 | % | | 49 | % | | 50 | % | Member’s equity | — | % | | — | % | | — | % | | — | % | | 57 | % | | — | % | | — | % | | — | % | Commercial paper and notes payable | 4 | % | | 2 | % | | 2 | % | | 4 | % | | 2 | % | | 4 | % | | 3 | % | | — | % |
__________ (a)As of December 31, 2021, Exelon's Long-term debt and ACE's net credit exposureCommon equity capital structure percentages were 50% and 45%, respectively. The change in capital structure percentages above is a result of a decrease in common equity due to suppliers was immaterial.the separation of Constellation in addition to an increase in long-term debt issuances. See Note 152 — Derivative Financial InstrumentsDiscontinued Operations for additional information regarding the separation. (b)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. Security Ratings 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 Combined Notesentity that is accessing the capital markets. The Registrants’ borrowings are not subject to Consolidated Financial Statements. Credit-Risk-Related Contingent Features (All Registrants)
Generationdefault 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 15 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regardingon collateral requirements. See Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information regarding the letters of credit supporting the cash collateral. Generation transacts output through bilateral contracts. The bilateral contracts are subject to credit risk, which relates to the ability of counterparties to meet their contractual payment obligations. Any failure to collect these payments from counterparties could have a material impact on Exelon’s and Generation’s financial statements. As market prices rise above or fall below contracted price levels, Generation is required to post collateral with purchasers; as market prices fall below contracted price levels, counterparties are required to post collateral with Generation. To post collateral, Generation depends on access to bank credit facilities, which serve as liquidity sources to fund collateral requirements. See ITEM 7. Liquidity and Capital Resources — Credit Matters — Exelon Credit Facilities for additional information.provisions.
The Utility Registrants As of December 31, 2019, the Utility Registrants werecredit ratings for ComEd, PECO, BGE, and DPL did not required to post collateral under their energy and/or natural gas procurement contracts. See Note 3 — Regulatory Matters and Note 15 — 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 incomechange 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 Instruments2022. On January 14, 2022, Fitch lowered Exelon Corporate's long-term and senior unsecured ratings from BBB+ to BBB and affirmed the short-term rating of the Combined NotesF2. In addition, Fitch upgraded Pepco, ACE, and PHI's long-term rating from BBB to Consolidated Financial Statements for additional information.
Equity Price Risk (ExelonBBB+ and Generation)
Exelonupgraded Pepco and Generation maintain trust funds, as required by the NRC,ACE's senior secured rating from A- 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.
A.
| | | ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
Generation
General
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
Contents
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 issuance 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, 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, and fund pension and other postretirement benefit obligations and invest in new and existing ventures. BGE spendsOPEB obligations. The 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.
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 $4.0 billion, as of December 31, 2022. 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 and Cash Flows from Operating Activities A discussion of items pertinent to BGE’sRequirements” section below for additional information. The Registrants expect cash flows fromto be sufficient to meet operating activities is set forth under Cash Flows from Operating Activities in EXELON CORPORATION — Liquidityexpenses, financing costs, and Capital Resources of this Form 10-K.
Cash Flows from Investing Activities
A discussion of items pertinent to BGE’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 BGE’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 BGE 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 BGE’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 BGE’s critical accounting policies and estimates.
New Accounting Pronouncements
capital expenditure requirements. See Note 116 — Significant Accounting PoliciesDebt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information regarding new accounting pronouncements.on the Registrants’ debt and credit agreements. Cash flows related to Generation have not been presented as discontinued operations and are included in the Consolidated Statements of Cash Flows for all periods presented. The Exelon Consolidated Statement of Cash Flows for the year ended December 31, 2022 includes one month of cash flows from Generation. The Exelon Consolidated Statement of Cash Flows for the year ended December 31, 2021 includes twelve months of cash flows from Generation. This is the primary reason for the changes in cash flows as shown in the tables unless otherwise noted below. | | | ITEM 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK | Cash Flows from Operating ActivitiesBGE
BGE is exposed to market risks associated with creditThe Utility Registrants' cash flows from operating activities primarily result from the transmission 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 consist of the purchase and regulated retail saledistribution of electricity and, in the provisioncase of PECO, BGE, and DPL, gas distribution services. The Utility Registrants' distribution services are provided to an established and transmission services,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. Additionally, ComEd is required to purchase CMCs from participating nuclear-powered generating facilities for a lesser extent,five-year period, and all of its costs of doing so will be recovered through a new rider. The price to be paid for each CMC is established through a competitive bidding process. ComEd will provide net payments to, or collect net payments from, customers for the purchasedifference between customer credits issued and regulated retail salethe credit to be received from the participating nuclear-powered generating facilities. ComEd’s cash flows are affected by the establishment of CMC prices and supplythe timing of natural gasrecovering costs through the CMC regulatory asset.
See Note 3 — Regulatory Matters and Note 18 — 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 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 Endedcash flows from operating activities for the years ended December 31, 2019 Compared to Year Ended December 31, 20182022 and 2021 by Registrant:
A discussion of PHI’s results of operations for 2019 compared to 2018 is set forth under Results of Operations—PHI | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Increase (decrease) in cash flows from operating activities | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Net income | $ | 342 | | | $ | 175 | | | $ | 72 | | | $ | (28) | | | $ | 47 | | | $ | 9 | | | $ | 41 | | | $ | 2 | | Adjustments to reconcile net income to cash: | | | | | | | | | | | | | | | | Non-cash operating activities | (2,382) | | | (176) | | | 124 | | | 173 | | | 259 | | | 93 | | | 25 | | | 141 | | Option premiums paid, net | 299 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Collateral received (posted), net | 1,322 | | | 51 | | | — | | | 16 | | | 99 | | | 22 | | | 35 | | | 42 | | Income taxes | (331) | | | — | | | (25) | | | (37) | | | (18) | | | (30) | | | (13) | | | 11 | | Pension and non-pension postretirement benefit contributions | 49 | | | 12 | | | — | | | 13 | | | (30) | | | — | | | — | | | (4) | | Regulatory assets and liabilities, net | (692) | | | (645) | | | (24) | | | (8) | | | (37) | | | 12 | | | 9 | | | (43) | | Changes in working capital and other noncurrent assets and liabilities | 3,251 | | | 185 | | | (79) | | | (98) | | | (227) | | | (97) | | | (64) | | | (60) | | Increase (decrease) in cash flows from operating activities | $ | 1,858 | | | $ | (398) | | | $ | 68 | | | $ | 31 | | | $ | 93 | | | $ | 9 | | | $ | 33 | | | $ | 89 | |
Changes 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 generatedthe 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. See above for additional information related to cash flows from Generation. Significant operating cash flow impacts for the Registrants and Generation for 2022 and 2021 were as follows:
•See Note 22 —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. •Changes in collateral depended upon whether Generation was in a net mark-to-market liability or asset position, and collateral may have been required to be posted with or collected from its counterparties. In addition, the collateral posting and collection requirements differed depending on whether the transactions were on an exchange or in the over-the-counter markets. Changes in collateral for the Utility Registrants are dependent upon the credit exposure of procurement contracts that may require suppliers to post collateral. The amount of cash collateral received from external counterparties increased due to rising energy prices. See Note 15 — Derivative Financial Instruments for additional information. •See Note 13 — 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 regulatory assets and liabilities, net, are due to the extent necessary, externaltiming of cash payments for costs recoverable, or cash receipts for costs recovered, under our regulatory mechanisms differs from the recovery period of those costs. Included within the changes is energy efficiency spend for ComEd of $394 million and $343 million for the years ended December 31, 2022 and 2021, respectively. Also included within the changes is energy efficiency and demand response programs spend for BGE, Pepco, DPL, and ACE of $113 million, $71 million, $28 million, and $11 million for the year ended December 31, 2022, respectively, and $107 million, $72 million, $29 million, and $4 million for the year ended December 31, 2021, respectively. PECO had no energy efficiency and demand response programs spend recorded to a regulatory asset for the years ended December 31, 2022 and 2021. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. •Changes in working capital and other noncurrent assets and liabilities for the Utility Registrants and Exelon Corporate total $(304) million and for Generation total $3,555 million. The change for Generation primarily relates to the revolving accounts receivable financing includingarrangement. See the Collection of DPP discussion below for additional information. The change in working capital and other noncurrent assets and liabilities for Exelon Corporate and the Utility Registrants is dependent upon the normal course of operations for all Registrants. For ComEd, it is also
dependent upon whether the participating nuclear-powered generating facilities owe money to ComEd as a result of the established pricing for CMCs. In 2022, the established pricing resulted in a receivable from nuclear-powered generating facilities, which is reported within the cash flows from operations as a change in accounts receivable. In future periods the established pricing could result in ComEd owing payments to nuclear-powered generating facilities, which would be reported within cash flows from operations as a change in accounts payable and accrued expenses. Cash Flows from Investing Activities The following table provides a summary of the change in cash flows from investing activities for the years ended December 31, 2022 and 2021 by Registrant: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Increase (decrease) in cash flows from investing activities | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Capital expenditures | $ | 834 | | | $ | (119) | | | $ | (109) | | | $ | (36) | | | $ | 11 | | | $ | (31) | | | $ | (1) | | | $ | 47 | | Investment in NDT fund sales, net | 113 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Collection of DPP | (3,733) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Proceeds from sales of assets and businesses | (861) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | | | | | | | | | | | | | | | | Other investing activities | (26) | | | 2 | | | (1) | | | (7) | | | 4 | | | 4 | | | (1) | | | — | | (Decrease) increase in cash flows from investing activities | $ | (3,673) | | | $ | (117) | | | $ | (110) | | | $ | (43) | | | $ | 15 | | | $ | (27) | | | $ | (2) | | | $ | 47 | |
Significant investing cash flow impacts for the Registrants for 2022 and 2021 were as follows: •Variances in capital expenditures are primarily due to the timing of cash expenditures for capital projects. See the "Credit Matters and Cash Requirements" section below for additional information on projected capital expenditure spending for the Utility Registrants. See Note 2 — Discontinued Operations of the Combined Notes to Consolidated Financial Statements for capital expenditures related to Generation prior to the separation. •Collection of DPP relates to Generation's revolving accounts receivable financing agreement which Generation entered into in April 2020. Generation received $400 million of additional funding related to the DPP in February and March of 2021. •Proceeds from sales of assets and businesses decreased primarily due to the sale of a significant portion of Generation's solar business and a biomass facility in 2021. Cash Flows from Financing Activities The following table provides a summary of the change in cash flows from financing activities for the years ended December 31, 2022 and 2021 by Registrant: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (Decrease) increase in cash flows from financing activities | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Changes in short-term borrowings, net | $ | (513) | | | $ | 900 | | | $ | 239 | | | $ | 148 | | | $ | (154) | | | $ | (16) | | | $ | (37) | | | $ | (101) | | Long-term debt, net | 2,395 | | | (50) | | | (25) | | | (50) | | | 50 | | | 40 | | | — | | | 10 | | Changes in intercompany money pool | — | | | — | | | 40 | | | — | | | 51 | | | — | | | — | | | — | | Issuance of common stock | 563 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Dividends paid on common stock | 163 | | | (71) | | | (60) | | | (8) | | | — | | | (195) | | | 4 | | | 143 | | Acquisition of noncontrolling interest | 885 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Distributions to member | — | | | — | | | — | | | — | | | (47) | | | — | | | — | | | — | | Contributions from parent/member | — | | | (121) | | | (140) | | | 29 | | | 104 | | | 221 | | | 27 | | | (144) | | Transfer of cash, restricted cash, and cash equivalents to Constellation | (2,594) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Other financing activities | (66) | | | 5 | | | (6) | | | (5) | | | (5) | | | (4) | | | — | | | — | | Increase (decrease) in cash flows from financing activities | $ | 833 | | | $ | 663 | | | $ | 48 | | | $ | 114 | | | $ | (1) | | | $ | 46 | | | $ | (6) | | | $ | (92) | |
Significant financing cash flow impacts for the Registrants for 2022 and 2021 were as follows: •Changes in short-term borrowings, net, are driven by repayments on and issuances of notes due in less than 365 days. Refer to Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on short-term borrowings for the Registrants. These changes also included repayments of $552 million in commercial paper and term loans by Generation prior to the separation. •Long-term debt, net, varies due to debt issuances and redemptions each year. Refer to the debt issuances and redemptions tables below for additional information for the Registrants. •Changes inintercompany money pool are driven by short-term borrowing needs. Refer below for more information regarding the intercompany money pool. •Issuance of common stock relates to the August 2022 underwritten public offering of Exelon common stock. See Note 19 — Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for additional information. •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. •Acquisition of noncontrolling interest relates to Generation's acquisition of CENG noncontrolling interest in 2021. •Refer to Note 2 — Discontinued Operations for the transfer of cash, restricted cash, and cash equivalents to Constellation related to the separation. •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 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of the Registrants’ long-term debt. Debt activity for 2022 and 2021 by Registrant was as follows: During 2022, the following long-term debt was issued: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Company | | Type | | Interest Rate | | Maturity | | Amount | | Use of Proceeds | Exelon | | SMBC Term Loan Agreement | | SOFR plus 0.65% | | July 21, 2023(a) | | $300 | | Fund a cash payment to Constellation and for general corporate purposes. | Exelon | | U.S. Bank Term Loan Agreement | | SOFR plus 0.65% | | July 21, 2023(a) | | 300 | | Fund a cash payment to Constellation and for general corporate purposes. | Exelon | | PNC Term Loan Agreement | | SOFR plus 0.65% | | July 24, 2023(a) | | 250 | | Fund a cash payment to Constellation and for general corporate purposes. | Exelon | | Notes(b) | | 2.75% | | March 15, 2027 | | 650 | | Repay existing indebtedness and for general corporate purposes. | Exelon | | Notes(b) | | 3.35% | | March 15, 2032 | | 650 | | Repay existing indebtedness and for general corporate purposes. | Exelon | | Notes(b) | | 4.10% | | March 15, 2052 | | 700 | | Repay existing indebtedness and for general corporate purposes. | Exelon | | Long-Term Software License Agreements | | 2.30% | | December 1, 2025 | | 17 | | Procurement of software licenses | Exelon | | Long-Term Software License Agreements | | 3.70% | | August 9, 2025 | | 8 | | Procurement of software licenses | Exelon | | SMBC Term Loan Agreement | | SOFR plus 0.85% | | April 7, 2024 | | 500 | | Repay existing indebtedness and for general corporate purposes. | ComEd(c) | | First Mortgage Bonds, Series 132 | | 3.15% | | March 15, 2032 | | 300 | | Repay outstanding commercial paper obligations and to fund other general corporate purposes. | ComEd | | First Mortgage Bonds, Series 133 | | 3.85% | | March 15, 2052 | | 450 | | Repay outstanding commercial paper obligations and to fund other general corporate purposes. | PECO | | First and Refunding Mortgage Bonds | | 4.60% | | May 15, 2052 | | 350 | | Refinance existing indebtedness and for general corporate purposes. | PECO | | First and Refunding Mortgage Bonds | | 4.375% | | August 15, 2052 | | 425 | | Refinance outstanding commercial paper and for general corporate purposes. | BGE | | Notes | | 4.55% | | June 1, 2052 | | 500 | | Repay outstanding commercial paper obligations, repay existing indebtedness, and for general corporate purposes. | Pepco | | First Mortgage Bonds | | 3.97% | | March 24, 2052 | | 400 | | Repay existing indebtedness and for general corporate purposes. | Pepco | | First Mortgage Bonds | | 3.35% | | September 15, 2032 | | 225 | | Repay existing indebtedness and for general corporate purposes. | DPL | | First Mortgage Bonds | | 3.06% | | February 15, 2052 | | 125 | | Repay existing indebtedness and for general corporate purposes. | ACE | | First Mortgage Bonds | | 2.27% | | February 15, 2032 | | 25 | | Repay existing indebtedness and for general corporate purposes. | ACE | | First Mortgage Bonds | | 3.06% | | February 15, 2052 | | 150 | | Repay existing indebtedness and for general corporate purposes. |
__________ (a)During the third quarter of 2022, the SMBC Term Loan, U.S. Bank Term Loan, and PNC Term Loan were all reclassified to Long-term debt due within one year on the Exelon Consolidated Balance Sheet, given that the Term Loans have maturity dates of July 21, 2023 , and July 24, 2023, respectively. (b)In connection with the issuance and sale of the Notes, Exelon entered into a Registration Rights Agreement with the representatives of the initial purchasers of the Notes and other parties. Pursuant to the Registration Rights Agreement,
Exelon filed a registration statement on August 3, 2022, with respect to an offer to exchange the Notes for substantially similar notes of Exelon that are registered under the Securities Act. An exchange offer of registered notes for the Notes was completed on January 12, 2023. The registered notes issued in exchange for Notes in the exchange offer have terms identical in all respects to the Notes, except that their issuance was registered under the Securities Act. (c)On January 3, 2023, ComEd entered into a purchase agreement of First Mortgage Bonds of $400 million and $575 million at 4.90% and 5.30% due on February 1, 2033 and February 1, 2053, respectively. The closing date of the issuance occurred on January 10, 2023. During 2021, the following long-term debt was issued: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Company | | Type | | Interest Rate | | Maturity | | Amount | | Use of Proceeds | Exelon | | Long-Term Software License Agreements | | 3.62% | | December 1, 2025 | | $4 | | Procurement of software licenses. | ComEd | | First Mortgage Bonds, Series 130 | | 3.13% | | March 15, 2051 | | 700 | | Repay a portion of outstanding commercial paper obligations and two outstanding term loans, and to fund other general corporate purposes. | ComEd | | First Mortgage Bonds, Series 131 | | 2.75% | | September 1, 2051 | | 450 | | Refinance existing indebtedness and for general corporate purposes. | PECO | | First and Refunding Mortgage Bonds | | 3.05% | | March 15, 2051 | | 375 | | Funding for general corporate purposes. | PECO | | First and Refunding Mortgage Bonds | | 2.85% | | September 15, 2051 | | 375 | | Refinance existing indebtedness and for general corporate purposes. | BGE | | Senior Notes | | 2.25% | | June 15, 2031 | | 600 | | Repay a portion of outstanding commercial paper obligations, repay existing indebtedness, and to fund other general corporate purposes. | Pepco | | First Mortgage Bonds | | 2.32% | | March 30, 2031 | | 150 | | Repay existing indebtedness and for general corporate purposes. | Pepco | | First Mortgage Bonds | | 3.29% | | September 28, 2051 | | 125 | | Repay existing indebtedness and for general corporate purposes. | DPL | | First Mortgage Bonds | | 3.24% | | March 30, 2051 | | 125 | | Repay existing indebtedness and for general corporate purposes. | 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 | | 2.27% | | February 15, 2032 | | 75 | | Repay existing indebtedness and for general corporate purposes. |
During 2022, the following long-term debt was retired and/or redeemed: | | | | | | | | | | | | | | | | | | | | | | | | | | | Company | | Type | | Interest Rate | | Maturity | | Amount | Exelon | | Junior Subordinated Notes | | 3.50% | | May 2, 2022 | | $ | 1,150 | | Exelon | | Long-Term Software License Agreement | | 3.96% | | May 1, 2024 | | 2 | Exelon | | Long-Term Software License Agreement | | 2.30% | | December 1, 2025 | | 4 | | Exelon | | Long-Term Software License Agreement | | 3.70% | | August 9, 2025 | | 1 | | PECO | | First Mortgage Bonds | | 2.375% | | September 15, 2022 | | 350 | | BGE | | Notes | | 2.80% | | August 15, 2022 | | 250 | Pepco | | First Mortgage Bonds | | 3.05% | | April 1, 2022 | | 200 | Pepco | | Tax-Exempt Bonds | | 1.70% | | September 1, 2022 | | 110 |
Additionally, in connection with the separation, on January 31, 2022, Exelon Corporate received cash from Generation of $258 million to settle an intercompany loan that mirrored the terms and amounts of the third-party debt obligations. The loan agreements were entered into as part of the 2012 Constellation merger. See Note 16
— Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the mirror debt. During 2021, the following long-term debt was retired and/or redeemed: | | | | | | | | | | | | | | | | | | | | | | | | | | | Company | | Type | | Interest Rate | | Maturity | | Amount | Exelon | | Senior Notes | | 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 |
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, 2022 and for the first quarter of 2023 were as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | Period | | Declaration Date | | Shareholder of Record Date | | Dividend Payable Date | | Cash per Share(a) | First Quarter 2022 | | February 8, 2022 | | February 25, 2022 | | March 10, 2022 | | $ | 0.3375 | | Second Quarter 2022 | | April 26, 2022 | | May 13, 2022 | | June 10, 2022 | | $ | 0.3375 | | Third Quarter 2022 | | July 26, 2022 | | August 15, 2022 | | September 9, 2022 | | $ | 0.3375 | | Fourth Quarter 2022 | | October 28, 2022 | | November 15, 2022 | | December 9, 2022 | | $ | 0.3375 | | First Quarter 2023 | | February 14, 2023 | | February 27, 2023 | | March 10, 2023 | | $ | 0.3600 | |
___________ (a)Exelon's Board of Directors approved an updated dividend policy for 2023. The 2023 quarterly dividend will be $0.36 per share. Credit Matters and Cash Requirements 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 borrowings frommarkets, and large, diversified credit facilities. The credit facilities include $4.0 billion in aggregate total commitments of which $2.1 billion was available to support additional commercial paper as of December 31, 2022, and of which no financial institution has more than 6% of the aggregate commitments for the Registrants. On February 1, 2022, Exelon money pool or capital contributions from Exelon. PHI’sCorporate and the Utility Registrants each entered into a new 5-year revolving credit facility that replaced its existing syndicated revolving credit facility. See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. The Registrants had access to external financing at reasonable terms is dependent on itsthe commercial paper markets and had availability under their revolving credit facilities during 2022 to fund their short-term liquidity needs, when necessary. 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 general business conditions, as well as thatoutlooks, 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 utility industrycapital 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.
On August 4, 2022, Exelon entered into an agreement with certain underwriters in general. connection with an underwritten public offering of 12.995 million shares of its common stock, no par value. The net proceeds were $563 million before expenses paid. Exelon used the proceeds, together with available cash balances, to repay $575 million in borrowings under a $1.15 billion term loan credit facility. See EXELON CORPORATIONNote 19 — Liquidity and Capital ResourcesShareholders' Equity 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 primarilyOn August 4, 2022, Exelon executed an equity distribution agreement (“Equity Distribution Agreement”) with certain sales agents and forward sellers and certain forward purchasers establishing an ATM equity distribution program under which it may offer and sell shares of its common stock, having an aggregate gross sales price of up to fund PHI’s capital requirements, including construction expenditures, retire debt, pay dividends, fund pension$1.0 billion. Exelon has no obligation to offer or sell any shares of common stock under the Equity Distribution Agreement and other postretirement benefit obligationsmay at any time suspend or terminate offers and invest in newsales under the Equity Distribution Agreement. As of December 31, 2022, Exelon has not issued any shares of common stock under the ATM program and existing ventures. PHI spendshas not entered into any forward sale agreements.
Pursuant to the Separation Agreement between Exelon and Constellation Energy Corporation, Exelon made a significant amountcash payment of cash$1.75 billion to Generation 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
January 31, 2022. See Note 12 — Significant Accounting PoliciesDiscontinued Operations of the Combined Notes to Consolidated Financial Statements for additional information on the separation. The following table presents the incremental collateral that each Utility Registrant would have been required to provide in the event each Utility Registrant lost its investment grade credit rating at December 31, 2022 and available credit facility capacity prior to any incremental collateral at December 31, 2022: | | | | | | | | | | | | | | | | | | | PJM Credit Policy Collateral | | Other Incremental Collateral Required(a) | | Available Credit Facility Capacity Prior to Any Incremental Collateral | ComEd | $ | 31 | | | $ | — | | | $ | 568 | | PECO | 1 | | | 71 | | | 361 | | BGE | 3 | | | 119 | | | 191 | | Pepco | 5 | | | — | | | 1 | | DPL | 6 | | | 15 | | | 185 | | ACE | 2 | | | — | | | 300 | | __________(a)Represents incremental collateral related to natural gas procurement contracts.
Capital Expenditures As of December 31, 2022, estimates of capital expenditures for plant additions and improvements are as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (in millions)(a) | 2023 Transmission | | 2023 Distribution | | 2023 Gas | | Total 2023 | | Beyond 2023(b) | Exelon | N/A | | N/A | | N/A | | $ | 7,175 | | | $ | 24,100 | | ComEd | 475 | | | 2,075 | | | N/A | | 2,550 | | | 8,575 | | PECO | 75 | | | 975 | | | 325 | | | 1,375 | | | 4,825 | | BGE | 325 | | | 525 | | | 475 | | | 1,325 | | | 4,700 | | PHI | 550 | | | 1,225 | | | 125 | | | 1,900 | | | 6,000 | | Pepco | 250 | | | 650 | | | N/A | | 900 | | | 2,825 | | DPL | 175 | | | 275 | | | 125 | | | 575 | | | 1,800 | | ACE | 150 | | | 300 | | | N/A | | 425 | | | 1,400 | |
___________ (a)Numbers rounded to the nearest $25M and may not sum due to rounding. (b)Includes estimated capital expenditures for the Utility Registrants from 2024 and 2026. 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. Retirement 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 annual contributions with the objective of achieving 100% funded status on an ABO basis over time. This funding strategy helps minimize volatility of future period required pension contributions. Exelon’s estimated annual qualified pension contributions will be $20 million in 2023. 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 2023: | | | | | | | | | | | | | | | | | | | Qualified Pension Plans | | Non-Qualified Pension Plans | | OPEB | Exelon | $ | 20 | | | $ | 48 | | | $ | 47 | | ComEd | 20 | | | 3 | | | 19 | | PECO | — | | | 1 | | | — | | BGE | — | | | 1 | | | 15 | | | | | | | | PHI | — | | | 9 | | | 11 | | Pepco | — | | | 1 | | | 11 | | DPL | — | | | — | | | — | | ACE | — | | | — | | | — | | | | | | | |
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 14 — 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, 2022 under existing financial commitments:
Exelon | | | | | | | | | | | | | | | | | | | | | | | | | 2023 | | Beyond 2023 | | Total | | Time Period | Long-term debt(a) | $ | 1,788 | | | $ | 35,289 | | | $ | 37,077 | | | 2023 - 2053 | Interest payments on long-term debt(b) | 1,476 | | | 23,645 | | | 25,121 | | | 2023 - 2052 | Operating leases(c) | 52 | | | 327 | | | 379 | | | 2023 - 2106 | Fuel purchase agreements(d) | 321 | | | 1,076 | | | 1,397 | | | 2023 - 2038 | | | | | | | | | Electric supply procurement | 4,041 | | | 2,407 | | | 6,448 | | | 2023 - 2026 | Long-term renewable energy and REC commitments | 348 | | | 1,483 | | | 1,831 | | | 2023 - 2038 | Other purchase obligations(c)(e) | 4,816 | | | 3,070 | | | 7,886 | | | 2023 - 2032 | DC PLUG obligation | 34 | | | 3 | | | 37 | | | 2023 - 2024 | ZEC commitments | 99 | | | 676 | | | 775 | | | 2023 - 2027 | Pension contributions(f) | 20 | | | 704 | | | 724 | | | 2023 - 2028 | Total cash requirements | $ | 12,995 | | | $ | 68,680 | | | $ | 81,675 | | | |
__________ (a)Includes amounts from ComEd and PECO financing trusts. (b)Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2022 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, 2022. Includes estimated interest payments due to ComEd and PECO financing trusts. (c)These amounts exclude payments and obligations related to the Baltimore City Conduit system lease. In January 2023, BGE signed an agreement to extend its use of the Baltimore City Conduit system through December 2026. Over the term of the new agreement, BGE has committed to pay the City of Baltimore approximately $19 million and also incur $120 million of capital improvements to the Conduit system. However, the agreement is still pending approval by Baltimore City which is expected to occur in the first quarter of 2023. Once approved, the agreement would be effective immediately. (d)Represents commitments to purchase natural gas and related transportation, storage capacity, and services. (e)Represents the future estimated value at December 31, 2022 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. (f)These amounts represent Exelon’s expected contributions to its qualified pension plans. Qualified pension contributions for years after 2028 are not included.
ComEd | | | | | | | | | | | | | | | | | | | | | | | | | 2023 | | Beyond 2023 | | Total | | Time Period | Long-term debt(a) | $ | — | | | $ | 10,835 | | | $ | 10,835 | | | 2023 - 2053 | Interest payments on long-term debt(b) | 421 | | | 7,640 | | | 8,061 | | | 2023 - 2052 | Operating leases | 2 | | | — | | | 2 | | | 2023 - 2026 | | | | | | | | | Electric supply procurement | 955 | | | 450 | | | 1,405 | | | 2023 - 2025 | Long-term renewable energy and REC commitments | 318 | | | 1,299 | | | 1,617 | | | 2023 - 2038 | Other purchase obligations(c) | 1,124 | | | 488 | | | 1,612 | | | 2023 - 2032 | ZEC commitments | 99 | | | 676 | | | 775 | | | 2023 - 2027 | Total cash requirements | $ | 2,919 | | | $ | 21,388 | | | $ | 24,307 | | | |
__________ (a)Includes amounts from ComEd financing trust. (b)Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2022 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, as of December 31, 2022, 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 | | | | | | | | | | | | | | | | | | | | | | | | | 2023 | | Beyond 2023 | | Total | | Time Period | Long-term debt(a) | $ | 50 | | | $ | 4,809 | | | $ | 4,859 | | | 2023 - 2052 | Interest payments on long-term debt(b) | 194 | | | 4,053 | | | 4,247 | | | 2023 - 2052 | Operating leases | — | | | 1 | | | 1 | | | 2023 - 2034 | Fuel purchase agreements(c) | 172 | | | 307 | | | 479 | | | 2023 - 2029 | Electric supply procurement | 767 | | | 313 | | | 1,080 | | | 2023 - 2024 | Other purchase obligations(d) | 835 | | | 593 | | | 1,428 | | | 2023 - 2030 | Total cash requirements | $ | 2,018 | | | $ | 10,076 | | | $ | 12,094 | | | |
__________ (a)Includes amounts from PECO financing trusts. (b)Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2022 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, as of December 31, 2022, 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 | | | | | | | | | | | | | | | | | | | | | | | | | 2023 | | Beyond 2023 | | Total | | Time Period | Long-term debt | $ | 300 | | | $ | 3,950 | | | $ | 4,250 | | | 2023 - 2052 | Interest payments on long-term debt(a) | 151 | | | 2,836 | | | 2,987 | | | 2023 - 2052 | Operating leases(b) | 1 | | | 18 | | | 19 | | | 2023 - 2106 | Fuel purchase agreements(c) | 116 | | | 573 | | | 689 | | | 2023 - 2038 | Electric supply procurement | 1,003 | | | 755 | | | 1,758 | | | 2023 - 2025 | Other purchase obligations(b)(d) | 966 | | | 299 | | | 1,265 | | | 2023 - 2028 | Total cash requirements | $ | 2,537 | | | $ | 8,431 | | | $ | 10,968 | | | |
__________ (a)Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2022 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. (b)These amounts exclude payments and obligations related to the Baltimore City Conduit system lease. In January 2023, BGE signed an agreement to extend its use of the Baltimore City Conduit system through December 2026. Over the term of the new agreement, BGE has committed to pay the City of Baltimore approximately $19 million and also incur $120 million of capital improvements to the Conduit system. However, the agreement is still pending approval by Baltimore City which is expected to occur in the first quarter of 2023. Once approved, the agreement would be effective immediately. (c)Represents commitments to purchase natural gas and related transportation, storage capacity, and services. (d)Represents the future estimated value, as of December 31, 2022, 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 | | | | | | | | | | | | | | | | | | | | | | | | | 2023 | | Beyond 2023 | | Total | | Time Period | Long-term debt | $ | 577 | | | $ | 7,042 | | | $ | 7,619 | | | 2023 - 2052 | Interest payments on long-term debt(a) | 314 | | | 4,438 | | | 4,752 | | | 2023 - 2052 | Finance leases | 14 | | | 68 | | | 82 | | | 2023 - 2030 | Operating leases | 37 | | | 195 | | | 232 | | | 2023 - 2032 | Fuel purchase agreements(b) | 33 | | | 196 | | | 229 | | | 2023 - 2028 | Electric supply procurement | 1,316 | | | 889 | | | 2,205 | | | 2023 - 2026 | Long-term renewable energy and REC commitments | 30 | | | 184 | | | 214 | | | 2023 - 2033 | Other purchase obligations(c) | 1,335 | | | 710 | | | 2,045 | | | 2023 - 2031 | DC PLUG obligation | 34 | | | 3 | | | 37 | | | 2023 - 2024 | Total cash requirements | $ | 3,690 | | | $ | 13,725 | | | $ | 17,415 | | | |
__________ (a)Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2022 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, 2022. (b)Represents commitments to purchase natural gas and related transportation, storage capacity, and services. (c)Represents the future estimated value, as of December 31, 2022, 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 | | | | | | | | | | | | | | | | | | | | | | | | | 2023 | | Beyond 2023 | | Total | | Time Period | Long-term debt | $ | — | | | $ | 3,773 | | | $ | 3,773 | | | 2023 - 2052 | Interest payments on long-term debt(a) | 170 | | | 2,659 | | | 2,829 | | | 2023 - 2052 | Finance leases | 5 | | | 23 | | | 28 | | | 2023 - 2030 | Operating leases | 7 | | | 41 | | | 48 | | | 2023 - 2032 | Electric supply procurement | 597 | | | 453 | | | 1,050 | | | 2023 - 2026 | Other purchase obligations(b) | 696 | | | 334 | | | 1,030 | | | 2023 - 2027 | DC PLUG obligation | 34 | | | 3 | | | 37 | | | 2023 - 2024 | Total cash requirements | $ | 1,509 | | | $ | 7,286 | | | $ | 8,795 | | | |
__________ (a)Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2022 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. (b)Represents the future estimated value, as of December 31, 2022, 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 | | | | | | | | | | | | | | | | | | | | | | | | | 2023 | | Beyond 2023 | | Total | | Time Period | Long-term debt | $ | 578 | | | $ | 1,337 | | | $ | 1,915 | | | 2023 - 2052 | Interest payments on long-term debt(a) | 68 | | | 1,061 | | | 1,129 | | | 2023 - 2052 | Finance leases | 6 | | | 28 | | | 34 | | | 2023 - 2030 | Operating leases | 10 | | | 52 | | | 62 | | | 2023 - 2032 | Fuel purchase agreements(b) | 33 | | | 196 | | | 229 | | | 2023 - 2028 | Electric supply procurement | 358 | | | 220 | | | 578 | | | 2023 - 2025 | Long-term renewable energy and REC commitments | 30 | | | 184 | | | 214 | | | 2023 - 2033 | Other purchase obligations(c) | 270 | | | 158 | | | 428 | | | 2023 - 2031 | Total cash requirements | $ | 1,353 | | | $ | 3,236 | | | $ | 4,589 | | | |
__________ (a)Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2022 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, 2022. (b)Represents commitments to purchase natural gas and related transportation, storage capacity, and services. (c)Represents the future estimated value, as of December 31, 2022, 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 | | | | | | | | | | | | | | | | | | | | | | | | | 2023 | | Beyond 2023 | | Total | | Time Period | Long-term debt | $ | — | | | $ | 1,747 | | | $ | 1,747 | | | 2023 - 2052 | Interest payments on long-term debt(a) | 62 | | | 598 | | | 660 | | | 2023 - 2052 | Finance leases | 3 | | | 17 | | | 20 | | | 2023 - 2030 | Operating leases | 4 | | | 7 | | | 11 | | | 2023 - 2028 | Electric supply procurement | 361 | | | 216 | | | 577 | | | 2023 - 2025 | Other purchase obligations(b) | 323 | | | 168 | | | 491 | | | 2023 - 2027 | Total cash requirements | $ | 753 | | | $ | 2,753 | | | $ | 3,506 | | | |
__________ (a)Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2022 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. (b)Represents the future estimated value, as of December 31, 2022, 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 new accounting pronouncements. 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 16 — Debt and Credit Agreements | Interest payments on long-term debt | Note 16 — Debt and Credit Agreements | Finance leases | Note 10 — Leases | Operating leases | Note 10 — Leases | | | ITEM 7A.REC commitments | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKNote 3 — Regulatory Matters | ZEC commitments | Note 3 — Regulatory Matters | DC PLUG obligation | Note 3 — Regulatory Matters | Pension contributions | Note 14 — Retirement Benefits |
PHICredit Facilities
PHI is exposed to market risks associated with creditExelon Corporate, ComEd, 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 consist 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 Compared 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 areBGE meet their short-term liquidity requirements primarily provided by internally generated cash flows from operations and, to the extent necessary, external financing, includingthrough the issuance of long-term debt,commercial paper. PECO meets its short-term liquidity requirements primarily through the issuance of commercial paper orand 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 facility borrowings. Pepco’s access to external financing at reasonable terms is dependent on its credit ratingsfacilities for general corporate purposes, including meeting short-term funding requirements and general business conditions, as well as thatthe issuance of the utility industry in general. At December 31, 2019, Pepco had access to a revolving credit facility with aggregate bank commitmentsletters of $300 million.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.information on the Registrants’ credit facilities and short term borrowing activity. 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
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.
Contents
Capital Structure
Credit MattersAs of December 31, 2022, the capital structures of the Registrants consisted of the following:
A discussion | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exelon(a) | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Long-term debt | 57 | % | | 43 | % | | 44 | % | | 44 | % | | 41 | % | | 48 | % | | 48 | % | | 50 | % | Long-term debt to affiliates(b) | 1 | % | | 1 | % | | 2 | % | | — | % | | — | % | | — | % | | — | % | | — | % | Common equity | 38 | % | | 54 | % | | 52 | % | | 52 | % | | — | % | | 48 | % | | 49 | % | | 50 | % | Member’s equity | — | % | | — | % | | — | % | | — | % | | 57 | % | | — | % | | — | % | | — | % | Commercial paper and notes payable | 4 | % | | 2 | % | | 2 | % | | 4 | % | | 2 | % | | 4 | % | | 3 | % | | — | % |
__________ (a)As of credit matters pertinentDecember 31, 2021, Exelon's Long-term debt and Common equity capital structure percentages were 50% and 45%, respectively. The change in capital structure percentages above is a result of a decrease in common equity due to Pepco is set forth under Credit Mattersthe separation of Constellation 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 Arrangementsaddition to an increase 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
long-term debt issuances. See Note 12 — Significant Accounting PoliciesDiscontinued Operations for additional information regarding the separation. (b)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. Security Ratings 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 15 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding new accounting pronouncements.on collateral provisions. The credit ratings for ComEd, PECO, BGE, and DPL did not change for the year ended December 31, 2022. On January 14, 2022, Fitch lowered Exelon Corporate's long-term and senior unsecured ratings 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 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, 2022, are presented in the following tables. ACE did not have any intercompany money pool activity as of December 31, 2022. | | | | | | | | | | | | | | | | | | | For the Year Ended December 31, 2022 | | As of December 31, 2022 | Exelon Intercompany Money Pool | Maximum Contributed | | Maximum Borrowed | | Contributed (Borrowed) | Exelon Corporate | $ | 396 | | | $ | — | | | $ | 182 | | PECO | 138 | | | (105) | | | — | | BSC | — | | | (380) | | | (183) | | PHI Corporate | — | | | (54) | | | (44) | | PCI | 50 | | | — | | | 45 | |
| | | | | | | | | | | | | | | | | | | For the Year Ended December 31, 2022 | | As of December 31, 2022 | PHI Intercompany Money Pool | Maximum Contributed | | Maximum Borrowed | | Contributed (Borrowed) | | | | | | | Pepco | $ | — | | | $ | (108) | | | $ | — | | DPL | 108 | | | — | | | — | | | | | | | | | | | | | |
Shelf Registration Statements Exelon and the Utility Registrants have a currently effective combined shelf registration statement, unlimited in amount, filed with the SEC on August 3, 2022, that will expire in August 2025. 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 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, 2022 | | | Short-term Financing Authority | | Remaining Long-term Financing Authority | Commission | | Expiration Date | | Amount | Commission | | Expiration Date | | Amount | ComEd(a) | | FERC | | December 31, 2023 | | $ | 2,500 | | | ICC | | January 1, 2025 | | $ | 1,343 | | PECO(b) | | FERC | | December 31, 2023 | | 1,500 | | | PAPUC | | December 31, 2024 | | 1,125 | | BGE(c) | | FERC | | December 31, 2023 | | 700 | | | MDPSC | | N/A | | — | | Pepco(d) | | FERC | | December 31, 2023 | | 500 | | | MDPSC / DCPSC | | 2022 & 2025 | | 1,400 | | DPL(e) | | FERC | | December 31, 2023 | | 500 | | | MDPSC / DEPSC | | December 31, 2025 | | 1,200 | | ACE(f) | | NJBPU | | December 31, 2023 | | 350 | | | NJBPU | | December 31, 2024 | | 700 | |
__________ (a)On November 18, 2021, ComEd received approval from the ICC for $2 billion in new money long-term debt financing authority with an effective date of January 1, 2022. (b)On December 2, 2021, PECO received approval from the PAPUC for $2.5 billion in new long-term debt financing authority with an effective date of January 1, 2022. (c)On December 21, 2022, BGE received approval from the MDPSC for $1.8 billion in new long-term financing authority with an effective date of January 4, 2023. (d)On June 9, 2022 and June 30, 2022, Pepco received approval from the MDPSC and DCPSC, respectively, for $1.4 billion in new long-term financing authority. The long-term financing authority became effective on the date of respective approvals and has an expiration date of December 31, 2025. (e)On November 2, 2022, DPL filed with the MDPSC and DEPSC for approval of $1.2 billion in new long-term financing authority with an effective date of December 14, 2022. The financing authority filed with MDPSC does not have an expiration date, while the financing authority filed with DEPSC has an expiration date of December 31, 2025.
(f)On July 13, 2022, ACE received approval from the NJBPU for $700 million in new long-term debt financing authority with an effective date of July 20, 2022.
| | | | | | ITEM 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
Pepco
Pepco isThe Registrants hold commodity and financial instruments that are exposed to the following market risksrisks:
•Commodity price risk, which is discussed further below. •Counterparty credit risk associated with non-performance by counterparties on executed derivative instruments and participation in all, or some of the established, wholesale spot energy markets that are administered by PJM. The credit policies of PJM may, under certain circumstances, require that losses arising from the default of one member on spot energy market transactions be shared by the remaining participants. See Note 15 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for a detailed discussion of counterparty credit risk related to derivative instruments. •Equity price and interest rates. These risks are described above under Quantitativerate risk associated with Exelon’s pension 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 consistOPEB plan trusts. See Note 14 — Retirement Benefits of the purchase and regulated retail sale of electricity and2021 Recast Form 10-K for additional information.
•Interest rate risk associated with changes in interest rates for 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.Registrants’ outstanding long-term debt. This segmentrisk is discussed in further detail in ITEM 1. BUSINESS — DPL of this Form 10-K. Executive Overview
A discussion of items pertinent to DPL’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 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 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. DPL’s access to external financing at reasonable terms is dependent on its credit ratings and general business conditions,significantly reduced as well as thatsubstantially all of the utility industry in general. If these conditions deteriorateRegistrants’ outstanding debt has fixed interest rates. There is inherent interest rate risk related to where DPL no longer has accessrefinancing maturing debt by issuing new long-term debt. The Registrants use a combination of fixed-rate and variable-rate debt to the capital markets 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 commitments of $300 million.
manage interest rate exposure. 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 In addition, Exelon Corporate may utilize interest rate derivatives to lock in rate levels in anticipation of future financings, which are used primarilytypically designated as cash flow hedges, or to fund DPL’s capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and other postretirement benefit obligations and investlock in new and existing ventures. DPL spends a significant amount of cashrate levels on capital improvements and construction projects that have a long-term return on investment. Additionally, DPL operates in a rate-regulated environment inborrowings, 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
are typically designated as economic hedges. See Note 115 — Significant Accounting PoliciesDerivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for information regarding new accounting pronouncements.additional information. | | | ITEM 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
DPL
DPL is exposed to market risks•Electric operating revenues risk associated with creditComEd's distribution formula rate. ComEd's ROE for its electric distribution service through 2023 is directly correlated to yields on U.S. Treasury bonds. Exelon Corporate may utilize interest rate derivatives to mitigate volatility and interest rates. These risksmanage risk to Exelon, which 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 operationstypically accounted 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 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 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
economic hedges. See Note 115 — Significant Accounting PoliciesDerivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for information regarding new accounting pronouncements.additional information. The Registrants operate primarily under cost-based rate regulation limiting exposure to the effects of market risk. Hedging programs are utilized to reduce exposure to energy and natural gas price volatility and have no direct earnings impacts as the costs are fully recovered through regulatory-approved recovery mechanisms. | | | ITEM 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK | 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. Risk management issues are reported to Exelon’s Board of Directors, Exelon's Audit and Risk Committee, and/or the applicable Utility Board Registrant. The Registrants do not execute derivatives for speculative or proprietary trading purposes.ACECommodity Price Risk (All Registrants)
ACECommodity 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 purchases differs from the amount of energy it has contracted to sell, Exelon is exposed to market risksfluctuations in commodity prices. Exelon seeks to mitigate its commodity price risk through the sale and purchase of electricity and natural gas.
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 qualify for NPNS, 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. For additional information on these contracts, see Note 3 — Regulatory Matters and Note 15 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements. The following table presents maturity and source of fair value for Exelon's and ComEd's mark-to-market commodity contract liabilities. The table provides two fundamental pieces of information. First, the table provides the source of fair value used in determining the carrying amount of Exelon's and ComEd's total mark-to-market liabilities. Second, the table shows the maturity, by year, of Exelon's and ComEd's commodity contract liabilities giving an indication of when these mark-to-market amounts will settle and require cash. See Note 17 — 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. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Maturities Within | | Total Fair Value | Commodity derivative contracts(a): | 2023 | | 2024 | | 2025 | | 2026 | | 2027 | | 2028 and Beyond | | Prices based on model or other valuation methods (Level 3) | $ | (5) | | | $ | (8) | | | $ | (11) | | | $ | (12) | | | $ | (13) | | | $ | (35) | | | $ | (84) | | _________(a)Represents ComEd's net liabilities associated with credit and interest rates. These risks are described above under Quantitative and Qualitative Disclosures about Market Risk— Exelon.the floating-to-fixed energy swap contracts with unaffiliated suppliers.
| | | | | | 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, 2019.2022. 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, 2019,2022, Exelon’s internal control over financial reporting was effective. The effectiveness of Exelon’s internal control over financial reporting as of December 31, 2019,2022, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein. February 14, 2023 February 11, 2020
Management’s Report on Internal Control Over Financial Reporting The management of Exelon Generation Company, LLC (Generation) 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.
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, 2019.2022. 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, 2019,2022, ComEd’s internal control over financial reporting was effective. February 11, 202014, 2023
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, 2019.2022. 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, 2019,2022, PECO’s internal control over financial reporting was effective. February 11, 202014, 2023
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, 2019.2022. 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, 2019,2022, BGE’s internal control over financial reporting was effective. February 11, 202014, 2023
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, 2019.2022. 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, 2019,2022, PHI’s internal control over financial reporting was effective. February 11, 202014, 2023
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, 2019.2022. 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, 2019,2022, Pepco’s internal control over financial reporting was effective. February 11, 202014, 2023
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, 2019.2022. 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, 2019,2022, DPL’s internal control over financial reporting was effective. February 11, 202014, 2023
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, 2019.2022. 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, 2019,2022, ACE’s internal control over financial reporting was effective. February 11, 202014, 2023
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, of Exelon Corporation and its subsidiaries (the “Company”) 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, 2019,2022, 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, 20192022 and 2018,2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 20192022 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, 2019,2022, 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 mattersmatter communicated beloware matters is a matter arising from the current period audit of the consolidated financial statements that werewas communicated or required to be communicated to the audit committee and that (i) relaterelates 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 mattersmatter below, providing a separate opinionsopinion on the critical audit mattersmatter or on the accounts or disclosures to which they relate.
Annual Nuclear Decommissioning Asset Retirement Obligations (ARO) Assessment
As described in Notes 1 and 9 to the consolidated financial statements, Exelon Generation has a legal obligation to decommission its nuclear generation stations following the expiration of their operating licenses. To estimate its decommissioning obligation related to its nuclear generating stations for financial accounting and reporting purposes, management uses a probability-weighted cash flow model, which on a unit-by-unit basis, considers multiple scenarios that include significant estimates and assumptions such as 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, the nuclear decommissioning asset retirement obligation was approximately $10.5 billion.
The principal considerations for our determination that performing procedures relating to Exelon Generation’s annual ARO assessment is a critical audit matter are there was a significant amount of judgment by management when estimating its decommissioning obligation. This in turn led to significant auditor judgment, subjectivity, and effort in performing procedures to evaluate management’s cash flow model and significant assumptions, including the 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.
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 developing the ARO estimates by evaluating the appropriateness of the cash flow model, testing the completeness and accuracy of data used by management, and evaluating the reasonableness of management’s significant assumptions, including 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 and 11 to the consolidated financial statements, Exelon Generation 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 and asset groups are impaired by comparing the undiscounted expected future
cash flows to the carrying value. When the undiscounted cash flow analysis indicates a long-lived asset or asset group is not recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset or asset group over its fair value. The undiscounted expected future cash flows include significant unobservable inputs including revenue and generation forecasts and projected capital and maintenance expenditures. As of December 31, 2019, the total carrying value of long-lived generation assets subject to this evaluation was approximately $24.2 billion.
The principal considerations for our determination that performing procedures relating to Exelon Generation’s impairment assessment of long-lived generation assets is a critical audit matter are there was a significant amount of judgment by management in assessing the recoverability of these assets or asset groups. This in turn led to significant auditor judgment, subjectivity and effort in performing procedures to evaluate the audit evidence related to the reasonableness of management’s significant assumptions used in management's estimates, including revenue and generation forecasts. In addition, the audit effort involved the use of professionals with specialized skills 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 recoverability of Exelon Generation’s long-lived generation assets or asset groups. These procedures also included, among others, testing management’s process for developing undiscounted expected future cash flows for long-lived generation assets 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, including revenue and generation forecasts. Professionals with specialized skill and knowledge were used to assist in evaluating the reasonableness of 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.
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 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, 2019,2022, there were $9.5$9.7 billion of regulatory assets and $10.4$9.5 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, 202014, 2023
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, of Commonwealth Edison Company and its subsidiaries (the “Company”) 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 Generation 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, 20192022 and 2018,2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 20192022 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, 2022, there were $3.4 billion of regulatory assets and $7.1 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, 202014, 2023
We have served as the Company's auditor since 2001.2000.
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders of Commonwealth EdisonPECO Energy Company
Opinion on the Financial Statements
We have audited the consolidated financial statements, including the related notes, of PECO Energy Company and its subsidiaries (the “Company”) 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 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, 20192022 and 2018,2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 20192022 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, 2022, there were $732 million of regulatory assets and $345 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, 202014, 2023
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, of Baltimore Gas and Electric Company (the “Company”) 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), (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of PECO Energythe Company as of December 31, 2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022 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, 2022, there were $704 million of regulatory assets and $863 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 14, 2023 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, of Pepco Holdings LLC and its subsidiaries (the “Company”) 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) (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, 20192022 and 2018,2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 20192022 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, 2022, there were $2.1 billion of regulatory assets and $1.1 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, 202014, 2023
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 consolidated financial statements, including the related notes, of Potomac Electric Power Company (the “Company”) as listed in the index appearing under Item 15(a)(5)(6)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(5)(6)(ii) (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, 2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022 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, 2022, there were $672 million of regulatory assets and $461 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 14, 2023
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, of Delmarva Power & Light Company (the “Company”) 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) (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of Baltimore Gasthe Company as of December 31, 2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022 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, 2022, there were $282 million of regulatory assets and $424 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 14, 2023
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, of Atlantic City Electric Company and its subsidiariessubsidiary (the “Company”) 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) (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, 20192022 and 2018,2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 20192022 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, 2022, there were $624 million of regulatory assets and $182 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, 202014, 2023
We have served as the Company's auditor since 1998.
Exelon Corporation and Subsidiary Companies Consolidated Statements of Operations and Comprehensive IncomeIncome | | | 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) | 2022 | | 2021 | | 2020 | Operating revenues | | | | | | Operating revenues | | | | | | Competitive businesses revenues | $ | 17,754 |
| | $ | 19,168 |
| | $ | 17,394 |
| | Rate-regulated utility revenues | 16,839 |
| | 16,879 |
| | 15,964 |
| | Electric operating revenues | | Electric operating revenues | $ | 16,899 | | | $ | 16,245 | | | $ | 15,236 | | Natural gas operating revenues | | Natural gas operating revenues | 2,018 | | | 1,522 | | | 1,421 | | Revenues from alternative revenue programs | (155 | ) | | (69 | ) | | 200 |
| Revenues from alternative revenue programs | 161 | | | 171 | | | 6 | | | Total operating revenues | 34,438 |
| | 35,978 |
| | 33,558 |
| Total operating revenues | 19,078 | | | 17,938 | | | 16,663 | | Operating expenses | | | | | | Operating expenses | | Competitive businesses purchased power and fuel | 10,849 |
| | 11,679 |
| | 9,668 |
| | Rate-regulated utility purchased power and fuel | 4,648 |
| | 4,991 |
| | 4,367 |
| | Purchased power | | Purchased power | 5,380 | | | 4,703 | | | 4,086 | | Purchased fuel | | Purchased fuel | 834 | | | 504 | | | 426 | | Purchased power and fuel from affiliates | | Purchased power and fuel from affiliates | 159 | | | 1,178 | | | 1,209 | | Operating and maintenance | 8,615 |
| | 9,337 |
| | 10,025 |
| Operating and maintenance | 4,673 | | | 4,547 | | | 4,641 | | Depreciation and amortization | 4,252 |
| | 4,353 |
| | 3,828 |
| Depreciation and amortization | 3,325 | | | 3,033 | | | 2,891 | | Taxes other than income taxes | 1,732 |
| | 1,783 |
| | 1,731 |
| Taxes other than income taxes | 1,390 | | | 1,291 | | | 1,232 | | Total operating expenses | 30,096 |
|
| 32,143 |
|
| 29,619 |
| Total operating expenses | 15,761 | | | 15,256 | | | 14,485 | | Gain on sales of assets and businesses | 31 |
| | 56 |
| | 3 |
| | Bargain purchase gain | — |
| | — |
| | 233 |
| | Gain on deconsolidation of business | 1 |
| | — |
| | 213 |
| | | (Loss) Gain on sales of assets and businesses | | (Loss) Gain on sales of assets and businesses | (2) | | | — | | | 13 | | | Operating income | 4,374 |
|
| 3,891 |
|
| 4,388 |
| Operating income | 3,315 | | | 2,682 | | | 2,191 | | Other income and (deductions) | | | | | | Other income and (deductions) | | Interest expense, net | (1,591 | ) | | (1,529 | ) | | (1,524 | ) | Interest expense, net | (1,422) | | | (1,264) | | | (1,282) | | Interest expense to affiliates | (25 | ) | | (25 | ) | | (36 | ) | Interest expense to affiliates | (25) | | | (25) | | | (25) | | Other, net | 1,227 |
| | (112 | ) | | 947 |
| Other, net | 535 | | | 261 | | | 208 | | Total other income and (deductions) | (389 | ) |
| (1,666 | ) |
| (613 | ) | Total other income and (deductions) | (912) | | | (1,028) | | | (1,099) | | Income before income taxes | 3,985 |
| | 2,225 |
| | 3,775 |
| | Income from continuing operations before income taxes | | Income from continuing operations before income taxes | 2,403 | | | 1,654 | | | 1,092 | | Income taxes | 774 |
| | 118 |
| | (126 | ) | Income taxes | 349 | | | 38 | | | (7) | | Equity in losses of unconsolidated affiliates | (183 | ) | | (28 | ) | | (32 | ) | | Net income | 3,028 |
|
| 2,079 |
|
| 3,869 |
| | Net income attributable to noncontrolling interests | 92 |
| | 74 |
| | 90 |
| | | Net income from continuing operations after income taxes | | Net income from continuing operations after income taxes | 2,054 | | | 1,616 | | | 1,099 | | Net income from discontinued operations after income taxes (Note 2) | | Net income from discontinued operations after income taxes (Note 2) | 117 | | | 213 | | | 855 | | Net Income | | Net Income | 2,171 | | | 1,829 | | | 1,954 | | Net income (loss) attributable to noncontrolling interests | | Net income (loss) attributable to noncontrolling interests | 1 | | | 123 | | | (9) | | Net income attributable to common shareholders | $ | 2,936 |
|
| $ | 2,005 |
|
| $ | 3,779 |
| Net income attributable to common shareholders | $ | 2,170 | | | $ | 1,706 | | | $ | 1,963 | | | Amounts attributable to common shareholders: | | Amounts attributable to common shareholders: | | Net income from continuing operations | | Net income from continuing operations | 2,054 | | | 1,616 | | | 1,099 | | Net income from discontinued operations | | Net income from discontinued operations | 116 | | | 90 | | | 864 | | Net income attributable to common shareholders | | Net income attributable to common shareholders | $ | 2,170 | | | $ | 1,706 | | | $ | 1,963 | | | Comprehensive income, net of income taxes | | | | | | Comprehensive income, net of income taxes | | Net income | $ | 3,028 |
| | $ | 2,079 |
| | $ | 3,869 |
| Net income | $ | 2,171 | | | $ | 1,829 | | | $ | 1,954 | | 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 | (1) | | | (4) | | | (40) | | Actuarial loss reclassified to periodic benefit cost | 149 |
| | 247 |
| | 197 |
| Actuarial loss reclassified to periodic benefit cost | 42 | | | 223 | | | 190 | | | Pension and non-pension postretirement benefit plan valuation adjustment | (289 | ) | | (143 | ) | | 10 |
| Pension and non-pension postretirement benefit plan valuation adjustment | 46 | | | 432 | | | (357) | | Unrealized gain on cash flow hedges | — |
| | 12 |
| | 3 |
| | Unrealized gain on marketable securities | — |
| | — |
| | 6 |
| | Unrealized gain on investments in unconsolidated affiliates | 1 |
| | 2 |
| | 4 |
| | Unrealized gain (loss) on foreign currency translation | 6 |
| | (10 | ) | | 7 |
| | Other comprehensive income | (198 | ) |
| 42 |
|
| 171 |
| | Unrealized gain (loss) on cash flow hedges | | Unrealized gain (loss) on cash flow hedges | 2 | | | (1) | | | (3) | | | Unrealized gain on foreign currency translation | | Unrealized gain on foreign currency translation | — | | | — | | | 4 | | | Other comprehensive income (loss) | | Other comprehensive income (loss) | 89 | | | 650 | | | (206) | | Comprehensive income | 2,830 |
|
| 2,121 |
|
| 4,040 |
| Comprehensive income | 2,260 | | | 2,479 | | | 1,748 | | Comprehensive income attributable to noncontrolling interests | 93 |
| | 75 |
| | 88 |
| | Comprehensive income (loss) attributable to noncontrolling interests | | Comprehensive income (loss) attributable to noncontrolling interests | 1 | | | 123 | | | (9) | | Comprehensive income attributable to common shareholders | $ | 2,737 |
| | $ | 2,046 |
|
| $ | 3,952 |
| Comprehensive income attributable to common shareholders | $ | 2,259 | | | $ | 2,356 | | | $ | 1,757 | | | | | | | | | Average shares of common stock outstanding: | | | | | | Average shares of common stock outstanding: | | Basic | 973 |
| | 967 |
| | 947 |
| Basic | 986 | | | 979 | | | 976 | | 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) | 987 | | | 980 | | | 977 | | Earnings per average common share: | | | | | | | | Earnings per average common share from continuing operations | | Earnings per average common share from continuing operations | | Basic | $ | 3.02 |
| | $ | 2.07 |
| | $ | 3.99 |
| Basic | $ | 2.08 | | | $ | 1.65 | | | $ | 1.13 | | Diluted | $ | 3.01 |
|
| $ | 2.07 |
| | $ | 3.98 |
| Diluted | $ | 2.08 | | | $ | 1.65 | | | $ | 1.13 | | | Earnings per average common share from discontinued operations | | Earnings per average common share from discontinued operations | | Basic | | Basic | $ | 0.12 | | | $ | 0.09 | | | $ | 0.88 | | Diluted | | Diluted | $ | 0.12 | | | $ | 0.09 | | | $ | 0.88 | |
__________ | | (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 were none for the year ended December 31, 2022 and 2021 and less than 1 million for the years ended December 31, 2020.
See the Combined Notes to Consolidated Financial Statements
178119
Exelon Corporation and Subsidiary Companies Consolidated Statements of Cash Flows | | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | (In millions) | 2022 | | 2021 | | 2020 | Cash flows from operating activities | | | | | | Net income | $ | 2,171 | | | $ | 1,829 | | | $ | 1,954 | | Adjustments to reconcile net income to net cash flows provided by operating activities: | | | | | | Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization | 3,533 | | | 7,573 | | | 6,527 | | Asset impairments | 48 | | | 552 | | | 591 | | Gain on sales of assets and businesses | (8) | | | (201) | | | (24) | | | | | | | | | | | | | | Deferred income taxes and amortization of investment tax credits | 255 | | | 18 | | | 309 | | Net fair value changes related to derivatives | (53) | | | (568) | | | (268) | | Net realized and unrealized gains on NDT funds | 205 | | | (586) | | | (461) | | Net unrealized losses (gains) on equity investments | 16 | | | 160 | | | (186) | | Other non-cash operating activities | 370 | | | (200) | | | 592 | | Changes in assets and liabilities: | | | | | | Accounts receivable | (1,222) | | | (703) | | | 697 | | Inventories | (121) | | | (141) | | | (85) | | Accounts payable and accrued expenses | 1,318 | | | 440 | | | (129) | | Option premiums paid, net | (39) | | | (338) | | | (139) | | Collateral received (posted), net | 1,248 | | | (74) | | | 494 | | Income taxes | (4) | | | 327 | | | 140 | | Regulatory assets and liabilities, net | (1,326) | | | (634) | | | (649) | | Pension and non-pension postretirement benefit contributions | (616) | | | (665) | | | (601) | | Other assets and liabilities | (905) | | | (3,777) | | | (4,527) | | Net cash flows provided by operating activities | 4,870 | | | 3,012 | | | 4,235 | | Cash flows from investing activities | | | | | | Capital expenditures | (7,147) | | | (7,981) | | | (8,048) | | | | | | | | Proceeds from NDT fund sales | 488 | | | 6,532 | | | 3,341 | | Investment in NDT funds | (516) | | | (6,673) | | | (3,464) | | Collection of DPP | 169 | | | 3,902 | | | 3,771 | | | | | | | | Proceeds from sales of assets and businesses | 16 | | | 877 | | | 46 | | | | | | | | | | | | | | Other investing activities | — | | | 26 | | | 18 | | Net cash flows used in investing activities | (6,990) | | | (3,317) | | | (4,336) | | Cash flows from financing activities | | | | | | | | | | | | Changes in short-term borrowings | 986 | | | 269 | | | 161 | | Proceeds from short-term borrowings with maturities greater than 90 days | 1,300 | | | 1,380 | | | 500 | | Repayments on short-term borrowings with maturities greater than 90 days | (1,500) | | | (350) | | | — | | Issuance of long-term debt | 6,309 | | | 3,481 | | | 7,507 | | Retirement of long-term debt | (2,073) | | | (1,640) | | | (6,440) | | | | | | | | | | | | | | Issuance of common stock | 563 | | | — | | | — | | | | | | | | | | | | | | Dividends paid on common stock | (1,334) | | | (1,497) | | | (1,492) | | Acquisition of CENG noncontrolling interest | — | | | (885) | | | — | | Proceeds from employee stock plans | 36 | | | 80 | | | 45 | | Transfer of cash, restricted cash, and cash equivalents to Constellation | (2,594) | | | — | | | — | | Other financing activities | (102) | | | (80) | | | (136) | | Net cash flows provided by financing activities | 1,591 | | | 758 | | | 145 | | (Decrease) increase in cash, restricted cash, and cash equivalents | (529) | | | 453 | | | 44 | | Cash, restricted cash, and cash equivalents at beginning of period | 1,619 | | | 1,166 | | | 1,122 | | Cash, restricted cash, and cash equivalents at end of period | $ | 1,090 | | | $ | 1,619 | | | $ | 1,166 | | | | | | | | Supplemental cash flow information | | | | | | Increase in capital expenditures not paid | $ | 36 | | | $ | 16 | | | $ | 194 | | Increase in DPP | 348 | | | 3,652 | | | 4,441 | | Increase in PP&E related to ARO update | 332 | | | 642 | | | 850 | |
| | | | | | | | | | | | | | 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
179120
Exelon Corporation and Subsidiary Companies
Consolidated Balance Sheets
| | | | | | | | | | 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
180
Exelon Corporation and Subsidiary Companies Consolidated Balance Sheets | | | | | | | | | | | | | December 31, | (In millions) | 2022 | | 2021 | ASSETS | | | | Current assets | | | | Cash and cash equivalents | $ | 407 | | | $ | 672 | | Restricted cash and cash equivalents | 566 | | | 321 | | | | | | Accounts receivable | | | | Customer accounts receivable | 2,544 | | 2,189 | Customer allowance for credit losses | (327) | | (320) | Customer accounts receivable, net | 2,217 | | | 1,869 | | Other accounts receivable | 1,426 | | 1,068 | Other allowance for credit losses | (82) | | (72) | Other accounts receivable, net | 1,344 | | | 996 | | | | | | | | | | Inventories, net | | | | Fossil fuel | 208 | | | 105 | | Materials and supplies | 547 | | | 476 | | | | | | Regulatory assets | 1,641 | | | 1,296 | | | | | | | | | | Other | 406 | | | 387 | | Current assets of discontinued operations | — | | | 7,835 | | Total current assets | 7,336 | | | 13,957 | | Property, plant, and equipment (net of accumulated depreciation and amortization of $15,930 and $14,430 as of December 31, 2022 and 2021, respectively) | 69,076 | | | 64,558 | | Deferred debits and other assets | | | | Regulatory assets | 8,037 | | | 8,224 | | Goodwill | 6,630 | | | 6,630 | | Receivable related to Regulatory Agreement Units | 2,897 | | | — | | Investments | 232 | | | 250 | | | | | | | | | | Other | 1,141 | | | 885 | | Property, plant, and equipment, deferred debits, and other assets of discontinued operations | — | | | 38,509 | | Total deferred debits and other assets | 18,937 | | | 54,498 | | Total assets | $ | 95,349 | | | $ | 133,013 | |
| | | | | | | | | | December 31, | (In millions) | 2019 | | 2018 | LIABILITIES AND SHAREHOLDERS’ EQUITY | | | | Current liabilities | | | | Short-term borrowings | $ | 1,370 |
| | $ | 714 |
| Long-term debt due within one year | 4,710 |
| | 1,349 |
| Accounts payable | 3,560 |
| | 3,800 |
| Accrued expenses | 1,981 |
| | 2,112 |
| Payables to affiliates | 5 |
| | 5 |
| Regulatory liabilities | 406 |
| | 644 |
| Mark-to-market derivative liabilities | 247 |
| | 475 |
| Unamortized energy contract liabilities | 132 |
| | 149 |
| Renewable energy credit obligation | 443 |
| | 344 |
| Liabilities held for sale | — |
| | 777 |
| Other | 1,331 |
| | 1,035 |
| Total current liabilities | 14,185 |
|
| 11,404 |
| Long-term debt | 31,329 |
| | 34,075 |
| Long-term debt to financing trusts | 390 |
| | 390 |
| Deferred credits and other liabilities | | | | Deferred income taxes and unamortized investment tax credits | 12,351 |
| | 11,321 |
| Asset retirement obligations | 10,846 |
| | 9,679 |
| Pension obligations | 4,247 |
| | 3,988 |
| Non-pension postretirement benefit obligations | 2,076 |
| | 1,928 |
| Spent nuclear fuel obligation | 1,199 |
| | 1,171 |
| Regulatory liabilities | 9,986 |
| | 9,559 |
| Mark-to-market derivative liabilities | 393 |
| | 479 |
| Unamortized energy contract liabilities | 338 |
| | 463 |
| Other | 3,064 |
| | 2,130 |
| Total deferred credits and other liabilities | 44,500 |
|
| 40,718 |
| Total liabilities(a) | 90,404 |
|
| 86,587 |
| 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 |
| Noncontrolling interests | 2,349 |
| | 2,306 |
| Total equity | 34,573 |
|
| 33,047 |
| Total liabilities and shareholders' equity | $ | 124,977 |
|
| $ | 119,634 |
|
__________
| | (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. |
See the Combined Notes to Consolidated Financial Statements
181121
Exelon Corporation and Subsidiary Companies Consolidated Balance Sheets | | | | | | | | | | | | | December 31, | (In millions) | 2022 | | 2021 | LIABILITIES AND SHAREHOLDERS’ EQUITY | | | | Current liabilities | | | | Short-term borrowings | $ | 2,586 | | | $ | 1,248 | | Long-term debt due within one year | 1,802 | | | 2,153 | | Accounts payable | 3,382 | | | 2,379 | | Accrued expenses | 1,226 | | | 1,137 | | Payables to affiliates | 5 | | | 5 | | | | | | Regulatory liabilities | 437 | | | 376 | | Mark-to-market derivative liabilities | 8 | | | 18 | | Unamortized energy contract liabilities | 10 | | | 89 | | | | | | | | | | | | | | Other | 1,155 | | | 766 | | Current liabilities of discontinued operations | — | | | 7,940 | | Total current liabilities | 10,611 | | | 16,111 | | Long-term debt | 35,272 | | | 30,749 | | Long-term debt to financing trusts | 390 | | | 390 | | Deferred credits and other liabilities | | | | Deferred income taxes and unamortized investment tax credits | 11,250 | | | 10,611 | | Regulatory liabilities | 9,112 | | | 9,628 | | Pension obligations | 1,109 | | | 2,051 | | Non-pension postretirement benefit obligations | 507 | | | 811 | | Asset retirement obligations | 269 | | | 271 | | Mark-to-market derivative liabilities | 83 | | | 201 | | Unamortized energy contract liabilities | 35 | | | 146 | | Other | 1,967 | | | 1,573 | | Long-term debt, deferred credits, and other liabilities of discontinued operations | — | | | 25,676 | | Total deferred credits and other liabilities | 24,332 | | | 50,968 | | Total liabilities | 70,605 | | | 98,218 | | Commitments and contingencies | | | | Shareholders’ equity | | | | Common stock (No par value, 2,000 shares authorized, 994 shares and 979 shares outstanding as of December 31, 2022 and 2021, respectively) | 20,908 | | | 20,324 | | Treasury stock, at cost (2 shares as of December 31, 2022 and 2021) | (123) | | | (123) | | Retained earnings | 4,597 | | | 16,942 | | Accumulated other comprehensive loss, net | (638) | | | (2,750) | | Total shareholders’ equity | 24,744 | | | 34,393 | | | | | | Noncontrolling interests | — | | | 402 | | Total equity | 24,744 | | | 34,795 | | Total liabilities and shareholders' equity | $ | 95,349 | | | $ | 133,013 | |
See the Combined Notes to Consolidated Financial Statements
122
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, 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 loss, net of income taxes | — | | | — | | | — | | | — | | | 650 | | | — | | | 650 | | Balance, December 31, 2021 | 981,291 | | | $ | 20,324 | | | $ | (123) | | | $ | 16,942 | | | $ | (2,750) | | | $ | 402 | | | $ | 34,795 | | Net income | — | | | — | | | — | | | 2,170 | | | — | | | 1 | | | 2,171 | | Long-term incentive plan activity | 561 | | | 1 | | | — | | | — | | | — | | | — | | | 1 | | Employee stock purchase plan issuances | 983 | | | 41 | | | — | | | — | | | — | | | — | | | 41 | | Changes in equity of noncontrolling interests | — | | | — | | | — | | | — | | | — | | | (7) | | | (7) | | Distribution of Constellation (Note 2) | — | | | (21) | | | — | | | (13,179) | | | 2,023 | | | (396) | | | (11,573) | | Issuance of common stock | 12,995 | | | 563 | | | — | | | — | | | — | | | — | | | 563 | | Common stock dividends ($1.35/common share) | — | | | — | | | — | | | (1,336) | | | — | | | — | | | (1,336) | | Other comprehensive income, net of income taxes | — | | | — | | | — | | | — | | | 89 | | | — | | | 89 | | Balance, December 31, 2022 | 995,830 | | | $ | 20,908 | | | $ | (123) | | | $ | 4,597 | | | $ | (638) | | | $ | — | | | $ | 24,744 | |
See the Combined Notes to Consolidated Financial Statements
182123
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) | 2022 | | 2021 | | 2020 | Operating revenues | | | | | | Electric operating revenues | $ | 5,478 | | | $ | 6,323 | | | $ | 5,914 | | Revenues from alternative revenue programs | 267 | | | 42 | | | (47) | | Operating revenues from affiliates | 16 | | | 41 | | | 37 | | Total operating revenues | 5,761 | | | 6,406 | | | 5,904 | | Operating expenses | | | | | | Purchased power | 1,050 | | | 1,888 | | | 1,653 | | Purchased power from affiliates | 59 | | | 383 | | | 345 | | Operating and maintenance | 1,094 | | | 1,048 | | | 1,231 | | Operating and maintenance from affiliates | 318 | | | 307 | | | 289 | | Depreciation and amortization | 1,323 | | | 1,205 | | | 1,133 | | Taxes other than income taxes | 374 | | | 320 | | | 299 | | Total operating expenses | 4,218 | | | 5,151 | | | 4,950 | | Loss on sales of assets | (2) | | | — | | | — | | Operating income | 1,541 | | | 1,255 | | | 954 | | Other income and (deductions) | | | | | | Interest expense, net | (401) | | | (376) | | | (369) | | Interest expense to affiliates | (13) | | | (13) | | | (13) | | Other, net | 54 | | | 48 | | | 43 | | Total other income and (deductions) | (360) | | | (341) | | | (339) | | Income before income taxes | 1,181 | | | 914 | | | 615 | | Income taxes | 264 | | | 172 | | | 177 | | Net income | $ | 917 | | | $ | 742 | | | $ | 438 | | | | | | | | | | | | | | | | | | | | Comprehensive income | $ | 917 | | | $ | 742 | | | $ | 438 | |
| | | | | | | | | | | | | | 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
188124
Commonwealth Edison Company and Subsidiary Companies Consolidated Statements of Cash Flows | | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | (In millions) | 2022 | | 2021 | | 2020 | Cash flows from operating activities | | | | | | Net income | $ | 917 | | | $ | 742 | | | $ | 438 | | Adjustments to reconcile net income to net cash flows provided by operating activities: | | | | | | Depreciation and amortization | 1,323 | | | 1,205 | | | 1,133 | | | | | | | | Deferred income taxes and amortization of investment tax credits | 241 | | | 244 | | | 228 | | | | | | | | Other non-cash operating activities | (165) | | | 126 | | | 202 | | Changes in assets and liabilities: | | | | | | Accounts receivable | (163) | | | (25) | | | (10) | | Receivables from and payables to affiliates, net | (34) | | | 32 | | | (1) | | Inventories | (28) | | | (2) | | | (13) | | Accounts payable and accrued expenses | 406 | | | — | | | 63 | | Collateral received, net | 51 | | | — | | | 14 | | Income taxes | — | | | — | | | 8 | | Regulatory assets and liabilities, net | (1,033) | | | (388) | | | (410) | | Pension and non-pension postretirement benefit contributions | (184) | | | (196) | | | (148) | | Other assets and liabilities | (134) | | | (143) | | | (180) | | Net cash flows provided by operating activities | 1,197 | | | 1,595 | | | 1,324 | | Cash flows from investing activities | | | | | | Capital expenditures | (2,506) | | | (2,387) | | | (2,217) | | | | | | | | | | | | | | Other investing activities | 28 | | | 26 | | | 2 | | Net cash flows used in investing activities | (2,478) | | | (2,361) | | | (2,215) | | Cash flows from financing activities | | | | | | Changes in short-term borrowings | 427 | | | (323) | | | 193 | | Proceeds from short-term borrowings with maturities greater than 90 days | 150 | | | — | | | — | | Issuance of long-term debt | 750 | | | 1,150 | | | 1,000 | | Retirement of long-term debt | — | | | (350) | | | (500) | | Dividends paid on common stock | (578) | | | (507) | | | (499) | | Contributions from parent | 670 | | | 791 | | | 712 | | Other financing activities | (11) | | | (16) | | | (13) | | Net cash flows provided by financing activities | 1,408 | | | 745 | | | 893 | | Increase (decrease) in cash, restricted cash, and cash equivalents | 127 | | | (21) | | | 2 | | Cash, restricted cash, and cash equivalents at beginning of period | 384 | | | 405 | | | 403 | | Cash, restricted cash, and cash equivalents at end of period | $ | 511 | | | $ | 384 | | | $ | 405 | | | | | | | | Supplemental cash flow information | | | | | | (Decrease) increase in capital expenditures not paid | $ | (20) | | | $ | (46) | | | $ | 109 | | | | | | | |
| | | | | | | | | | | | | | 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
189125
Commonwealth Edison Company and Subsidiary Companies Consolidated Balance Sheets | | | | | | | | | | | | | December 31, | (In millions) | 2022 | | 2021 | ASSETS | | | | Current assets | | | | Cash and cash equivalents | $ | 67 | | | $ | 131 | | Restricted cash and cash equivalents | 327 | | | 210 | | Accounts receivable | | | | Customer accounts receivable | 558 | | 647 | Customer allowance for credit losses | (59) | | (73) | Customer accounts receivable, net | 499 | | | 574 | | Other accounts receivable | 441 | | 227 | Other allowance for credit losses | (17) | | (17) | Other accounts receivable, net | 424 | | | 210 | | Receivables from affiliates | 3 | | | 16 | | Inventories, net | 196 | | | 170 | | | | | | | | | | Regulatory assets | 775 | | | 335 | | Other | 92 | | | 76 | | Total current assets | 2,383 | | | 1,722 | | Property, plant, and equipment (net of accumulated depreciation and amortization of $6,673 and $6,099 as of December 31, 2022 and 2021, respectively) | 27,513 | | | 25,995 | | Deferred debits and other assets | | | | Regulatory assets | 2,667 | | | 1,870 | | Goodwill | 2,625 | | | 2,625 | | Receivables from affiliates | — | | | 2,761 | | Receivable related to Regulatory Agreement Units | 2,660 | | | — | | Investments | 6 | | | 6 | | Prepaid pension asset | 1,206 | | | 1,086 | | Other | 601 | | | 405 | | Total deferred debits and other assets | 9,765 | | | 8,753 | | Total assets | $ | 39,661 | | | $ | 36,470 | |
| | | | | | | | | | 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
190126
Commonwealth Edison Company and Subsidiary Companies Consolidated Balance Sheets | | | | | | | | | | | | | December 31, | (In millions) | 2022 | | 2021 | LIABILITIES AND SHAREHOLDERS’ EQUITY | | | | Current liabilities | | | | Short-term borrowings | $ | 577 | | | $ | — | | | | | | Accounts payable | 1,010 | | | 647 | | Accrued expenses | 415 | | | 384 | | Payables to affiliates | 74 | | | 121 | | Customer deposits | 108 | | | 99 | | Regulatory liabilities | 226 | | | 185 | | Mark-to-market derivative liabilities | 5 | | | 18 | | | | | | | | | | Other | 191 | | | 133 | | Total current liabilities | 2,606 | | | 1,587 | | Long-term debt | 10,518 | | | 9,773 | | Long-term debt to financing trusts | 205 | | | 205 | | Deferred credits and other liabilities | | | | Deferred income taxes and unamortized investment tax credits | 5,021 | | | 4,685 | | Regulatory liabilities | 6,913 | | | 6,759 | | Asset retirement obligations | 148 | | | 144 | | Non-pension postretirement benefit obligations | 165 | | | 169 | | Mark-to-market derivative liabilities | 79 | | | 201 | | Other | 642 | | | 592 | | Total deferred credits and other liabilities | 12,968 | | | 12,550 | | Total liabilities | 26,297 | | | 24,115 | | Commitments and contingencies | | | | Shareholders’ equity | | | | Common stock ($12.50 par value, 250 shares authorized, 127 shares outstanding as of December 31, 2022 and 2021) | 1,588 | | | 1,588 | | Other paid-in capital | 9,746 | | | 9,076 | | Retained earnings | 2,030 | | | 1,691 | | Total shareholders’ equity | 13,364 | | | 12,355 | | Total liabilities and shareholders’ equity | $ | 39,661 | | | $ | 36,470 | |
| | | | | | | | | | December 31, | (In millions) | 2019 | | 2018 | LIABILITIES AND SHAREHOLDERS’ EQUITY | | | | Current liabilities | | | | Short-term borrowings | $ | 130 |
| | $ | — |
| Long-term debt due within one year | 500 |
| | 300 |
| Accounts payable | 527 |
| | 607 |
| Accrued expenses | 385 |
| | 373 |
| Payables to affiliates | 103 |
| | 119 |
| Customer deposits | 118 |
| | 111 |
| Regulatory liabilities | 200 |
| | 293 |
| Mark-to-market derivative liability | 32 |
| | 26 |
| Other | 122 |
| | 96 |
| Total current liabilities | 2,117 |
| | 1,925 |
| Long-term debt | 7,991 |
| | 7,801 |
| Long-term debt to financing trust | 205 |
| | 205 |
| Deferred credits and other liabilities | | | | Deferred income taxes and unamortized investment tax credits | 4,021 |
| | 3,813 |
| Asset retirement obligations | 128 |
| | 118 |
| Non-pension postretirement benefits obligations | 180 |
| | 201 |
| Regulatory liabilities | 6,542 |
| | 6,050 |
| Mark-to-market derivative liability | 269 |
| | 223 |
| Other | 635 |
| | 630 |
| Total deferred credits and other liabilities | 11,775 |
| | 11,035 |
| Total liabilities | 22,088 |
| | 20,966 |
| Commitments and contingencies |
| |
| Shareholders’ equity | | | | Common stock ($12.50 par value, 250 shares authorized, 127 shares outstanding at December 31, 2019 and 2018) | 1,588 |
| | 1,588 |
| Other paid-in capital | 7,572 |
| | 7,322 |
| Retained deficit unappropriated | (1,639 | ) | | (1,639 | ) | Retained earnings appropriated | 3,156 |
| | 2,976 |
| Total shareholders’ equity | 10,677 |
| | 10,247 |
| Total liabilities and shareholders’ equity | $ | 32,765 |
| | $ | 31,213 |
|
See the Combined Notes to Consolidated Financial Statements
191127
Commonwealth Edison Company and Subsidiary Companies Consolidated Statements of Changes in Shareholders’ Equity | | | | | | | | | | | | | | | | | | | | | | | | (In millions) | Common Stock | | Other Paid-In Capital | | Retained Earnings | | Total Shareholders’ Equity | Balance, December 31, 2019 | $ | 1,588 | | | $ | 7,572 | | | $ | 1,517 | | | $ | 10,677 | | Net income | — | | | — | | | 438 | | | 438 | | | | | | | | | | Common stock dividends | — | | | — | | | (499) | | | (499) | | Contributions from parent | — | | | 713 | | | — | | | 713 | | | | | | | | | | Balance, December 31, 2020 | $ | 1,588 | | | $ | 8,285 | | | $ | 1,456 | | | $ | 11,329 | | Net income | — | | | — | | | 742 | | | 742 | | | | | | | | | | Common stock dividends | — | | | — | | | (507) | | | (507) | | Contributions from parent | — | | | 791 | | | — | | | 791 | | | | | | | | | | Balance, December 31, 2021 | $ | 1,588 | | | $ | 9,076 | | | $ | 1,691 | | | $ | 12,355 | | Net income | — | | | — | | | 917 | | | 917 | | | | | | | | | | Common stock dividends | — | | | — | | | (578) | | | (578) | | Contributions from parent | — | | | 670 | | | — | | | 670 | | | | | | | | | | Balance, December 31, 2022 | $ | 1,588 | | | $ | 9,746 | | | $ | 2,030 | | | $ | 13,364 | |
| | | | | | | | | | | | | | | | | | | | | (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
192128
PECO Energy Company and Subsidiary Companies Consolidated Statements of Operations and Comprehensive Income | | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | (In millions) | 2022 | | 2021 | | 2020 | Operating revenues | | | | | | Electric operating revenues | $ | 3,156 | | | $ | 2,613 | | | $ | 2,519 | | Natural gas operating revenues | 738 | | | 538 | | | 514 | | Revenues from alternative revenue programs | 2 | | | 26 | | | 16 | | Operating revenues from affiliates | 7 | | | 21 | | | 9 | | Total operating revenues | 3,903 | | | 3,198 | | | 3,058 | | Operating expenses | | | | | | Purchased power | 1,160 | | | 699 | | | 645 | | Purchased fuel | 342 | | | 188 | | | 185 | | Purchased power from affiliates | 33 | | | 194 | | | 188 | | Operating and maintenance | 791 | | | 757 | | | 816 | | Operating and maintenance from affiliates | 201 | | | 177 | | | 159 | | Depreciation and amortization | 373 | | | 348 | | | 347 | | Taxes other than income taxes | 202 | | | 184 | | | 172 | | Total operating expenses | 3,102 | | | 2,547 | | | 2,512 | | | | | | | | Operating income | 801 | | | 651 | | | 546 | | Other income and (deductions) | | | | | | Interest expense, net | (165) | | | (149) | | | (136) | | Interest expense to affiliates, net | (12) | | | (12) | | | (11) | | Other, net | 31 | | | 26 | | | 18 | | Total other income and (deductions) | (146) | | | (135) | | | (129) | | Income before income taxes | 655 | | | 516 | | | 417 | | Income taxes | 79 | | | 12 | | | (30) | | | | | | | | | | | | | | Net income | $ | 576 | | | $ | 504 | | | $ | 447 | | Comprehensive income | $ | 576 | | | $ | 504 | | | $ | 447 | |
| | | | | | | | | | | | | | 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
193129
PECO Energy Company and Subsidiary Companies Consolidated Statements of Cash Flows | | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | (In millions) | 2022 | | 2021 | | 2020 | Cash flows from operating activities | | | | | | Net income | $ | 576 | | | $ | 504 | | | $ | 447 | | Adjustments to reconcile net income to net cash flows provided by operating activities: | | | | | | Depreciation and amortization | 373 | | | 348 | | | 347 | | | | | | | | | | | | | | Deferred income taxes and amortization of investment tax credits | 70 | | | 11 | | | (23) | | | | | | | | Other non-cash operating activities | 40 | | | — | | | 24 | | Changes in assets and liabilities: | | | | | | Accounts receivable | (205) | | | (35) | | | (88) | | Receivables from and payables to affiliates, net | (31) | | | 21 | | | (6) | | Inventories | (56) | | | (26) | | | (1) | | Accounts payable and accrued expenses | 152 | | | 15 | | | 63 | | | | | | | | Income taxes | (20) | | | 5 | | | 31 | | Regulatory assets and liabilities, net | (45) | | | (21) | | | 1 | | Pension and non-pension postretirement benefit contributions | (18) | | | (18) | | | (18) | | Other assets and liabilities | 5 | | | (31) | | | — | | Net cash flows provided by operating activities | 841 | | | 773 | | | 777 | | Cash flows from investing activities | | | | | | Capital expenditures | (1,349) | | | (1,240) | | | (1,147) | | Changes in Exelon intercompany money pool | — | | | — | | | 68 | | | | | | | | Other investing activities | 8 | | | 9 | | | 7 | | Net cash flows used in investing activities | (1,341) | | | (1,231) | | | (1,072) | | Cash flows from financing activities | | | | | | | | | | | | Change in short-term borrowings | 239 | | | — | | | — | | Issuance of long-term debt | 775 | | | 750 | | | 350 | | Retirement of long-term debt | (350) | | | (300) | | | — | | | | | | | | Changes in Exelon intercompany money pool | — | | | (40) | | | 40 | | | | | | | | Dividends paid on common stock | (399) | | | (339) | | | (340) | | Contributions from parent | 274 | | | 414 | | | 248 | | | | | | | | Other financing activities | (15) | | | (9) | | | (4) | | Net cash flows provided by financing activities | 524 | | | 476 | | | 294 | | Increase (decrease) in cash, restricted cash, and cash equivalents | 24 | | | 18 | | | (1) | | Cash, restricted cash, and cash equivalents at beginning of period | 44 | | | 26 | | | 27 | | Cash, restricted cash, and cash equivalents at end of period | $ | 68 | | | $ | 44 | | | $ | 26 | | | | | | | | Supplemental cash flow information | | | | | | Increase in capital expenditures not paid | $ | 9 | | | $ | 26 | | | $ | 55 | | | | | | | |
| | | | | | | | | | | | | | 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
194130
PECO Energy Company and Subsidiary Companies Consolidated Balance Sheets | | | | | | | | | | | | | December 31, | (In millions) | 2022 | | 2021 | ASSETS | | | | Current assets | | | | Cash and cash equivalents | $ | 59 | | | $ | 36 | | Restricted cash and cash equivalents | 9 | | | 8 | | Accounts receivable | | | | Customer accounts receivable | 635 | | 489 | Customer allowance for credit losses | (105) | | (105) | Customer accounts receivable, net | 530 | | | 384 | | Other accounts receivable | 153 | | 116 | Other allowance for credit losses | (9) | | (7) | Other accounts receivable, net | 144 | | | 109 | | Receivables from affiliates | 4 | | | 1 | | | | | | Inventories, net | | | | Fossil fuel | 99 | | | 51 | | Materials and supplies | 52 | | | 45 | | | | | | | | | | Regulatory assets | 80 | | | 48 | | Other | 38 | | | 29 | | Total current assets | 1,015 | | | 711 | | Property, plant, and equipment (net of accumulated depreciation and amortization of $4,078 and $3,964 as of December 31, 2022 and 2021, respectively) | 12,125 | | | 11,117 | | Deferred debits and other assets | | | | Regulatory assets | 652 | | | 943 | | Receivables from affiliates | — | | | 597 | | Receivable related to Regulatory Agreement Units | 237 | | | — | | Investments | 30 | | | 34 | | Prepaid pension asset | 413 | | | 386 | | Other | 30 | | | 36 | | Total deferred debits and other assets | 1,362 | | | 1,996 | | Total assets | $ | 14,502 | | | $ | 13,824 | |
| | | | | | | | | | 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
195131
PECO Energy Company and Subsidiary Companies Consolidated Balance Sheets | | | | | | | | | | | | | December 31, | (In millions) | 2022 | | 2021 | LIABILITIES AND SHAREHOLDER'S EQUITY | | | | Current liabilities | | | | Short-term borrowings | $ | 239 | | | $ | — | | Long-term debt due within one year | 50 | | | 350 | | Accounts payable | 668 | | | 494 | | Accrued expenses | 142 | | | 136 | | Payables to affiliates | 42 | | | 70 | | | | | | Customer deposits | 63 | | | 48 | | Regulatory liabilities | 75 | | | 94 | | Other | 32 | | | 35 | | Total current liabilities | 1,311 | | | 1,227 | | Long-term debt | 4,562 | | | 3,847 | | Long-term debt to financing trusts | 184 | | | 184 | | Deferred credits and other liabilities | | | | Deferred income taxes and unamortized investment tax credits | 2,213 | | | 2,421 | | Regulatory liabilities | 270 | | | 635 | | Asset retirement obligations | 28 | | | 29 | | Non-pension postretirement benefit obligations | 286 | | | 286 | | Other | 85 | | | 83 | | Total deferred credits and other liabilities | 2,882 | | | 3,454 | | Total liabilities | 8,939 | | | 8,712 | | Commitments and contingencies | | | | | | | | Shareholder's equity | | | | Common stock (No par value, 500 shares authorized, 170 shares outstanding as of December 31, 2022 and 2021) | 3,702 | | | 3,428 | | Retained earnings | 1,861 | | | 1,684 | | | | | | Total shareholder's equity | 5,563 | | | 5,112 | | Total liabilities and shareholder's equity | $ | 14,502 | | | $ | 13,824 | |
| | | | | | | | | | 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
196132
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, 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 | | Net income | — | | | 576 | | | | | 576 | | Common stock dividends | — | | | (399) | | | | | (399) | | | | | | | | | | | | | | | | | | Contributions from parent | 274 | | | — | | | | | 274 | | | | | | | | | | | | | | | | | | Balance, December 31, 2022 | $ | 3,702 | | | $ | 1,861 | | | | | $ | 5,563 | |
See the Combined Notes to Consolidated Financial Statements
197133
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) | 2022 | | 2021 | | 2020 | Operating revenues | | | | | | Electric operating revenues | $ | 2,890 | | | $ | 2,497 | | | $ | 2,323 | | Natural gas operating revenues | 1,037 | | | 801 | | | 739 | | Revenues from alternative revenue programs | (47) | | | 12 | | | 16 | | Operating revenues from affiliates | 15 | | | 31 | | | 20 | | Total operating revenues | 3,895 | | | 3,341 | | | 3,098 | | Operating expenses | | | | | | Purchased power | 1,186 | | | 699 | | | 509 | | Purchased fuel | 363 | | | 243 | | | 171 | | Purchased power and fuel from affiliates | 18 | | | 233 | | | 311 | | Operating and maintenance | 670 | | | 618 | | | 617 | | Operating and maintenance from affiliates | 207 | | | 193 | | | 172 | | Depreciation and amortization | 630 | | | 591 | | | 550 | | Taxes other than income taxes | 302 | | | 283 | | | 268 | | Total operating expenses | 3,376 | | | 2,860 | | | 2,598 | | | | | | | | Operating income | 519 | | | 481 | | | 500 | | Other income and (deductions) | | | | | | Interest expense, net | (152) | | | (138) | | | (133) | | | | | | | | Other, net | 21 | | | 30 | | | 23 | | Total other income and (deductions) | (131) | | | (108) | | | (110) | | Income before income taxes | 388 | | | 373 | | | 390 | | Income taxes | 8 | | | (35) | | | 41 | | Net income | $ | 380 | | | $ | 408 | | | $ | 349 | | | | | | | | | | | | | | | | | | | | Comprehensive income | $ | 380 | | | $ | 408 | | | $ | 349 | | | | | | | | | | | | | |
See the Combined Notes to Consolidated Financial Statements
198134
Baltimore Gas and Electric Company and Subsidiary Companies Consolidated Statements of Cash Flows
| | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | (In millions) | 2022 | | 2021 | | 2020 | Cash flows from operating activities | | | | | | Net income | $ | 380 | | | $ | 408 | | | $ | 349 | | Adjustments to reconcile net income to net cash flows provided by operating activities: | | | | | | Depreciation and amortization | 630 | | | 591 | | | 550 | | Asset impairments | 48 | | | — | | | — | | | | | | | | Deferred income taxes and amortization of investment tax credits | 9 | | | (17) | | | 37 | | Other non-cash operating activities | 135 | | | 75 | | | 97 | | Changes in assets and liabilities: | | | | | | Accounts receivable | (197) | | | 30 | | | (165) | | Receivables from and payables to affiliates, net | (2) | | | (13) | | | (8) | | Inventories | (61) | | | (29) | | | 10 | | Accounts payable and accrued expenses | 77 | | | 14 | | | 102 | | Collateral received, net | 19 | | | 3 | | | — | | Income taxes | (17) | | | 20 | | | 60 | | Regulatory assets and liabilities, net | (160) | | | (152) | | | (118) | | Pension and non-pension postretirement benefit contributions | (68) | | | (81) | | | (78) | | Other assets and liabilities | (33) | | | (120) | | | 48 | | Net cash flows provided by operating activities | 760 | | | 729 | | | 884 | | Cash flows from investing activities | | | | | | Capital expenditures | (1,262) | | | (1,226) | | | (1,247) | | | | | | | | Other investing activities | 11 | | | 18 | | | 2 | | Net cash flows used in investing activities | (1,251) | | | (1,208) | | | (1,245) | | Cash flows from financing activities | | | | | | Changes in short-term borrowings | 278 | | | 130 | | | (76) | | Issuance of long-term debt | 500 | | | 600 | | | 400 | | Retirement of long-term debt | (250) | | | (300) | | | — | | | | | | | | | | | | | | | | | | | | Dividends paid on common stock | (300) | | | (292) | | | (246) | | | | | | | | Contributions from parent | 286 | | | 257 | | | 411 | | Other financing activities | (11) | | | (6) | | | (8) | | Net cash flows provided by financing activities | 503 | | | 389 | | | 481 | | Increase (decrease) in cash, restricted cash, and cash equivalents | 12 | | | (90) | | | 120 | | Cash, restricted cash, and cash equivalents at beginning of period | 55 | | | 145 | | | 25 | | Cash, restricted cash, and cash equivalents at end of period | $ | 67 | | | $ | 55 | | | $ | 145 | | | | | | | | Supplemental cash flow information | | | | | | Increase (decrease) in capital expenditures not paid | $ | 35 | | | $ | (59) | | | $ | 53 | | | | | | | |
| | | | | | | | | | | | | | 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
199135
Baltimore Gas and Electric Company Balance Sheets | | | | | | | | | | | | | December 31, | (In millions) | 2022 | | 2021 | ASSETS | | | | Current assets | | | | Cash and cash equivalents | $ | 43 | | | $ | 51 | | Restricted cash and cash equivalents | 24 | | | 4 | | Accounts receivable | | | | Customer accounts receivable | 617 | | 436 | Customer allowance for credit losses | (54) | | (38) | Customer accounts receivable, net | 563 | | | 398 | | Other accounts receivable | 132 | | 124 | Other allowance for credit losses | (10) | | (9) | Other accounts receivable, net | 122 | | | 115 | | Receivables from affiliates | — | | | 1 | | Inventories, net | | | | Fossil fuel | 91 | | | 42 | | Materials and supplies | 65 | | | 53 | | | | | | Prepaid utility taxes | 52 | | | 49 | | Regulatory assets | 177 | | | 215 | | Other | 13 | | | 8 | | Total current assets | 1,150 | | | 936 | | Property, plant, and equipment (net of accumulated depreciation and amortization of $4,583 and $4,299 as of December 31, 2022 and 2021, respectively) | 11,338 | | | 10,577 | | Deferred debits and other assets | | | | Regulatory assets | 527 | | | 477 | | Investments | 7 | | | 14 | | Prepaid pension asset | 291 | | | 276 | | Other | 37 | | | 44 | | Total deferred debits and other assets | 862 | | | 811 | | Total assets | $ | 13,350 | | | $ | 12,324 | |
| | | | | | | | | | 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
200136
Baltimore Gas and Electric Company Balance Sheets | | | | | | | | | | | | | December 31, | (In millions) | 2022 | | 2021 | LIABILITIES AND SHAREHOLDER'S EQUITY | | | | Current liabilities | | | | Short-term borrowings | $ | 408 | | | $ | 130 | | Long-term debt due within one year | 300 | | | 250 | | Accounts payable | 462 | | | 349 | | Accrued expenses | 159 | | | 176 | | | | | | Payables to affiliates | 39 | | | 48 | | Customer deposits | 105 | | | 97 | | Regulatory liabilities | 47 | | | 26 | | Other | 55 | | | 48 | | Total current liabilities | 1,575 | | | 1,124 | | Long-term debt | 3,907 | | | 3,711 | | Deferred credits and other liabilities | | | | Deferred income taxes and unamortized investment tax credits | 1,832 | | | 1,686 | | Regulatory liabilities | 816 | | | 934 | | Asset retirement obligations | 30 | | | 26 | | Non-pension postretirement benefit obligations | 166 | | | 175 | | Other | 88 | | | 98 | | Total deferred credits and other liabilities | 2,932 | | | 2,919 | | Total liabilities | 8,414 | | | 7,754 | | Commitments and contingencies | | | | Shareholder's equity | | | | Common stock (No par value, 0 shares(a) authorized, 0 shares(a) outstanding as of December 31, 2022 and 2021) | 2,861 | | | 2,575 | | Retained earnings | 2,075 | | | 1,995 | | | | | | Total shareholder's equity | 4,936 | | | 4,570 | | | | | | | | | | Total liabilities and shareholder's equity | $ | 13,350 | | | $ | 12,324 | |
| | | | | | | | | | 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, 2022 and 2021.
_____________
| | (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
201137
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, 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 | | | | | | Net income | — | | | 380 | | | | | 380 | | | | | | Common stock dividends | — | | | (300) | | | | | (300) | | | | | | | | | | | | | | | | | | Contributions from parent | 286 | | | — | | | | | 286 | | | | | | | | | | | | | | | | | | Balance, December 31, 2022 | $ | 2,861 | | | $ | 2,075 | | | | | $ | 4,936 | | | | | |
| | | | | | | | | | | | | (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
202138
Pepco Holdings LLC and Subsidiary Companies Consolidated Statements of Operations and Comprehensive Income | | | | | | | | | | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | | | | (In millions) | 2022 | | 2021 | | 2020 | | | | Operating revenues | | | | | | | | | Electric operating revenues | $ | 5,376 | | | $ | 4,769 | | | $ | 4,463 | | | | | Natural gas operating revenues | 238 | | | 168 | | | 162 | | | | | Revenues from alternative revenue programs | (59) | | | 91 | | | 21 | | | | | Operating revenues from affiliates | 10 | | | 13 | | | 17 | | | | | Total operating revenues | 5,565 | | | 5,041 | | | 4,663 | | | | | Operating expenses | | | | | | | | | Purchased power | 1,984 | | | 1,417 | | | 1,279 | | | | | Purchased fuel | 129 | | | 73 | | | 69 | | | | | Purchased power from affiliates | 51 | | | 367 | | | 366 | | | | | Operating and maintenance | 966 | | | 925 | | | 940 | | | | | Operating and maintenance from affiliates | 191 | | | 179 | | | 159 | | | | | Depreciation and amortization | 938 | | | 821 | | | 782 | | | | | Taxes other than income taxes | 475 | | | 458 | | | 450 | | | | | | | | | | | | | | Total operating expenses | 4,734 | | | 4,240 | | | 4,045 | | | | | | | | | | | | | | Gain on sales of assets | — | | | — | | | 11 | | | | | Operating income | 831 | | | 801 | | | 629 | | | | | Other income and (deductions) | | | | | | | | | Interest expense, net | (292) | | | (267) | | | (268) | | | | | | | | | | | | | | Other, net | 78 | | | 69 | | | 57 | | | | | Total other income and (deductions) | (214) | | | (198) | | | (211) | | | | | Income before income taxes | 617 | | | 603 | | | 418 | | | | | Income taxes | 9 | | | 42 | | | (77) | | | | | | | | | | | | | | Net income | $ | 608 | | | $ | 561 | | | $ | 495 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Comprehensive income | $ | 608 | | | $ | 561 | | | $ | 495 | | | | |
| | | | | | | | | | | | | | 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
203139
Pepco Holdings LLC and Subsidiary Companies Consolidated Statements of Cash Flows | | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | (In millions) | 2022 | | 2021 | | 2020 | Cash flows from operating activities | | | | | | Net income | $ | 608 | | | $ | 561 | | | $ | 495 | | | | | | | | Adjustments to reconcile net income to net cash flows provided by operating activities: | | | | | | Depreciation and amortization | 938 | | | 821 | | | 782 | | | | | | | | | | | | | | Deferred income taxes and amortization of investment tax credits | (9) | | | 24 | | | (97) | | | | | | | | Other non-cash operating activities | 163 | | | (12) | | | 103 | | Changes in assets and liabilities: | | | | | | Accounts receivable | (184) | | | (48) | | | (159) | | Receivables from and payables to affiliates, net | (46) | | | 6 | | | 3 | | Inventories | (34) | | | (16) | | | (6) | | Accounts payable and accrued expenses | 30 | | | 34 | | | 49 | | | | | | | | Collateral received, net | 148 | | | 49 | | | — | | Income taxes | (1) | | | 17 | | | (25) | | Regulatory assets and liabilities, net | (136) | | | (99) | | | (129) | | Pension and non-pension postretirement benefit contributions | (78) | | | (48) | | | (39) | | Other assets and liabilities | (149) | | | (132) | | | 25 | | Net cash flows provided by operating activities | 1,250 | | | 1,157 | | | 1,002 | | Cash flows from investing activities | | | | | | Capital expenditures | (1,709) | | | (1,720) | | | (1,604) | | | | | | | | | | | | | | | | | | | | | | | | | | Other investing activities | 6 | | | 2 | | | 7 | | Net cash flows used in investing activities | (1,703) | | | (1,718) | | | (1,597) | | Cash flows from financing activities | | | | | | Changes in short-term borrowings | (54) | | | 100 | | | 160 | | | | | | | | | | | | | | Issuance of long-term debt | 925 | | | 825 | | | 602 | | Retirement of long-term debt | (310) | | | (260) | | | (128) | | Change in Exelon intercompany money pool | 37 | | | (14) | | | 9 | | | | | | | | | | | | | | | | | | | | Distributions to member | (750) | | | (703) | | | (553) | | Contributions from member | 787 | | | 683 | | | 494 | | | | | | | | | | | | | | | | | | | | Other financing activities | (22) | | | (17) | | | (10) | | Net cash flows provided by financing activities | 613 | | | 614 | | | 574 | | Increase (decrease) in cash, restricted cash, and cash equivalents | 160 | | | 53 | | | (21) | | Cash, restricted cash, and cash equivalents at beginning of period | 213 | | | 160 | | | 181 | | Cash, restricted cash, and cash equivalents at end of period | $ | 373 | | | $ | 213 | | | $ | 160 | | | | | | | | Supplemental cash flow information | | | | | | Increase (decrease) in capital expenditures not paid | $ | 136 | | | $ | (6) | | | $ | 54 | | | | | | | |
| | | | | | | | | | | | | | 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
204140
Pepco Holdings LLC and Subsidiary Companies Consolidated Balance Sheets | | | | | | | | | | | | | December 31, | (In millions) | 2022 | | 2021 | ASSETS | | | | Current assets | | | | Cash and cash equivalents | $ | 198 | | | $ | 136 | | Restricted cash and cash equivalents | 175 | | | 77 | | Accounts receivable | | | | Customer accounts receivable | 734 | | 616 | Customer allowance for credit losses | (109) | | (104) | Customer accounts receivable, net | 625 | | | 512 | | Other accounts receivable | 300 | | 283 | Other allowance for credit losses | (46) | | (39) | Other accounts receivable, net | 254 | | | 244 | | | | | | Receivable from affiliates | 2 | | | 2 | | | | | | | | | | Inventories, net | | | | Fossil fuel | 18 | | | 11 | | Materials and supplies | 236 | | | 209 | | | | | | | | | | Regulatory assets | 455 | | | 432 | | | | | | Other | 96 | | | 69 | | Total current assets | 2,059 | | | 1,692 | | Property, plant, and equipment (net of accumulated depreciation and amortization of $2,618 and $2,108 as of December 31, 2022 and 2021, respectively) | 17,686 | | | 16,498 | | Deferred debits and other assets | | | | Regulatory assets | 1,610 | | | 1,794 | | Goodwill | 4,005 | | | 4,005 | | Investments | 138 | | | 145 | | | | | | | | | | Prepaid pension asset | 353 | | | 344 | | | | | | | | | | Other | 231 | | | 266 | | Total deferred debits and other assets | 6,337 | | | 6,554 | | Total assets | $ | 26,082 | | | $ | 24,744 | |
| | | | | | | | | | 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
205141
Pepco Holdings LLC and Subsidiary Companies Consolidated Balance Sheets | | | | | | | | | | | | | December 31, | (In millions) | 2022 | | 2021 | LIABILITIES AND EQUITY | | | | Current liabilities | | | | Short-term borrowings | $ | 414 | | | $ | 468 | | Long-term debt due within one year | 591 | | | 399 | | Accounts payable | 771 | | | 578 | | Accrued expenses | 260 | | | 281 | | Payables to affiliates | 66 | | | 104 | | Borrowings from Exelon intercompany money pool | 44 | | | 7 | | Customer deposits | 88 | | | 81 | | Regulatory liabilities | 76 | | | 68 | | | | | | Unamortized energy contract liabilities | 10 | | | 89 | | | | | | PPA Termination Obligation | 87 | | | — | | Other | 330 | | | 171 | | Total current liabilities | 2,737 | | | 2,246 | | Long-term debt | 7,529 | | | 7,148 | | Deferred credits and other liabilities | | | | Deferred income taxes and unamortized investment tax credits | 2,895 | | | 2,675 | | Regulatory liabilities | 1,011 | | | 1,238 | | Asset retirement obligations | 59 | | | 70 | | Non-pension postretirement benefit obligations | 50 | | | 66 | | | | | | | | | | | | | | | | | | Unamortized energy contract liabilities | 35 | | | 146 | | Other | 536 | | | 570 | | Total deferred credits and other liabilities | 4,586 | | | 4,765 | | Total liabilities | 14,852 | | | 14,159 | | Commitments and contingencies | | | | | | | | Member's equity | | | | Membership interest | 11,582 | | | 10,795 | | | | | | Undistributed losses | (352) | | | (210) | | | | | | Total member's equity | 11,230 | | | 10,585 | | Total liabilities and member's equity | $ | 26,082 | | | $ | 24,744 | |
| | | | | | | | | | December 31, | (In millions) | 2019 | | 2018 | LIABILITIES AND EQUITY | | | | Current liabilities | | | | Short-term borrowings | $ | 208 |
| | $ | 179 |
| Long-term debt due within one year | 103 |
| | 125 |
| Accounts payable | 462 |
| | 496 |
| Accrued expenses | 296 |
| | 256 |
| Payables to affiliates | 98 |
| | 94 |
| Borrowings from Exelon intercompany money pool | 12 |
| | — |
| Customer deposits | 117 |
| | 116 |
| Regulatory liabilities | 70 |
| | 84 |
| Unamortized energy contract liabilities | 115 |
| | 119 |
| Other | 131 |
| | 123 |
| Total current liabilities | 1,612 |
| | 1,592 |
| Long-term debt | 6,460 |
| | 6,134 |
| Deferred credits and other liabilities | | | | Deferred income taxes and unamortized investment tax credits | 2,278 |
| | 2,137 |
| Asset retirement obligations | 57 |
| | 52 |
| Non-pension postretirement benefit obligations | 93 |
| | 103 |
| Regulatory liabilities | 1,707 |
| | 1,864 |
| Unamortized energy contract liabilities | 327 |
| | 442 |
| Other | 577 |
| | 369 |
| Total deferred credits and other liabilities | 5,039 |
| | 4,967 |
| Total liabilities(a) | 13,111 |
| | 12,693 |
| Commitments and contingencies |
| |
| Member's equity | | | | Membership interest | 9,618 |
| | 9,220 |
| Undistributed (losses) gains | (10 | ) | | 39 |
| Total member's equity | 9,608 |
| | 9,259 |
| Total liabilities and member's equity | $ | 22,719 |
| | $ | 21,952 |
|
_____________
| | (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. |
See the Combined Notes to Consolidated Financial Statements
206142
Pepco Holdings LLC and Subsidiary Companies Consolidated Statements of Changes in Equity | | | | | | | | | | | | | | | | | | | | (In millions) | Membership Interest | | Undistributed (Losses)/Gains | | | | Total Member's Equity | 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 | | Net income | — | | | 608 | | | | | 608 | | Distribution to member | — | | | (750) | | | | | (750) | | Contributions from member | 787 | | | — | | | | | 787 | | Balance, December 31, 2022 | $ | 11,582 | | | $ | (352) | | | | | $ | 11,230 | |
| | | | | | | | | | | | | (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
207143
Potomac Electric Power Company Statements of Operations and Comprehensive Income | | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | (In millions) | 2022 | | 2021 | | 2020 | Operating revenues | | | | | | Electric operating revenues | $ | 2,557 | | | $ | 2,216 | | | $ | 2,102 | | Revenues from alternative revenue programs | (31) | | | 53 | | | 40 | | Operating revenues from affiliates | 5 | | | 5 | | | 7 | | Total operating revenues | 2,531 | | | 2,274 | | | 2,149 | | Operating expenses | | | | | | Purchased power | 795 | | | 353 | | | 324 | | Purchased power from affiliate | 39 | | | 271 | | | 278 | | Operating and maintenance | 284 | | | 258 | | | 248 | | Operating and maintenance from affiliates | 223 | | | 213 | | | 205 | | Depreciation and amortization | 417 | | | 403 | | | 377 | | Taxes other than income taxes | 382 | | | 373 | | | 367 | | Total operating expenses | 2,140 | | | 1,871 | | | 1,799 | | | | | | | | Gain on sales of assets | — | | | — | | | 9 | | | | | | | | Operating income | 391 | | | 403 | | | 359 | | Other income and (deductions) | | | | | | Interest expense, net | (150) | | | (140) | | | (138) | | | | | | | | Other, net | 55 | | | 48 | | | 38 | | Total other income and (deductions) | (95) | | | (92) | | | (100) | | Income before income taxes | 296 | | | 311 | | | 259 | | Income taxes | (9) | | | 15 | | | (7) | | | | | | | | Net income | $ | 305 | | | $ | 296 | | | $ | 266 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Comprehensive income | $ | 305 | | | $ | 296 | | | $ | 266 | |
| | | | | | | | | | | | | | 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
208144
Potomac Electric Power Company Statements of Cash Flows | | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | (In millions) | 2022 | | 2021 | | 2020 | Cash flows from operating activities | | | | | | Net income | $ | 305 | | | $ | 296 | | | $ | 266 | | Adjustments to reconcile net income to net cash flows provided by operating activities: | | | | | | Depreciation and amortization | 417 | | | 403 | | | 377 | | | | | | | | | | | | | | Deferred income taxes and amortization of investment tax credits | (17) | | | (8) | | | (46) | | Other non-cash operating activities | 36 | | | (52) | | | (23) | | Changes in assets and liabilities: | | | | | | Accounts receivable | (104) | | | (28) | | | (67) | | Receivables from and payables to affiliates, net | (33) | | | 6 | | | (12) | | Inventories | (16) | | | (8) | | | 1 | | Accounts payable and accrued expenses | 24 | | | 16 | | | 41 | | Collateral received, net | 24 | | | 2 | | | — | | Income taxes | (19) | | | 11 | | | (1) | | Regulatory assets and liabilities, net | (69) | | | (81) | | | (55) | | Pension and non-pension postretirement benefit contributions | (11) | | | (11) | | | (11) | | Other assets and liabilities | (66) | | | (84) | | | 31 | | Net cash flows provided by operating activities | 471 | | | 462 | | | 501 | | Cash flows from investing activities | | | | | | Capital expenditures | (874) | | | (843) | | | (773) | | | | | | | | | | | | | | | | | | | | Other investing activities | 3 | | | (1) | | | — | | Net cash flows used in investing activities | (871) | | | (844) | | | (773) | | Cash flows from financing activities | | | | | | Changes in short-term borrowings | 124 | | | 140 | | | (47) | | Issuance of long-term debt | 625 | | | 275 | | | 300 | | Retirement of long-term debt | (310) | | | — | | | (3) | | Dividends paid on common stock | (463) | | | (268) | | | (232) | | Contributions from parent | 465 | | | 244 | | | 262 | | Other financing activities | (10) | | | (6) | | | (6) | | Net cash flows provided by financing activities | 431 | | | 385 | | | 274 | | Increase in cash, restricted cash, and cash equivalents | 31 | | | 3 | | | 2 | | Cash, restricted cash, and cash equivalents at beginning of period | 68 | | | 65 | | | 63 | | Cash, restricted cash, and cash equivalents at end of period | $ | 99 | | | $ | 68 | | | $ | 65 | | | | | | | | Supplemental cash flow information | | | | | | Increase in capital expenditures not paid | $ | 65 | | | $ | 30 | | | $ | 1 | | | | | | | |
| | | | | | | | | | | | | | 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
209145
Potomac Electric Power Company Balance Sheets | | | | | | | | | | | | | December 31, | (In millions) | 2022 | | 2021 | ASSETS | | | | Current assets | | | | Cash and cash equivalents | $ | 45 | | | $ | 34 | | Restricted cash and cash equivalents | 54 | | | 34 | | Accounts receivable | | | | Customer accounts receivable | 351 | | 277 | Customer allowance for credit losses | (47) | | (37) | Customer accounts receivable, net | 304 | | | 240 | | Other accounts receivable | 180 | | 160 | Other allowance for credit losses | (25) | | (16) | Other accounts receivable, net | 155 | | | 144 | | | | | | | | | | | | | | | | | | Inventories, net | 135 | | | 119 | | Regulatory assets | 235 | | | 213 | | | | | | Other | 53 | | | 25 | | Total current assets | 981 | | | 809 | | Property, plant, and equipment (net of accumulated depreciation and amortization of $4,067 and $3,875 as of December 31, 2022 and 2021, respectively) | 8,794 | | | 8,104 | | Deferred debits and other assets | | | | Regulatory assets | 437 | | | 532 | | Investments | 119 | | | 120 | | | | | | Prepaid pension asset | 273 | | | 279 | | Other | 53 | | | 59 | | Total deferred debits and other assets | 882 | | | 990 | | Total assets | $ | 10,657 | | | $ | 9,903 | |
| | | | | | | | | | 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
210146
Potomac Electric Power Company Balance Sheets | | | December 31, | | December 31, | (In millions) | 2019 | | 2018 | (In millions) | 2022 | | 2021 | LIABILITIES AND SHAREHOLDER'S EQUITY | | | | LIABILITIES AND SHAREHOLDER'S EQUITY | | | | Current liabilities | | | | Current liabilities | | Short-term borrowings | $ | 82 |
| | $ | 40 |
| Short-term borrowings | $ | 299 | | | $ | 175 | | Long-term debt due within one year | 2 |
| | 15 |
| Long-term debt due within one year | 4 | | | 313 | | Accounts payable | 195 |
| | 214 |
| Accounts payable | 382 | | | 272 | | Accrued expenses | 156 |
| | 126 |
| Accrued expenses | 125 | | | 160 | | Payables to affiliates | 66 |
| | 62 |
| Payables to affiliates | 34 | | | 59 | | | Customer deposits | 57 |
| | 54 |
| Customer deposits | 39 | | | 35 | | Regulatory liabilities | 8 |
| | 7 |
| Regulatory liabilities | 6 | | | 14 | | | Merger related obligation | 39 |
| | 38 |
| Merger related obligation | 26 | | | 27 | | Current portion of DC PLUG obligation | 30 |
| | 30 |
| | | Other | 22 |
| | 42 |
| Other | 93 | | | 55 | | Total current liabilities | 657 |
| | 628 |
| Total current liabilities | 1,008 | | | 1,110 | | Long-term debt | 2,862 |
| | 2,704 |
| Long-term debt | 3,747 | | | 3,132 | | | 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 | 1,382 | | | 1,275 | | Regulatory liabilities | | Regulatory liabilities | 455 | | | 549 | | Asset retirement obligations | 41 |
| | 37 |
| Asset retirement obligations | 39 | | | 45 | | | Non-pension postretirement benefit obligations | 20 |
| | 29 |
| Non-pension postretirement benefit obligations | — | | | 3 | | Regulatory liabilities | 746 |
| | 822 |
| | | Other | 297 |
| | 275 |
| Other | 244 | | | 314 | | Total deferred credits and other liabilities | 2,235 |
| | 2,218 |
| Total deferred credits and other liabilities | 2,120 | | | 2,186 | | Total liabilities | 5,754 |
| | 5,550 |
| Total liabilities | 6,875 | | | 6,428 | | Commitments and contingencies |
| |
| Commitments and contingencies | | | | 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, 2022 and 2021) | | Common stock ($0.01 par value, 200 shares authorized, 0 shares(a) outstanding as of December 31, 2022 and 2021) | 2,767 | | | 2,302 | | | Retained earnings | 1,111 |
| | 1,081 |
| Retained earnings | 1,015 | | | 1,173 | | | Total shareholder's equity | 2,907 |
| | 2,717 |
| Total shareholder's equity | 3,782 | | | 3,475 | | Total liabilities and shareholder's equity | $ | 8,661 |
|
| $ | 8,267 |
| Total liabilities and shareholder's equity | $ | 10,657 | | | $ | 9,903 | |
_____________ | | (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, 2022 and 2021.
See the Combined Notes to Consolidated Financial Statements
211147
Potomac Electric Power Company Statements of Changes in Shareholder's Equity | | | | | | | | | | | | | | | | | | (In millions) | Common Stock | | Retained Earnings | | Total Shareholder's Equity | 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 | | Net income | — | | | 305 | | | 305 | | Common stock dividends | — | | | (463) | | | (463) | | Contributions from parent | 465 | | | — | | | 465 | | Balance, December 31, 2022 | $ | 2,767 | | | $ | 1,015 | | | $ | 3,782 | |
| | | | | | | | | | | | | (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
212148
Delmarva Power & Light Company Statements of Operations and Comprehensive Income | | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | (In millions) | 2022 | | 2021 | | 2020 | Operating revenues | | | | | | Electric operating revenues | $ | 1,360 | | | $ | 1,191 | | | $ | 1,107 | | Natural gas operating revenues | 238 | | | 168 | | | 162 | | Revenues from alternative revenue programs | (9) | | | 14 | | | (7) | | Operating revenues from affiliates | 6 | | | 7 | | | 9 | | Total operating revenues | 1,595 | | | 1,380 | | | 1,271 | | Operating expenses | | | | | | Purchased power | 567 | | | 387 | | | 359 | | Purchased fuel | 129 | | | 73 | | | 69 | | Purchased power from affiliates | 10 | | | 79 | | | 75 | | Operating and maintenance | 183 | | | 183 | | | 208 | | Operating and maintenance from affiliates | 166 | | | 162 | | | 153 | | Depreciation and amortization | 232 | | | 210 | | | 191 | | Taxes other than income taxes | 72 | | | 67 | | | 65 | | Total operating expenses | 1,359 | | | 1,161 | | | 1,120 | | | | | | | | Operating income | 236 | | | 219 | | | 151 | | Other income and (deductions) | | | | | | Interest expense, net | (66) | | | (61) | | | (61) | | Other, net | 13 | | | 12 | | | 10 | | Total other income and (deductions) | (53) | | | (49) | | | (51) | | Income before income taxes | 183 | | | 170 | | | 100 | | Income taxes | 14 | | | 42 | | | (25) | | Net income | $ | 169 | | | $ | 128 | | | $ | 125 | | Comprehensive income | $ | 169 | | | $ | 128 | | | $ | 125 | |
| | | | | | | | | | | | | | 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
213149
Delmarva Power & Light Company Statements of Cash Flows | | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | (In millions) | 2022 | | 2021 | | 2020 | Cash flows from operating activities | | | | | | Net income | $ | 169 | | | $ | 128 | | | $ | 125 | | Adjustments to reconcile net income to net cash flows provided by operating activities: | | | | | | Depreciation and amortization | 232 | | | 210 | | | 191 | | | | | | | | | | | | | | Deferred income taxes and amortization of investment tax credits | 16 | | | 39 | | | (13) | | Other non-cash operating activities | 29 | | | 3 | | | 51 | | Changes in assets and liabilities: | | | | | | Accounts receivable | (59) | | | 15 | | | (34) | | Receivables from and payables to affiliates, net | (10) | | | (3) | | | 8 | | Inventories | (11) | | | (8) | | | (5) | | Accounts payable and accrued expenses | 19 | | | 16 | | | 4 | | Collateral received, net | 78 | | | 43 | | | — | | Income taxes | — | | | 13 | | | (25) | | Regulatory assets and liabilities, net | (34) | | | (43) | | | (35) | | Pension and non-pension postretirement benefit contributions | (1) | | | (1) | | | — | | Other assets and liabilities | (10) | | | (27) | | | 5 | | Net cash flows provided by operating activities | 418 | | | 385 | | | 272 | | Cash flows from investing activities | | | | | | Capital expenditures | (430) | | | (429) | | | (424) | | | | | | | | | | | | | | Other investing activities | 3 | | | 4 | | | (3) | | Net cash flows used in investing activities | (427) | | | (425) | | | (427) | | Cash flows from financing activities | | | | | | Changes in short-term borrowings | (34) | | | 3 | | | 90 | | Issuance of long-term debt | 125 | | | 125 | | | 178 | | Retirement of long-term debt | — | | | — | | | (80) | | Dividends paid on common stock | (143) | | | (147) | | | (141) | | Contributions from parent | 147 | | | 120 | | | 112 | | Other financing activities | (5) | | | (5) | | | (2) | | Net cash flows provided by financing activities | 90 | | | 96 | | | 157 | | Increase in cash, restricted cash, and cash equivalents | 81 | | | 56 | | | 2 | | Cash, restricted cash, and cash equivalents at beginning of period | 71 | | | 15 | | | 13 | | Cash, restricted cash, and cash equivalents at end of period | $ | 152 | | | $ | 71 | | | $ | 15 | | | | | | | | Supplemental cash flow information | | | | | | Increase (decrease) in capital expenditures not paid | $ | 23 | | | $ | (18) | | | $ | 20 | | | | | | | |
| | | | | | | | | | | | | | 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
214150
Delmarva Power & Light Company Balance Sheets | | | | | | | | | | | | | December 31, | (In millions) | 2022 | | 2021 | ASSETS | | | | Current assets | | | | Cash and cash equivalents | $ | 31 | | | $ | 28 | | Restricted cash and cash equivalents | 121 | | | 43 | | Accounts receivable | | | | Customer accounts receivable | 204 | | 149 | Customer allowance for credit losses | (21) | | (18) | Customer accounts receivable, net | 183 | | | 131 | | Other accounts receivable | 52 | | 58 | Other allowance for credit losses | (7) | | (8) | Other accounts receivable, net | 45 | | | 50 | | Receivables from affiliates | — | | | 1 | | Inventories, net | | | | Fossil fuel | 18 | | | 11 | | Materials and supplies | 58 | | | 54 | | Prepaid utility taxes | 23 | | | 20 | | Regulatory assets | 80 | | | 68 | | | | | | | | | | Other | 14 | | | 16 | | Total current assets | 573 | | | 422 | | Property, plant, and equipment, (net of accumulated depreciation and amortization of $1,772 and $1,635 as of December 31, 2022 and 2021, respectively) | 4,820 | | | 4,560 | | Deferred debits and other assets | | | | Regulatory assets | 202 | | | 212 | | | | | | | | | | Prepaid pension asset | 153 | | | 157 | | Other | 54 | | | 61 | | Total deferred debits and other assets | 409 | | | 430 | | Total assets | $ | 5,802 | | | $ | 5,412 | | | | | |
| | | | | | | | | | 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
215151
Delmarva Power & Light Company Balance Sheets | | | December 31, | | December 31, | (In millions) | 2019 | | 2018 | (In millions) | 2022 | | 2021 | | LIABILITIES AND SHAREHOLDER'S EQUITY | | | | LIABILITIES AND SHAREHOLDER'S EQUITY | | | | Current liabilities | | | | Current liabilities | | Short-term borrowings | $ | 56 |
| | $ | — |
| Short-term borrowings | $ | 115 | | | $ | 149 | | Long-term debt due within one year | 80 |
| | 91 |
| Long-term debt due within one year | 584 | | | 83 | | Accounts payable | 112 |
| | 111 |
| Accounts payable | 172 | | | 131 | | Accrued expenses | 46 |
| | 39 |
| Accrued expenses | 41 | | | 40 | | Payables to affiliates | 32 |
| | 33 |
| Payables to affiliates | 22 | | | 33 | | Customer deposits | 36 |
| | 35 |
| Customer deposits | 29 | | | 28 | | Regulatory liabilities | 37 |
| | 59 |
| Regulatory liabilities | 44 | | | 25 | | | Other | 15 |
| | 7 |
| Other | 136 | | | 59 | | Total current liabilities | 414 |
|
| 375 |
| Total current liabilities | 1,143 | | | 548 | | Long-term debt | 1,487 |
| | 1,403 |
| Long-term debt | 1,354 | | | 1,727 | | 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 | 869 | | | 803 | | Regulatory liabilities | | Regulatory liabilities | 380 | | | 441 | | Asset retirement obligations | | Asset retirement obligations | 13 | | | 16 | | Non-pension postretirement benefit obligations | 16 |
| | 17 |
| Non-pension postretirement benefit obligations | 9 | | | 11 | | Regulatory liabilities | 574 |
| | 606 |
| | Other | 104 |
| | 50 |
| Other | 84 | | | 89 | | Total deferred credits and other liabilities | 1,349 |
|
| 1,301 |
| Total deferred credits and other liabilities | 1,355 | | | 1,360 | | Total liabilities | 3,250 |
|
| 3,079 |
| Total liabilities | 3,852 | | | 3,635 | | Commitments and contingencies | | |
|
| Commitments and contingencies | | | | 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, 2022 and 2021, respectively) | | Common stock ($2.25 par value, 0 shares(a) authorized, 0 shares(a) outstanding as of December 31, 2022 and 2021, respectively) | 1,356 | | | 1,209 | | Retained earnings | 603 |
| | 595 |
| Retained earnings | 594 | | | 568 | | Total shareholder's equity | 1,580 |
|
| 1,509 |
| Total shareholder's equity | 1,950 | | | 1,777 | | Total liabilities and shareholder's equity | $ | 4,830 |
|
| $ | 4,588 |
| Total liabilities and shareholder's equity | $ | 5,802 | | | $ | 5,412 | | |
_____________ | | (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, 2022 and 2021.
See the Combined Notes to Consolidated Financial Statements
216152
Delmarva Power & Light Company Statements of Changes in Shareholder's Equity | | | | | | | | | | | | | | | | | | (In millions) | Common Stock | | Retained Earnings | | Total Shareholder's Equity | 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 | | Net income | — | | | 169 | | | 169 | | Common stock dividends | — | | | (143) | | | (143) | | Contributions from parent | 147 | | | — | | | 147 | | Balance, December 31, 2022 | $ | 1,356 | | | $ | 594 | | | $ | 1,950 | |
| | | | | | | | | | | | | (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
217153
Atlantic City Electric Company and Subsidiary Company Consolidated Statements of Operations and Comprehensive Income | | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | (In millions) | 2022 | | 2021 | | 2020 | Operating revenues | | | | | | Electric operating revenues | $ | 1,448 | | | $ | 1,362 | | | $ | 1,253 | | Revenues from alternative revenue programs | (19) | | | 24 | | | (12) | | Operating revenues from affiliates | 2 | | | 2 | | | 4 | | Total operating revenues | 1,431 | | | 1,388 | | | 1,245 | | Operating expenses | | | | | | Purchased power | 622 | | | 677 | | | 596 | | Purchased power from affiliate | 2 | | | 17 | | | 13 | | Operating and maintenance | 189 | | | 179 | | | 192 | | Operating and maintenance from affiliates | 142 | | | 141 | | | 134 | | Depreciation and amortization | 261 | | | 179 | | | 180 | | Taxes other than income taxes | 9 | | | 8 | | | 8 | | Total operating expenses | 1,225 | | | 1,201 | | | 1,123 | | Gain on sales of assets | — | | | — | | | 2 | | | | | | | | | | | | | | Operating income | 206 | | | 187 | | | 124 | | Other income and (deductions) | | | | | | Interest expense, net | (66) | | | (58) | | | (59) | | Other, net | 11 | | | 4 | | | 6 | | Total other income and (deductions) | (55) | | | (54) | | | (53) | | Income before income taxes | 151 | | | 133 | | | 71 | | Income taxes | 3 | | | (13) | | | (41) | | | | | | | | Net income | $ | 148 | | | $ | 146 | | | $ | 112 | | Comprehensive income | $ | 148 | | | $ | 146 | | | $ | 112 | |
| | | | | | | | | | | | | | 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
218154
Atlantic City Electric Company and Subsidiary Company Consolidated Statements of Cash Flows | | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | (In millions) | 2022 | | 2021 | | 2020 | Cash flows from operating activities | | | | | | Net income | $ | 148 | | | $ | 146 | | | $ | 112 | | Adjustments to reconcile net income to net cash flows provided by operating activities: | | | | | | Depreciation and amortization | 261 | | | 179 | | | 180 | | | | | | | | Deferred income taxes and amortization of investment tax credits | (2) | | | (15) | | | (37) | | Other non-cash operating activities | 46 | | | — | | | 36 | | Changes in assets and liabilities: | | | | | | Accounts receivable | (19) | | | (37) | | | (55) | | Receivables from and payables to affiliates, net | (4) | | | 4 | | | 6 | | Inventories | (7) | | | 1 | | | (3) | | Accounts payable and accrued expenses | (9) | | | 3 | | | 5 | | Collateral received, net | 46 | | | 4 | | | — | | Income taxes | 11 | | | — | | | (1) | | Regulatory assets and liabilities, net | (19) | | | 24 | | | (42) | | Pension and non-pension postretirement benefit contributions | (7) | | | (3) | | | (2) | | Other assets and liabilities | (61) | | | (11) | | | — | | Net cash flows provided by operating activities | 384 | | | 295 | | | 199 | | Cash flows from investing activities | | | | | | Capital expenditures | (398) | | | (445) | | | (401) | | | | | | | | | | | | | | Other investing activities | 1 | | | 1 | | | 6 | | Net cash flows used in investing activities | (397) | | | (444) | | | (395) | | Cash flows from financing activities | | | | | | Changes in short-term borrowings | (144) | | | (43) | | | 117 | | | | | | | | | | | | | | Issuance of long-term debt | 175 | | | 425 | | | 123 | | Retirement of long-term debt | — | | | (260) | | | (44) | | | | | | | | Dividends paid on common stock | (145) | | | (288) | | | (114) | | Contributions from parent | 175 | | | 319 | | | 117 | | Other financing activities | (5) | | | (5) | | | (1) | | Net cash flows provided by financing activities | 56 | | | 148 | | | 198 | | Increase (decrease) in cash, restricted cash, and cash equivalents | 43 | | | (1) | | | 2 | | Cash, restricted cash, and cash equivalents at beginning of period | 29 | | | 30 | | | 28 | | Cash, restricted cash, and cash equivalents at end of period | $ | 72 | | | $ | 29 | | | $ | 30 | | | | | | | | Supplemental cash flow information | | | | | | Increase (decrease) in capital expenditures not paid | $ | 48 | | | $ | (18) | | | $ | 33 | | | | | | | |
| | | | | | | | | | | | | | 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
219155
Atlantic City Electric Company and Subsidiary Company Consolidated Balance Sheets | | | | | | | | | | | | | December 31, | (In millions) | 2022 | | 2021 | ASSETS | | | | Current assets | | | | Cash and cash equivalents | $ | 72 | | | $ | 29 | | | | | | Accounts receivable | | | | Customer accounts receivable | 179 | | 190 | Customer allowance for credit losses | (41) | | (49) | Customer accounts receivable, net | 138 | | | 141 | | Other accounts receivable | 70 | | 76 | Other allowance for credit losses | (14) | | (15) | Other accounts receivable, net | 56 | | | 61 | | | | | | Receivables from affiliates | 1 | | | 2 | | | | | | Inventories, net | 43 | | | 36 | | | | | | | | | | | | | | Regulatory assets | 130 | | | 61 | | Other | 3 | | | 3 | | Total current assets | 443 | | | 333 | | Property, plant, and equipment, (net of accumulated depreciation and amortization of $1,551 and $1,420 as of December 31, 2022 and 2021, respectively) | 3,990 | | | 3,729 | | Deferred debits and other assets | | | | Regulatory assets | 494 | | | 430 | | | | | | | | | | | | | | Prepaid pension asset | 18 | | | 27 | | | | | | Other | 34 | | | 37 | | Total deferred debits and other assets | 546 | | | 494 | | Total assets | $ | 4,979 | | | $ | 4,556 | |
| | | | | | | | | | 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
220156
Atlantic City Electric Company and Subsidiary Company Consolidated Balance Sheets | | | | | | | | | | | | | December 31, | (In millions) | 2022 | | 2021 | LIABILITIES AND SHAREHOLDER'S EQUITY | | | | Current liabilities | | | | Short-term borrowings | $ | — | | | $ | 144 | | Long-term debt due within one year | 3 | | | 3 | | Accounts payable | 206 | | | 165 | | Accrued expenses | 47 | | | 44 | | Payables to affiliates | 26 | | | 31 | | | | | | | | | | | | | | Customer deposits | 21 | | | 18 | | Regulatory liabilities | 26 | | | 28 | | PPA termination obligation | 87 | | | — | | Other | 58 | | | 12 | | Total current liabilities | 474 | | | 445 | | Long-term debt | 1,754 | | | 1,579 | | Deferred credits and other liabilities | | | | Deferred income taxes and unamortized investment tax credits | 734 | | | 682 | | Regulatory liabilities | 156 | | | 214 | | | | | | | | | | Non-pension postretirement benefit obligations | 8 | | | 12 | | | | | | | | | | | | | | Other | 100 | | | 49 | | Total deferred credits and other liabilities | 998 | | | 957 | | Total liabilities | 3,226 | | | 2,981 | | Commitments and contingencies | | | | Shareholder's equity | | | | Common stock ($3.00 par value, 25 shares authorized, 9 shares outstanding as of December 31, 2022 and 2021) | 1,765 | | | 1,590 | | Retained deficit | (12) | | | (15) | | | | | | Total shareholder's equity | 1,753 | | | 1,575 | | Total liabilities and shareholder's equity | $ | 4,979 | | | $ | 4,556 | |
| | | | | | | | | | December 31, | (In millions) | 2019 | | 2018 | LIABILITIES AND SHAREHOLDER'S EQUITY | | | | Current liabilities | | | | Short-term borrowings | $ | 70 |
| | $ | 139 |
| Long-term debt due within one year | 20 |
| | 18 |
| Accounts payable | 144 |
| | 154 |
| Accrued expenses | 42 |
| | 35 |
| Payables to affiliates | 25 |
| | 28 |
| Customer deposits | 25 |
| | 26 |
| Regulatory liabilities | 25 |
| | 18 |
| Other | 9 |
| | 4 |
| Total current liabilities | 360 |
|
| 422 |
| Long-term debt | 1,307 |
| | 1,170 |
| Deferred credits and other liabilities | | | | Deferred income taxes and unamortized investment tax credits | 577 |
| | 535 |
| Non-pension postretirement benefit obligations | 17 |
| | 17 |
| Regulatory liabilities | 357 |
| | 402 |
| Other | 39 |
| | 27 |
| Total deferred credits and other liabilities | 990 |
|
| 981 |
| Total liabilities(a) | 2,657 |
|
| 2,573 |
| Commitments and contingencies |
| |
| 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 |
| Total shareholder's equity | 1,276 |
|
| 1,126 |
| Total liabilities and shareholder's equity | $ | 3,933 |
|
| $ | 3,699 |
|
_____________
| | (a) | 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
221157
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, 2019 | $ | 1,154 | | | $ | 129 | | | $ | 1,283 | | Net income | — | | | 112 | | | 112 | | Common stock dividends | — | | | (114) | | | (114) | | Contributions from parent | 117 | | | — | | | 117 | | Balance, December 31, 2020 | $ | 1,271 | | | $ | 127 | | | $ | 1,398 | | Net income | — | | | 146 | | | 146 | | Common stock dividends | — | | | (288) | | | (288) | | Contributions from parent | 319 | | | — | | | 319 | | Balance, December 31, 2021 | $ | 1,590 | | | $ | (15) | | | $ | 1,575 | | Net income | — | | | 148 | | | 148 | | | | | | | | | | | | | | Common stock dividends | — | | | (145) | | | (145) | | Contributions from parent | 175 | | | — | | | 175 | | Balance, December 31, 2022 | $ | 1,765 | | | $ | (12) | | | $ | 1,753 | |
| | | | | | | | | | | | | (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
222158
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted) Note 1 — Significant Accounting Policies 1. Significant Accounting Policies (All Registrants) Description of Business (All Registrants) Exelon is a utility services holding company engaged in the generation, delivery and marketing of energy through Generation and the energy distribution and transmission businesses through ComEd, PECO, BGE, Pepco, DPL, and ACE. On February 21, 2021, Exelon’s Board of Directors approved a plan to separate the Utility Registrants and Generation. The separation was completed on February 1, 2022, creating two publicly traded companies, Exelon and Constellation. See Note 2 — Discontinued Operations for additional information. | | | | | | | | | | | | | | | Name of Registrant | | Business | | Service Territories | Exelon Generation Company, LLC | | Generation, physical delivery and marketing of power across multiple geographical regions through its customer-facing business, Constellation, which sells electricity to both wholesale and retail customers. Generation also sells natural gas, renewable energy and other energy-related products and services. | | Five reportable segments: Mid-Atlantic, Midwest, New York, ERCOT and Other Power Regions | | | | | | Commonwealth Edison Company | | Purchase and regulated retail sale of electricity | | Northern Illinois, including the City of Chicago | | | Transmission and distribution of electricity to retail customers | | | PECO Energy Company | | Purchase and regulated retail sale of electricity and natural gas | | Southeastern Pennsylvania, including the City of Philadelphia (electricity) | | | Transmission and distribution of electricity and distribution of natural gas to retail customers | | Pennsylvania counties surrounding the City of Philadelphia (natural gas) | Baltimore Gas and Electric Company | | Purchase and regulated retail sale of electricity and natural gas | | Central Maryland, including the City of Baltimore (electricity and natural gas) | | | Transmission and distribution of electricity and distribution of natural gas to retail customers | | | Pepco Holdings LLC | | Utility services holding company engaged, through its reportable segments Pepco, DPL, and ACE | | Service Territories of Pepco, DPL, and ACE | | | | | | Potomac Electric
Power Company | | Purchase and regulated retail sale of electricity | | District of Columbia, and major portions of Montgomery and Prince George’s Counties, Maryland. | | | Transmission and distribution of electricity to retail customers | | | Delmarva Power & Light Company | | Purchase and regulated retail sale of electricity and natural gas | | Portions of Delaware and Maryland (electricity) | | | Transmission and distribution of electricity and distribution of natural gas to retail customers | | Portions of New Castle County, Delaware (natural gas) | Atlantic City Electric Company | | Purchase and regulated retail sale of electricity | | Portions of Southern New Jersey | | | Transmission and distribution of electricity to retail customers | | |
Basis of Presentation (All Registrants) This is a combined 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. All intercompany transactions have been eliminated.eliminated, except for the historical transactions between the Utility Registrants and Generation for the purposes of presenting discontinued operations in all periods presented in the Consolidated Statements of Operations and Comprehensive Income. Through its business services subsidiary, BSC, Exelon provides its subsidiaries with a variety of support services at cost, including legal, human resources, financial, information technology, and supply management services. PHI also has a business services subsidiary, PHISCO, which provides a variety of support services at cost, including legal, accounting,finance, 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” within the consolidated financial statements and include intercompany eliminations unless otherwise disclosed.
As of December 31, 2022 and 2021, Exelon owned 100% of PECO, BGE, and PHI and more than 99% of ComEd. PHI owns 100% of Pepco, DPL, and ACE. As of December 31, 2021, Exelon owned 100% of Generation. As of February 1, 2022, as a result of the completion of the separation, Exelon no longer owns any interest in Generation. The separation of Constellation, including Generation and its subsidiaries, meets the
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 1 — Significant Accounting Policies
Exelon owns 100%criteria for discontinued operations and as such, its results of operations are presented as discontinued operations and have been excluded from continuing operations for all periods presented. Accounting rules require that certain BSC costs previously allocated to Generation PECO, BGEbe presented as part of Exelon’s continuing operations as these costs do not qualify as expenses of the discontinued operations. Comprehensive income, shareholders' equity, and PHIcash flows related to Generation have not been segregated 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, of which Generation holds a 50.01% and 51% interest, respectively. The remaining interests in these consolidated VIEs are included in noncontrolling interests on Exelon’sthe Consolidated Statements of Operations and Generation’sComprehensive Income, Consolidated Balance Sheets.Statements of Changes in Shareholders’ Equity, and Consolidated Statements of Cash Flows, respectively, for all periods presented. See Note 222 — Variable Interest EntitiesDiscontinued Operations for additional information of Exelon’s and Generation’s consolidated VIEs.
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 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. 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 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 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. Changes in measurement are reported in earnings.information.
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, 2022 and 2021, 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. 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,unbilled energy revenues, allowance for credit losses, inventory reserves, allowance for uncollectible accounts, goodwill and long-lived asset impairments,impairment assessments, derivative instruments, unamortized energy contracts, fixed asset depreciation, environmental costs and other loss contingencies, taxesAROs, and unbilled energy revenues.taxes. Actual results could differ from those estimates. Prior Period Adjustments and Reclassifications (Exelon, PHI, and Pepco)ACE) In the fourthfirst quarter 2019,of 2022, management identified an error related to an overstatement of the regulatory assetliability associated with Pepco’s decouplingACE’s mechanism for Maryland that originatedto recover the cost of Transition Bonds issued in 2007 upon the inception of the program.2002 and 2003 by ACE Funding. Management has concluded that the error was not material to previously issued consolidated financial statements and thefor Exelon, PHI or ACE. The error was corrected through a revision to Exelon’s, PHI’s and Pepco’s consolidatedACE’s financial statements contained herein for the years ended December 31, 2018 and 2017.herein. The impact of the error correction was an $11$8 million reductionincrease to Exelon’s, PHI’s and Pepco’sACE’s opening Retained earnings as of January 1, 20172021 with a corresponding reduction to current Regulatory assetsliabilities of $18$11 million and an increase to Deferred income taxes and unamortized investment tax credits of $7$3 million. In addition, Exelon’s, PHI’s and Pepco’sThe impact of the error to ACE’s Total operating revenues decreased by $7and Net income was less than $1 million for the yearsyear 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.2021. 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 yearsyear ended December 31, 20182021. The error was corrected in the Exelon and 2017 for Exelon, PHI and Pepco. Exelon’s diluted earnings per share of common stock remained unchanged from the originally reported amountfinancial statements for the year ended December 31, 2018. Exelon’s basic earnings per share2022 as it was not material, resulting in an increase to Net income 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.
$8 million.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 1 — Significant Accounting Policies
Regulatory 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)(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-currentnoncurrent 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-currentnoncurrent 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 commoditiespower and related productsnatural gas and services, utility revenues from ARP, and realized and unrealized revenues recognized under mark-to-market energy commodity derivative contracts.ARP. 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. The companies recognize all ARP revenues that will be collected within 24 months of the end of the annual period in which they are recorded. See Note 3 — Regulatory Matters for additional information. 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 15 — 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 2322 — 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.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 1 — Significant Accounting Policies 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 and are based on the electricity produced by those generating assets.incurred. Operating lease expense, finance lease expense, and variable lease payments are primarily 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. 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 areincome is recognized in the period in which the related obligation is performed and consist primarily of payments received from sales of electricity under contracted generation and are based on the electricity produced by those generating assets.performed. Operating lease income and variable lease paymentsincome 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, the 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 arrangements are generally not leases. The Registrants do not account for secondary use pole attachments as leases. See Note 10 — 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.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 1 — Significant Accounting Policies 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, 20192022 and 2018,2021, 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 below for Generation and the Utility Registrants. | GenerationComEd | Project-specific nonrecourse financing structures for debt service and financing of operations of the underlying entities. | 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(a) | 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(a) | Repayment of transition bonds and collateral held from energy suppliers.Transition Bonds |
__________ (a) As of December 31, 2021, the Transition Bonds were fully redeemed. Restricted cash and cash equivalents not available to satisfy current liabilities are classified as noncurrent assets. As of December 31, 20192022 and 2018,2021, 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.site. See Note 2316 — Debt and Credit Agreements and Note 22 — 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, the allowance isbalances based on accounts receivable aging historical experience, current information, and other currently available information. Utility Registrants estimate thereasonable and supportable forecasts. The allowance for credit losses 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 Registrants' Consolidated Statements of Operations and Comprehensive Income or Regulatory assets and liabilities on the 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. Variable Interest Entities (Exelon, Generation, PHIother assets which primarily are with governmental agencies and ACE)
Exelon accountsother high-quality counterparties with no history of default. As such, the allowance for its investments incredit losses related to these receivables is not material. The Registrants monitor these balances and arrangements with VIEs based on the following specific requirements:
requireswill record an entity to qualitatively assess 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 consolidates a VIE (the primary beneficiary) to disclose (1) the assets of the consolidated VIE,allowance 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
liabilitiesthere are indicators of a consolidated VIE for which creditors do not have recourse to the generaldecline in credit of the primary beneficiary.
quality. See Note 226 — Variable Interest EntitiesAccounts Receivable 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 and materials and supplies and emissions allowances are generally included in inventory when purchased. Fossil fuel and emissions allowances areis expensed to purchasedPurchased power and fuel expense when used or sold. Materials and supplies generally includes transmission distribution and generating plantdistribution materials and are expensed to operatingOperating and maintenance or capitalized to property,Property, plant, and equipment, as appropriate, when installed or used.
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 reportedCombined Notes to Consolidated Financial Statements
(Dollars in OCI.millions, except per share data unless otherwise noted)
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 exception 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 as equity securities with readily determinable fair values. 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, 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's NDT funds are classified as current or noncurrent assets, depending on the timing of the decommissioning activities and income taxes on trust earnings. See Note 31 — Regulatory Matters for additional information regarding ComEd’s and PECO’s regulatory assets and liabilities and Note 17 — Fair Value of Financial Assets and Liabilities and Note 9 — Asset Retirement Obligations for additional information regarding marketable securities held by NDT funds.Significant Accounting Policies
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 includecosts and 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 capitalize 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 7 — Property, Plant, and Equipment, Note 8 — Jointly Owned Electric Utility Plant and Note 2322 — Supplemental Financial Information for additional information regarding property, plant and equipment. Nuclear Fuel (Exelon and Generation)
The cost of nuclear fuel is capitalized within Property, plant and equipment and charged to fuel expense using the unit-of-production method. Any potential future SNF disposal fees will be expensed through 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 18 — Commitments and Contingencies for additional information regarding the cost of SNF storage and disposal.
Nuclear Outage Costs (Exelon and Generation)
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.information.
Depreciation and Amortization (All Registrants) Except for the amortization of nuclear fuel, depreciationDepreciation is generally recorded over the estimated service lives of property, plant, and equipment on a straight-line basis using the group composite or unitarycomposite 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 and historical retirements, site licenses and management estimates of operating costs and expected future energy market conditions. See Note 6 — Early Plant Retirements for additional information on the impacts of expected and potential early plant retirements.
See Note 7 — 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.
Amortization of income tax related regulatory assets and liabilities is generally recorded to Income tax expense. Except for the regulatory assets and liabilities discussed above, amortization is generally recorded to
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 of 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 2322 — Supplemental Financial Information for additional information regarding Generation’s nuclear fuel and ARC, and the amortization of the Utility Registrants' regulatory assets. 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 AROThe 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 based on its annual evaluationfactor in new cost estimates, credit-adjusted, risk-free rates (CARFR) and escalation rates, and the timing 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.flows. AROs are accreted throughout each year to reflect the time value of money for these present value obligations through a 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 9 — 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 18 — 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 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 impairment may include a deteriorating business climate, including, but not limited to, declines in energy prices, condition of the asset, specific regulatory disallowance, abandonment, or plans to dispose of a long-lived asset significantly before the end of its useful life. The Registrants determine if long-lived assets and asset groups are impaired by comparingWhen the estimated undiscounted expected future cash flows attributable to the carrying value. 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 11 — 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 12 — Intangible Assets for additional information. Equity Method Investments (Exelon and Generation). Exelon and Generation regularly monitor and evaluate 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 Generation 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). Declines in the fair value of debt security investments below the cost basis are reviewed to determine if such decline is 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). Equity investments with readily determinable fair values are measured and recorded at fair value with any changes in fair value recorded through 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 derivativesDerivatives are recognized on the balance sheet at their fair value unless they qualify for certain exceptions, including NPNS. For derivatives that qualify and are designated as cash flow hedges, changes in fair value each period are initially recorded in AOCI and recognized in earnings when the NPNS. underlying hedged transaction affects earnings. Amounts recognized in earnings are recorded in Interest expense, net on the Consolidated Statement of Operations and Comprehensive Income based on the activity the transaction is economically hedging.Cash inflows and outflows related to derivative instruments designated as cash flow hedges 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.
For derivatives intended to serve as economic hedges, which are not designated for hedge accounting, changes in fair value each period are recognized in earnings or as a regulatory asset or liability each period. Amounts classifiedrecognized in earnings are includedrecorded in Operating revenue,Electric operating revenues, Purchased power and fuel, or 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 majority of the derivatives serve as economic hedges, there are also derivatives entered into for proprietary trading purposes, subject to Exelon’s Risk Management Policy, and changes in the fair value of those derivatives are recorded in revenue in the Consolidated Statements of Operations and Comprehensive Income. At the Utility Registrants, changesChanges in fair value may beare also recorded as a regulatory asset or liability ifwhen there is an ability to recover or return the associated costs.costs or benefits in accordance with regulatory requirements. Cash inflows and 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
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 1 — Significant Accounting Policies nature of each transaction. On July 1, 2018, Exelon and Generation de-designated its fair value and cash flow hedges.the hedged item. See Note 3 — Regulatory Matters and Note 15 — 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. See Note 15 — 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 14 — Retirement Benefits for additional information. New Accounting Standards (All Registrants)
2. Discontinued Operations (Exelon) 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"). Exelon completed the separation on February 1, 2022, through the distribution of 326,663,937 common stock shares of Constellation, the new publicly traded company, to Exelon shareholders. Under the separation plan, Exelon shareholders retained their current shares of Exelon stock and received one share of Constellation common stock for every three shares of Exelon common stock held on January 20, 2022, the record date for the distribution, in a transaction that was tax-free to Exelon and its shareholders for U.S. federal income tax purposes. Constellation was newly formed and incorporated in Pennsylvania on June 15, 2021 for the purposes of separation and holds Generation (including Generation's subsidiaries). Pursuant to the separation: New Accounting Standards Adopted in 2019:• In 2019,Exelon entered into four term loans consisting of a 364-day term loan for $1.15 billion and three 18-month term loans for $300 million, $300 million and $250 million, respectively. Exelon issued these term loans primarily to fund the Registrants adopted the following new authoritative accounting guidance issued by the FASB.cash payment to Constellation and for general corporate purposes. See Note 16 — Debt and Credit Agreements for additional information.
Cloud Computing Arrangements (Issued August 2018).• AlignsExelon made a cash payment of $1.75 billion to Constellation on January 31, 2022.
•Exelon contributed its equity ownership interest in Generation to Constellation. Exelon no longer retains any equity ownership interest in Generation or Constellation. •Exelon transferred certain corporate assets and employee-related obligations to Constellation. •Exelon received cash from Generation of $258 million to settle the requirementsintercompany loan on January 31, 2022. See Note 16 — Debt and Credit Agreements for capitalizing costs incurredadditional information. Continuing Involvement In order to implement a cloud computing arrangementgovern the ongoing relationships between Exelon and Constellation after the separation, and to facilitate an orderly transition, Exelon and Constellation have entered into several agreements, including the following: •Separation Agreement – governs the rights and obligations between Exelon and Constellation regarding certain actions to be taken in connection with the internal-use software guidance. As a result, certain implementation costs incurred in a cloud computing arrangement that are currently expensed as incurred will be deferredseparation, among others, including the allocation of assets and amortized overliabilities between Exelon and Constellation. •Transition Services Agreement (TSA) – governs the non-cancellable termterms and conditions of the arrangement plus any reasonablyservices that Exelon will provide to Constellation and Constellation will provide to Exelon for an expected period of two years, provided that certain renewal periods.services may be longer than the term and services may be extended with approval from both parties. The standard was effective Januaryservices include specified accounting, finance, information technology, human resources, employee benefits, and other services that have historically been provided on a centralized basis by BSC. For the period from February 1, 2020 and can be applied using either a prospective or retrospective transition approach. A retrospective approach requires a cumulative-effect adjustment2022 to retained earnings as ofDecember 31, 2022, the amounts Exelon billed
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 12 — Significant Accounting PoliciesDiscontinued Operations
Constellation and Constellation billed Exelon for these services were $266 million recorded in Other income, net and $43 million recorded in Operating and maintenance expense, respectively.
•Tax Matters Agreement (TMA) – governs the beginningrespective rights, responsibilities and obligations of Exelon and Constellation with respect to all tax matters, including tax liabilities and benefits, tax attributes, tax returns, tax contests and other tax sharing regarding U.S. federal, state, local and foreign income taxes, other tax matters and related tax returns. See Note 13 — Income Taxes for additional Information. In addition, the periodUtility Registrants will continue to incur expenses from transactions with Constellation after the separation. Prior to the separation, such expenses were primarily recorded as Purchased power from affiliates and an immaterial amount recorded as Operating and maintenance expense from affiliates at the Utility Registrants. After the separation, such expenses are primarily recorded as Purchased power and an immaterial amount recorded as Operating and maintenance expense at the Utility Registrants. •ComEd had an ICC-approved RFP contract with Constellation to provide a portion of adoption. ComEd’s electric supply requirements. ComEd also purchased RECs and ZECs from Constellation. •PECO received electric supply from Constellation under contracts executed through PECO’s competitive procurement process. In addition, PECO had a ten-year agreement with Constellation to sell solar AECs. •BGE received a portion of its energy requirements from Constellation under its MDPSC-approved market-based SOS and gas commodity programs. •Pepco received electric supply from Constellation under contracts executed through Pepco’s competitive procurement process approved by the MDPSC and DCPSC. •DPL received a portion of its energy requirements from Constellation under its MDPSC and DEPSC approved market-based SOS commodity programs. •ACE received electric supply from Constellation under contracts executed through ACE’s competitive procurement process approved by the NJBPU. ComEd and PECO also have receivables with Constellation for estimated excess funds at the end of decommissioning the Regulatory Agreement Units, such amounts are due back to ComEd and PECO, as applicable, for payment to their respective customers. See Note 3 — Regulatory Matters and Note 23 — Related Party Transactions for additional information. Discontinued Operations The Registrants early adopted this standard usingseparation represented a prospective approach as of January 1, 2019. The new guidance did notstrategic shift that would have a material impactmajor effect on Exelon’s operations and financial results. Accordingly, the Registrants' financial statements. Leases (Issued February 2016). The Registrants appliedseparation meets 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 accountedcriteria for as leases.discontinued operations.
The standard resultedfollowing table presents the results of Constellation that have been reclassified from continuing operations and included 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'discontinued operations within Exelon’s Consolidated Statements of Operations and Comprehensive Income for the years ended December 31, 2022, 2021, and 2020. These results are primarily Generation, which is comprised of Exelon’s Mid-Atlantic, Midwest, New York, ERCOT, and Other Power Regions reportable segments, and include the impact of transaction costs, certain BSC costs, including any transition costs, that were historically allocated and directly attributable to Generation, transactions between Generation and the Utility Registrants, and tax-related adjustments. Transaction costs include costs for external bankers, accountants, appraisers, lawyers, external counsels and other advisors, among others, who were involved in the negotiation, appraisal, due diligence and regulatory approval of the separation. Transition costs are primarily employee-related costs such as recruitment expenses, costs to establish certain stand-alone functions and information technology systems, professional services fees, and other separation-related costs during the transition to separate Generation. For the purposes of reporting discontinued operations, these results also include transactions between Generation and the Utility Registrants that were historically eliminated within Exelon’s 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 AdoptedOperations, as of January 1, 2020: The following new authoritative accounting guidance issued by the FASB was adopted as of January 1, 2020 andthese transactions will be reflected byongoing after the Registrantsseparation. Certain BSC costs that were historically allocated to Generation are presented as part of continuing operations 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)
CENG Put Option (Exelon and Generation)
Generation owns 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 22 — Variable Interest Entities for additional information.
On April 1, 2014, Generation and EDF entered into various agreements including a Nuclear Operating Services Agreement, an amended LLC Operating Agreement, an Employee Matters Agreement, and a Put Option Agreement, among others. Under the amended 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 DispositionsDiscontinued Operations
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 Put Option Agreement, EDF has 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 require approval by the NYPSC, the FERC and the NRC. The process and regulatory approvals could take one to two years or more to complete.
Acquisition of James A. FitzPatrick Nuclear Generating Station (Exelon and Generation)
On March 31, 2017, Generation acquired the single-unit James A. FitzPatrick (FitzPatrick) nuclear generating station located in Scriba, New York from Entergy Nuclear FitzPatrick LLC (Entergy) for a total purchase price of $289 million, which consisted of a cash purchase price of $110 million and a net cost reimbursement to and on behalf of Entergy of $179 million. As part of the transaction, Generation received the FitzPatrick NDT fund assets and assumed 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'sExelon’s Consolidated Statements of Operations as these costs do not qualify as expenses of the discontinued operations per the accounting rules.
| | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | | 2022 | | 2021 | | 2020 | Operating revenues | | | | | | Competitive business revenues | $ | 1,855 | | | $ | 18,466 | | | $ | 16,399 | | Competitive business revenues from affiliates | 161 | | | 1,189 | | | 1,206 | | Total operating revenues | 2,016 | | | 19,655 | | | 17,605 | | Operating expenses | | | | | | Competitive businesses purchased power and fuel | 1,138 | | | 12,163 | | | 9,585 | | Operating and maintenance(a) | 371 | | | 4,174 | | | 4,794 | | Depreciation and amortization | 94 | | | 3,003 | | | 2,123 | | Taxes other than income taxes | 44 | | | 475 | | | 482 | | Total operating expenses | 1,647 | | | 19,815 | | | 16,984 | | Gain on sales of assets and businesses | 10 | | | 201 | | | 11 | | Operating income | 379 | | | 41 | | | 632 | | Other income and (deductions) | | | | | | Interest expense, net | (20) | | | (282) | | | (328) | | Other, net | (281) | | | 795 | | | 937 | | Total other (deductions) and income | (301) | | | 513 | | | 609 | | Income before income taxes | 78 | | | 554 | | | 1,241 | | Income taxes | (40) | | | 332 | | | 380 | | Equity in losses of unconsolidated affiliates | (1) | | | (9) | | | (6) | | Net income | 117 | | | 213 | | | 855 | | Net income (loss) attributable to noncontrolling interests | 1 | | | 123 | | | (9) | | Net income from discontinued operations | $ | 116 | | | $ | 90 | | | $ | 864 | |
__________ (a)Includes transaction and Comprehensive Income which primarily reflects differences in strategies between Generationtransition costs related to the separation of $52 million and Entergy$43 million for the intended useyears ended December 31, 2022 and ultimate decommissioning of the plant. Exelon and Generation incurred $57 million of merger and integration2021, respectively. There were no separation related costs incurred in 2020. See discussion above for FitzPatrick foradditional information.
There were no assets and liabilities of discontinued operations included in Exelon's Consolidated Balance Sheet as of December 31, 2022. Constellation had net assets of $11,573 million that separated on February 1, 2022 that resulted in a reduction to Exelon's equity during the year ended December 31, 2017 which are included within Operating and maintenance expense2022. Refer to the Distribution of Constellation line in Exelon's and Generation's Consolidated StatementsStatement of Operations and Comprehensive Income.Changes in Shareholders' Equity for further information. 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), forThe following table presents 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 2019. The sale was completed on July 1, 2019. Exelon and Generation recognized a loss on the sale in the third quarter, 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 fuel until the spent fuel 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 of discontinued operations 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.
2021.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 2 — Mergers, Acquisitions and DispositionsDiscontinued Operations
| | | | | | | December 31, 2021 | ASSETS | | Current assets | | Cash and cash equivalents | $ | 510 | | Restricted cash and cash equivalents | 72 | | Accounts receivable | | Customer accounts receivable | 1,724 | Customer allowance for credit losses | (55) | Customer accounts receivable, net | 1,669 | | Other accounts receivable | 596 | Other allowance for credit losses | (4) | Other accounts receivable, net | 592 | | Mark-to-market derivative assets | 2,169 | | Inventories, net | | Fossil fuel and emission allowances | 284 | | Materials and supplies | 1,004 | | Renewable energy credits | 529 | | Assets held for sale | 13 | | Other | 993 | | Total current assets of discontinued operations | 7,835 | | Property, plant, and equipment (net of accumulated depreciation and amortization of $15,888) | 19,661 | | Deferred debits and other assets | | Nuclear decommissioning trust funds | 15,938 | | Investments | 193 | | Mark-to-market derivative assets | 949 | | Other | 1,768 | | Total property, plant, and equipment, deferred debits, and other assets of discontinued operations | 38,509 | | Total assets of discontinued operations | $ | 46,344 | |
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 2 — Discontinued Operations | | | | | | | December 31, 2021 | LIABILITIES AND SHAREHOLDERS’ EQUITY | | Current liabilities | | Short-term borrowings | $ | 2,082 | | Long-term debt due within one year | 1,220 | | Accounts payable | 1,757 | | Accrued expenses | 818 | | Mark-to-market derivative liabilities | 981 | | Renewable energy credit obligation | 779 | | Liabilities held for sale | 3 | | Other | 300 | | Total current liabilities of discontinued operations | 7,940 | | Long-term debt | 4,575 | | Deferred credits and other liabilities | | Deferred income taxes and unamortized investment tax credits | 3,583 | | Asset retirement obligations | 12,819 | | Pension obligations | 939 | | Non-pension postretirement benefit obligations | 876 | | Spent nuclear fuel obligation | 1,210 | | Mark-to-market derivative liabilities | 513 | | Other | 1,161 | | Total long-term debt, deferred credits, and other liabilities of discontinued operations | 25,676 | | Total liabilities of discontinued operations | $ | 33,616 | |
The following table presents selected financial information regarding cash flows of the discontinued operations that are included within Exelon’s Consolidated Statements of Cash Flows for the years ended December 31, 2022, 2021, and 2020. | | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | | 2022 | | 2021 | | 2020 | Non-cash items included in net income from discontinued operations: | | | | | | Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization | $ | 207 | | | $ | 4,540 | | | $ | 3,636 | | Asset impairments | — | | | 545 | | | 563 | | Loss (gain) on sales of assets and businesses | 9 | | | (201) | | | (11) | | Deferred income taxes and amortization of investment tax credits | (143) | | | (224) | | | 94 | | Net fair value changes related to derivatives | (59) | | | (568) | | | (270) | | Net realized and unrealized losses (gains) on NDT fund investments | 205 | | | (586) | | | (461) | | Net unrealized losses (gains) on equity investments | 16 | | | 160 | | | (186) | | Other decommissioning-related activity | 36 | | | (946) | | | (659) | | Cash flows from investing activities: | | | | | | Capital expenditures | (227) | | | (1,341) | | | (1,759) | | Collection of DPP | 169 | | | 3,902 | | | 3,771 | | Supplemental cash flow information: | | | | | | (Decrease) increase in capital expenditures not paid | (128) | | | 96 | | | (88) | | Increase in DPP | 348 | | | 3,652 | | | 4,441 | | Increase in PP&E related to ARO update | 335 | | | 618 | | | 850 | |
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 Registrants)
Distribution Base Rate Case Proceedings The following tables show the completed and pending distribution base rate case proceedings in 2019.2022. 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 Increase | | Approved Revenue Requirement Increase | | Approved ROE | | Approval Date | | Rate Effective Date | ComEd - Illinois(a) | | April 16, 2021 | | Electric | | $ | 51 | | | $ | 46 | | | 7.36% | | December 1, 2021 | | January 1, 2022 | | April 15, 2022 | | Electric | | 199 | | | 199 | | | 7.85% | | November 17, 2022 | | January 1, 2023 | PECO - Pennsylvania | | March 30, 2021 | | Electric | | 246 | | | 132 | | | N/A(b) | | November 18, 2021 | | January 1, 2022 | | March 31, 2022 | | Natural Gas | | 82 | | | 55 | | | | October 27, 2022 | | January 1, 2023 | 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 - Maryland | | September 1, 2021 (amended December 23, 2021)(f) | | Electric | | 27 | | | 13 | | | 9.60% | | March 2, 2022 | | March 2, 2022 | | May 19, 2022(g) | | Electric | | 38 | | | 29 | | | 9.60% | | December 14, 2022 | | January 1, 2023 | DPL - Delaware | | January 14, 2022 (amended August 15, 2022) | | Natural Gas | | 13 | | | 8 | | | 9.60% | | October 12, 2022 | | August 14, 2022 | ACE - New Jersey(h) | | December 9, 2020 (amended February 26, 2021) | | Electric | | 67 | | | 41 | | | 9.60% | | July 14, 2021 | | January 1, 2022 |
__________ | | (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. ComEd is required to file an annual update(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 CEJA 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. Under the performance-based formula, ComEd filed annual updates 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). |
ComEd’s 2018 approved revenue requirement above reflects a decrease of $58 millionin effect for the initialprior year revenue requirement for 2018 and an increase of $34 million related toactual costs incurred from the annual reconciliation for 2017. 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%year (annual reconciliation).
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
inclusive of an allowed ROE of 8.69%, reflecting the average rate on 30-year treasury notes plus 580 basis 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 monthly yields on 30-year treasury notesbonds plus 580 basis points less a performance metrics penalty of 7 basis points.
ComEd’s 2023 approved revenue requirement above reflects an increase of $144 million for the initial year revenue requirement for 2023 and an increase of $55 million related to the annual reconciliation for 2021. The revenue requirement for 2023 provides for a weighted average debt and equity return on distribution rate base of 5.94% inclusive of an allowed ROE of 7.85%, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points. The reconciliation revenue requirement for 2021 provides for a weighted average debt and equity return on distribution rate base of 5.91%, inclusive of an allowed ROE of 7.78%, reflecting the monthly yields on 30-year treasury bonds plus 580 basis points less a performance metrics penalty of 7 basis points. This is ComEd's last performance-based electric distribution formula rate update filing under EIMA. See tablediscussion of CEJA below for ComEd's regulatory assets associated with itsdetails on the transition away from the electric distribution formula rate.
(b)The PECO electric and natural gas base rate case proceedings were resolved through settlement agreements, which did not specify an approved ROE.
During(c)Reflects a three-year cumulative multi-year plan for 2021 through 2023. BGE proposed to use certain tax benefits to fully offset the firstincreases in 2021 and 2022 and partially offset the increase in 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. 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. In 2021, the MDPSC deferred a decision on whether to use certain tax benefits to offset the revenue requirement increases in 2023 and directed BGE to make another proposal at the end of 2022. In September 2022 BGE proposed that tax benefits not be used to offset the 2023 revenue requirement increases. On October 26, 2022, the MDPSC accepted BGE's recommendation to not use tax benefits to offset the 2023 revenue requirement increases.
(d)Reflects a cumulative multi-year plan with 18-months remaining in 2021 through 2022. The DCPSC awarded Pepco electric incremental revenue requirement increases of $42 million and $67 million, before offsets, for 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 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. (f)The approved settlement reflects a 9.60% ROE, which is solely for the purposes of calculating AFUDC and regulatory asset carrying costs. (g)Reflects a three-year cumulative multi-year plan for January 1, 2023 through December 31, 2025. The MDPSC awarded DPL electric incremental revenue requirement increases of $17 million, $6 million, and $6 million for 2023, 2024, and 2025, respectively. (h)Requested and approved increases are before New Jersey sales and use tax. The order allows ACE to retain approximately $11 million of certain tax benefits which resulted in a decrease to income tax expense in Exelon's, PHI's, and ACE's Consolidated Statements of Operations and Comprehensive Income in the third quarter of 2018, ComEd revised its electric distribution formula rate2021.
Combined Notes 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, usageConsolidated Financial Statements (Dollars in millions, except 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.share data unless otherwise noted)
| | (b) | The PECO rate case proceeding was resolved through a settlement agreement, which did not specify an approved ROE. |
Note 3 — Regulatory Matters
| | (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 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ComEd - Illinois(a) | | January 17, 2023 | | Electric | | $ | 1,472 | | | 10.50% to 10.65% | | Fourth quarter of 2023 | DPL - Delaware(b) | | December 15, 2022 | | Electric | | 60 | | | 10.50% | | Second quarter of 2024 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | __________ | | | | | | | | | 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)Reflects a four-year cumulative MRP for January 1, 2024 to December 31, 2027 and total requested revenue requirement increases of $877 million effective January 1, 2024, $175 million effective January 1, 2025, $217 million effective January 1, 2026, and $203 million effective January 1, 2027, based on forecasted revenue requirements. The revenue requirement will provide for a weighted average debt and equity return on distribution rate base of 7.43% in 2024, 7.50% in 2025, 7.62% in 2026, and 7.70% in 2027, inclusive of an allowed ROE of 10.50% in 2024, 10.55% in 2025, 10.60% in 2026, and 10.65% in 2027. The requested revenue requirements are based on capital structures that reflect between 50.58% and 51.19% common equity. ComEd’s MRP also includes a proposed rate phase-in to defer approximately $307 million of the $877 million year-over-year increase for 2024 revenue from 2024 to 2026._________(b)The rates will go into effect on July 15, 2023, subject to refund.
| | (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 additions (initial year revenue requirement). The update for ComEd also reconciles any differences between the revenue requirement in effect beginning June 1 of the prior year and actual costs incurred for that year (annual reconciliation). The annual update for PECO is based on prior year actual costs and current year projected capital additions, accumulated depreciation, and accumulated deferred income taxes. The annual update for BGE, Pepco, DPL, and ACE is based on prior year actual costs and current year projected capital additions, accumulated depreciation, depreciation and amortization expense, and accumulated deferred income taxes. The update for PECO, BGE, Pepco, DPL, and ACE also reconciles any differences between the actual costs and actual revenues for the calendar year (annual reconciliation).
For 2022, the following total increases/(decreases) were included in the Utility Registrants' electric transmission formula rate updates: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Registrant(a) | | Initial Revenue Requirement Increase | | Annual Reconciliation (Decrease) Increase | | Total Revenue Requirement Increase | | Allowed Return on Rate Base(b) | | Allowed ROE(c) | ComEd | | $ | 24 | | | $ | (24) | | | $ | — | | | 8.11 | % | | 11.50 | % | PECO | | 23 | | | 16 | | | 39 | | | 7.30 | % | | 10.35 | % | BGE | | 25 | | | (4) | | | 16 | | (d) | 7.30 | % | | 10.50 | % | Pepco | | 16 | | | 15 | | | 31 | | | 7.60 | % | | 10.50 | % | DPL | | 9 | | | 2 | | | 11 | | | 7.09 | % | | 10.50 | % | ACE | | 21 | | | 13 | | | 34 | | | 7.18 | % | | 10.50 | % |
__________ (a)All rates are effective June 1, 2022 - May 31, 2023, subject to review by interested parties pursuant to review protocols of each Utility Registrants' tariff.
(b)Represents the weighted average debt and equity return on transmission rate bases. For ComEd and PECO, the common equity component of the ratio used to calculate the weighted average debt and equity return on the transmission formula rate base is currently capped at 55% and 55.75%, respectively.
(c)The rate of return on common equity for each Utility Registrant includes a 50-basis-point incentive adder for being a member of a RTO. (d)The increase in BGE's transmission revenue requirement includes a $5 million reduction related to a FERC-approved dedicated facilities charge to recover the costs of providing transmission service to specifically designated load by BGE.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
For 2019, the following total increases/(decreases) were included in ComEd’s, BGE’s, Pepco's, DPL's and ACE's electric transmission formula rate filings:
| | | | | | | | | | | | | | | | 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 | % | BGE(a) | (10 | ) | (23 | ) | (19 | ) | (b) | 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 | % |
__________
| | (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, the rate of return on common equity is 11.50%, 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 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.
Other State Regulatory Matters Illinois Regulatory Matters CEJA (Exelon and ComEd). On September 15, 2021, the Governor of Illinois signed into law CEJA. CEJA includes, among other features, (1) procurement of CMCs from qualifying nuclear-powered generating facilities, (2) a requirement to file a general rate case or a new four-year MRP no later than January 20, 2023 to establish rates effective after ComEd’s existing performance-based distribution formula rate sunsets, (3) an extension of and certain adjustments to ComEd’s energy efficiency MWh savings goals, (4) revisions to the Illinois RPS requirements, including expanded charges for the procurement of RECs from wind and solar generation, (5) a requirement to accelerate amortization of ComEd’s unprotected excess deferred income taxes (EDIT) that ComEd was previously directed by the ICC to amortize using the average rate assumption method which equates to approximately 39.5 years, and (6) requirements that ComEd and the ICC initiate and conduct various regulatory proceedings on subjects including ethics, spending, grid investments, and performance metrics. Regulatory or legal challenges regarding the validity or implementation of CEJA are possible and Exelon and ComEd cannot reasonably predict the outcome of any such challenges. ComEd Electric Distribution Rates ComEd filed, and received approval for, its last performance-based electric distribution formula rate update filing under EIMA in 2022; those rates are in effect throughout 2023. 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 rate 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 U.S. Treasury bonds plus 580 basis points. ComEd will in 2023 file with the ICC the first such petition to reconcile its 2022 actual costs with the approved revenue requirement that was in effect in 2022. The rate year 2023 reconciliation will be filed in 2024. Beginning in 2024, ComEd will recover from retail customers, subject to certain exceptions, the costs it incurs to provide electric delivery services either through its electric distribution rate or other recovery mechanisms authorized by CEJA. On January 17, 2023, ComEd filed a petition with the ICC seeking approval of a MRP for 2024-2027. The MRP supports a multi-year grid plan (Grid Plan), also filed on January 17, covering planned investments on the electric distribution system within ComEd’s service area through 2027. Costs incurred during each year of the multi-year plan are subject to ICC review and the plan’s revenue requirement for each year will be reconciled with the actual costs that the ICC determines are prudently and reasonably incurred for that year. The reconciliation is subject to adjustment for certain costs, including a limitation on recovery of costs that are more than 105% of certain costs in the previously approved MRP revenue requirement, absent a modification of the rate plan itself. Thus, for example, 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 during 2025. The ICC must issue its decision on both the MRP and Grid Plan by mid-December 2023, for rates to begin with the January 2024 billing cycle. In January 2022, ComEd filed a request with the ICC proposing performance metrics that would be used in determining ROE incentives and penalties in the event ComEd filed a MRP in January 2023. On September 27, 2022, the ICC issued a final order approving seven performance metrics that provide symmetrical performance adjustments of 32 total basis points to ComEd’s rate of return on common equity based on the extent to which ComEd achieves the annual performance goals. On November 10, 2022, the ICC granted ComEd's application for rehearing, in part. Rehearing on those issues must conclude by April 9, 2023. It is unclear if rehearing will result in modifications to the ICC-approved performance and tracking metrics. ComEd will make its initial filing in 2025 to assess performance achieved under the metrics in 2024, and to determine any ROE adjustment, which would take effect in 2026. Carbon Mitigation Credit CEJA establishes decarbonization requirements for Illinois as well as programs to support the retention and development of emissions-free sources of electricity. ComEd is required to purchase CMCs from participating
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters nuclear-powered generating facilities between June 1, 2022 and May 31, 2027. 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 CEJA will result in net payments to ComEd ratepayers if the energy index, the capacity price and applicable federal tax credits or subsidy exceed the CMC contract price. ComEd began issuing credits to its retail customers under its new CMC rider in the June 2022 billing period and recorded a regulatory asset of $843 million as of December 31, 2022 for the difference between customer credits issued and the credit to be received from the participating nuclear-powered generating facilities. Under CEJA, the costs of procuring CMCs will be recovered through a new rider, the Rider Carbon-Free Resource Adjustment (Rider CFRA). The Rider CFRA provides for an annual reconciliation and true-up to actual costs incurred or credits received by ComEd to purchase CMCs, with any difference to be credited to or collected from ComEd’s retail customers in subsequent periods. The difference between the net payments to (or receivables from) ComEd ratepayers and the credits received by ComEd to purchase CMCs is recorded to Purchased Power expense with an offset to the regulatory asset (or regulatory liability). On December 21, 2022, ComEd filed a supplemental statement to the Rider CFRA proposing that the company recover costs or provide credits faster than the tariff allows, implement monthly reconciliations, and allow the Company to adjust Rider CFRA rates based not only on anticipated differences but also past payments or credits. The ICC approved the proposal on January 19, 2023. If the revised CFRA tariff were in effect as of the balance sheet date, the current portion of the CMC regulatory asset balance would have increased by $117 million as of December 31, 2022, with an offsetting reduction in the noncurrent regulatory asset balance. Excess Deferred Income Taxes The ICC initiated a docket to accelerate and fully credit to customers TCJA unprotected property-related EDIT no later than December 31, 2025. On July 7, 2022, the ICC issued a final order on the schedule for the acceleration of EDIT amortization, adopting the proposal as submitted by several parties, including ComEd, ICC Staff, the Illinois Attorney General's Office, and the Citizens Utility Board. EDIT amortization will be credited to customers through a new rider from January 1, 2023 through December 31, 2025. Beneficial Electrification Plan On July 1, 2022, ComEd filed a proposed plan to promote beneficial electrification efforts in its Northern Illinois service area with the ICC as required by CEJA. ComEd's plan is designed to meaningfully reduce barriers to beneficial electrification, including those related to electric vehicles (EVs), such as upfront technology adoption costs, charging costs, and charging availability; promote equity and environmental justice; reduce carbon emissions and surface-level pollutants; and support customer education and awareness of electrification options. As proposed, ComEd could expend approximately $300 million in total over the three-year period 2023 through 2025. The beneficial electrification plan requests recovery of all those costs through a rider mechanism, under which certain of the costs would be amortized over ten years with a return on the unrecovered balance. On November 10, 2022, in responses to a Staff motion, the ICC approved an interim order dismissing from ComEd’s Beneficial Electrification Plan certain rebates (rebates to support residential customers’ purchase of EVs; and rebates to ComEd’s commercial and industrial customers to support the installation of EV chargers). However, the ICC found that building electrification measures were properly within the scope of beneficial electrification, in line with ComEd’s proposal. The ICC also adopted ComEd’s position regarding the rate impact of spending associated with EV related infrastructure. On November 21, 2022, ComEd filed an application for rehearing of the interim order, which the ICC denied. On December 9, 2022, the Office of the Illinois Attorney General (AG) also sought rehearing. On December 15, 2022, ComEd filed an appeal of the ICC’s interim order and the denial of rehearing with the Illinois Appellate Court. That appeal has been stayed pending the resolution of the balance of the case. Also on December 15, 2022, the ICC denied the AG’s application for rehearing and the AG subsequently filed an appeal. The testimony and hearing phase of this proceeding has concluded and the parties are now drafting legal briefs on the contested issues. By law the ICC must issue its decision by the end of March, therefore, a final order is expected to be issued by the ICC no later than the first quarter of 2023. At this time, ComEd cannot predict the outcome of these proceedings.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters Energy Efficiency CEJA 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 2023 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 2019,2022, 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 | May 25, 2022 | | $ | 50 | | | $ | 50 | | | 7.85 | % | | October 27, 2022 | | January 1, 2023 |
| | | | | | | | | | | | | 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 2023 approved revenue requirement above reflects an increase of $66 million for the initial year revenue requirement for 2023 and a decrease of $16 million related to the annual reconciliation for 2021. The revenue requirement for 2023 provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 5.94% inclusive of an allowed ROE of 7.85%, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points. The revenue requirement for the 2021 reconciliation year provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 5.52% inclusive of an allowed ROE of 6.99%, which includes a downward performance adjustment that decreased the ROE. The performance adjustment can either increase or decrease the ROE based upon the achievement of energy efficiency savings goals. 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 outcome or the potential financial impact, if any, on BGE, Pepco or DPL.received funds of $50 million, 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
$12 million, and $8 million, respectively, in July 2021. The funds have been used to reduce or eliminate certain qualifying past-due residential customer receivables.
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. Termination of Energy Procurement Provisions of PPAs (Exelon, PHI, and ACE). On December 22, 2021, ACE filed with the NJBPU a petition to terminate the provisions in the PPAs to purchase electricity from two coal-powered generation facilities located in the state of New Jersey. The petition was approved by the NJBPU on March 23, 2022. Upon closing of the transaction on March 31, 2022, ACE recognized a liability of $203 million for the contract termination fee, which is to be paid by the end of 2024, and recognized a corresponding regulatory asset of$203 million. As of December 31, 2022, the $137 million liability for the contract termination fee consists of $87 million and $50 million included in Other current liabilities and Other deferred credits and other liabilities, respectively, in Exelon's Consolidated Balance Sheet. The current and noncurrent liabilities are included in PPA termination obligation and Other deferred credits and other liabilities, respectively, in PHI's and ACE's Consolidated Balance Sheets. For the year ended December 31, 2022, ACE has paid $66 million of the liability, which is recorded in Changes in Other assets and liabilities in Exelon's, PHI's, and ACE's Consolidated Statements of Cash Flows. ACE Infrastructure Investment Program FilingFilings (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. On October 31, 2022, ACE filed with the NJBPU the company’s second IIP, proposing to seek recovery through a new component of ACE’s rider mechanism, totaling $379 million, over the four-year period of July 1, 2023 to June 30, 2027. The new IIP will allow ACE to invest in projects that are designed to enhance the reliability, resiliency, and safety of the service ACE provides to its customers. ACE has requested that the NJBPU render a
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters decision in this matter during the first half of 2023 but cannot predict if the NJBPU will approve the application as filed. 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 contributionrequirements. Under the legislation, the NJBPU will issue ZECs to air quality in the statequalifying nuclear power plants and that their revenues are insufficient to cover their costs and risks. Electricthe electric distribution utilities in New Jersey, including ACE, will be required to purchase those ZECs. 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. 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's(2) 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
in the second quarter of 2020.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
upFERC Audit (Exelon and ComEd). The Registrants are subject to approximately $79 million, $51 million, $17 million, $11 million, $4 million, $5 millionperiodic audits and $2 million, respectively, asinvestigations by FERC. FERC’s Division of DecemberAudits and Accounting initiated a nonpublic audit of ComEd in May 2021 evaluating ComEd’s compliance with (1) approved terms, rates and conditions of its transmission formula rate mechanism; (2) accounting requirements of the Uniform System of Accounts; (3) reporting requirements of the FERC Form 1; and (4) the requirements for record retention. The audit covered the period from January 1, 2017 through August 31, 2019.
PJM Transmission Rate Design (All Registrants).2022. On June 15, 2016, several parties,January 17, 2023, ComEd was provided with information on a series of potential findings, including concerning ComEd's methodology regarding the Utility Registrants, filed a proposed settlement withallocation of certain overhead costs to capital under FERC to resolve outstanding issues related to cost responsibility for charges to transmission customers for certain transmission facilities that operateregulations. The final outcome and resolution of the findings or of the audit itself cannot be predicted and the results, while not reasonably estimable at or above 500 kV. The settlement included provisions for monthly credits or charges relatedthis time, could be material to the periods priorExelon and ComEd financial statements.
Combined Notes 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 settlementConsolidated Financial Statements (Dollars in August 2018.millions, except per share data unless otherwise noted)
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.
Note 3 — Regulatory Matters | | | | | | | | | | | | | | | 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. The following tables provide information about the regulatory assets and liabilities of the Registrants as of December 31, 2022 and 2021: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2022 | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Regulatory assets | | | | | | | | | | | | | | | | Pension and OPEB | $ | 1,867 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | Pension and OPEB - merger related | 769 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Deferred income taxes | 606 | | | — | | | 595 | | | — | | | 11 | | | 11 | | | — | | | — | | AMI programs - deployment costs | 122 | | | — | | | — | | | 69 | | | 53 | | | 25 | | | 22 | | | 6 | | AMI programs - legacy meters | 160 | | | 48 | | | — | | | 20 | | | 92 | | | 53 | | | 17 | | | 22 | | | | | | | | | | | | | | | | | | Electric distribution formula rate annual reconciliations | 271 | | | 271 | | | — | | | — | | | — | | | — | | | — | | | — | | Electric distribution formula rate significant one-time events | 115 | | | 115 | | | — | | | — | | | — | | | — | | | — | | | — | | Energy efficiency costs | 1,434 | | | 1,434 | | | — | | | — | | | — | | | — | | | — | | | — | | Fair value of long-term debt | 521 | | | — | | | — | | | — | | | 414 | | | — | | | — | | | — | | Fair value of PHI's unamortized energy contracts | 44 | | | — | | | — | | | — | | | 44 | | | — | | | — | | | — | | Carbon mitigation credit | 843 | | | 843 | | | — | | | — | | | — | | | — | | | — | | | — | | Asset retirement obligations | 151 | | | 99 | | | 22 | | | 21 | | | 9 | | | 6 | | | 2 | | | 1 | | MGP remediation costs | 318 | | | 293 | | | 13 | | | 12 | | | — | | | — | | | — | | | — | | Renewable energy | 85 | | | 85 | | | — | | | — | | | — | | | — | | | — | | | — | | Electric energy and natural gas costs | 241 | | | — | | | 15 | | | 25 | | | 201 | | | 41 | | | 26 | | | 134 | | Transmission formula rate annual reconciliations | 37 | | | — | | | 16 | | | — | | | 21 | | | 3 | | | 5 | | | 13 | | Energy efficiency and demand response programs | 560 | | | — | | | — | | | 286 | | | 274 | | | 187 | | | 74 | | | 13 | | | | | | | | | | | | | | | | | | Under-recovered revenue decoupling | 106 | | | — | | | — | | | 8 | | | 98 | | | 98 | | | — | | | — | | | | | | | | | | | | | | | | | | Removal costs | 782 | | | — | | | — | | | 171 | | | 611 | | | 144 | | | 109 | | | 359 | | DC PLUG charge | 37 | | | — | | | — | | | — | | | 37 | | | 37 | | | — | | | — | | Deferred storm costs | 90 | | | — | | | — | | | 55 | | | 35 | | | 2 | | | 2 | | | 31 | | COVID-19 | 58 | | | 20 | | | 17 | | | 8 | | | 13 | | | 10 | | | 3 | | | — | | Under-recovered credit loss expense | 71 | | | 38 | | | — | | | — | | | 33 | | | — | | | — | | | 33 | | Other | 390 | | | 196 | | | 54 | | | 29 | | | 119 | | | 55 | | | 22 | | | 12 | | Total regulatory assets | 9,678 | | | 3,442 | | | 732 | | | 704 | | | 2,065 | | | 672 | | | 282 | | | 624 | | Less: current portion | 1,641 | | | 775 | | | 80 | | | 177 | | | 455 | | | 235 | | | 80 | | | 130 | | Total noncurrent regulatory assets | $ | 8,037 | | | $ | 2,667 | | | $ | 652 | | | $ | 527 | | | $ | 1,610 | | | $ | 437 | | | $ | 202 | | | $ | 494 | |
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 ACE as of December 31, 2019 and December 31, 2018: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2022 | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Regulatory liabilities | | | | | | | | | | | | | | | | Deferred income taxes | $ | 3,546 | | | $ | 2,010 | | | $ | — | | | $ | 682 | | | $ | 854 | | | $ | 402 | | | $ | 304 | | | $ | 148 | | Decommissioning the Regulatory Agreement Units | 2,897 | | | 2,660 | | | 237 | | | — | | | — | | | — | | | — | | | — | | Removal costs | 1,750 | | | 1,604 | | | — | | | 35 | | | 111 | | | 20 | | | 91 | | | — | | Electric energy and natural gas costs | 87 | | | 11 | | | 65 | | | 4 | | | 7 | | | — | | | 7 | | | — | | Transmission formula rate annual reconciliations | 31 | | | 3 | | | — | | | 18 | | | 10 | | | 9 | | | 1 | | | — | | Renewable portfolio standards costs | 810 | | | 810 | | | — | | | — | | | — | | | — | | | — | | | — | | Stranded costs | 9 | | | — | | | — | | | — | | | 9 | | | — | | | — | | | 9 | | Energy efficiency and demand response programs | 15 | | | — | | | 15 | | | — | | | — | | | — | | | — | | | — | | Over-recovered revenue decoupling | 19 | | | — | | | — | | | 4 | | | 15 | | | — | | | 6 | | | 9 | | Dedicated facilities charge | 110 | | | — | | | — | | | 110 | | | — | | | — | | | — | | | — | | Other | 275 | | | 41 | | | 28 | | | 10 | | | 81 | | | 30 | | | 15 | | | 16 | | Total regulatory liabilities | 9,549 | | | 7,139 | | | 345 | | | 863 | | | 1,087 | | | 461 | | | 424 | | | 182 | | Less: current portion | 437 | | | 226 | | | 75 | | | 47 | | | 76 | | | 6 | | | 44 | | | 26 | | Total noncurrent regulatory liabilities | $ | 9,112 | | | $ | 6,913 | | | $ | 270 | | | $ | 816 | | | $ | 1,011 | | | $ | 455 | | | $ | 380 | | | $ | 156 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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 |
|
181
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 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 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 |
|
182
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 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 |
|
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, 2021 | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Regulatory liabilities | | | | | | | | | | | | | | | | Deferred income taxes | $ | 4,005 | | | $ | 2,105 | | | $ | — | | | $ | 819 | | | $ | 1,081 | | | $ | 525 | | | $ | 354 | | | $ | 202 | | Decommissioning the Regulatory Agreement Units | 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 | | | — | | | — | | | 24 | | Other | 292 | | | 6 | | | 61 | | | 102 | | | 58 | | | 8 | | | 15 | | | 11 | | Total regulatory liabilities | 10,004 | | | 6,944 | | | 729 | | | 960 | | | 1,306 | | | 563 | | | 466 | | | 242 | | 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 | | | $ | 214 | |
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 –— 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 established at the date of the Constellation and PHI mergers are amortized over the plan participants' average remaining service periods subject to applicable pension and other postretirementOPEB cost recognition policies. The costs are recovered through customer rates once amortized through net periodic benefit cost. See Note 14 –— Retirement Benefits for additional information. The capitalized non–service cost components are amortized over the lives of the underlying assets. | Legacy ConstellationBGE - 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 | DeferredRepresents 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. | OverAmounts are recoverable 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
| InstallationRepresents 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 - 20272029 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 | EarlyRepresents early retirement costs of legacy meters. | ComEd - 2028 PECO - 2020
BGE - 2026 Pepco - 20272029 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-recoveriesRepresents under/(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
2024
| Yes | Electric distribution formula rate significant one-time events
| Under-recoveries of electricRepresents deferred 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. | 20232026 | 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
| Represents 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. | 20292034 | 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$107 million and $127$414 million, respectively, as of December 30, 201931, 2022, and $569$114 million and $133$443 million, respectively, as of December 30, 2018,31, 2021, 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 | Carbon mitigation credit | Represents CMC procurement costs and credits as well as reasonable costs ComEd has incurred to implement and comply with the CMC procurement process. | Over 9 months starting with the September billing period and ending with the following May billing period | No | Asset Retirement Obligationsretirement obligations | FutureRepresents future legally required removal costs associated with existing asset retirement obligations.AROs. | Over the life of the related assets.assets | Yes, once the removal activities have been performed.performed | MGP Remediation Costs remediation costs
| EnvironmentalRepresents environmental remediation costs for MGP sites.
sites recorded at ComEd, PECO, and BGE.
| ComEd and PECO - Over the expected remediation period. See Note 18 -— Commitments and Contingencies for additional information.
BGE - 10 years from when the remediation spend is approved by the MDPSC. | ComEd and PECO - No
BGE - Yes | Renewable Energyenergy | Represents the change in fair value of ComEd‘s 20-year floating-to-fixed long-term renewable energy swap contracts. | 2032 | No |
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
| No | | | | | | | | | | | Line Item | Description | End Date of Remaining Recovery/Refund Period | Return | Electric Energyenergy and Natural Gas Costsnatural gas costs | UnderRepresents 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
| UnderRepresents 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.
| 20212024 | 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 - 20242027 Pepco, DPL - 20342037 ACE - 2032 | BGE, Pepco (Maryland), DPL (Maryland), ACE - Yes DPL (Delaware), Pepco (District of Columbia) - No PECO - Yes on capital investment recovered through this mechanism | | | | | Under (over) -recovered revenue decoupling
| Represents electric and / or gas distribution costs recoverable from or refundable to customers under decoupling mechanisms. | BGE - 2023 Pepco (Maryland) - $11 million - 2023 Pepco (District of Columbia) - $87 million: $49 million to be recovered via monthly surcharge by 2024; $38 million to be recovered via the monthly surcharge, the timing of which will be impacted by the next multi-year plan filed with DCPSC DPL - 2023 ACE - 2024 | BGE, Pepco, DPL, ACE - No | Stranded costs
| The 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 - 2024 | Stranded costs - Yes
Overcollection - 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 | Merger Integration CostsRemoval costs
| 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, Pepco and DPL - 2020 | BGE, Pepco, DPL- No | Securitized Stranded Costs
| Represents certain stranded costs associated with ACE's former electricity generation business.
| 2022
| Yes | Removal 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
| CostsRepresents 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
| Deferred Storm Costsstorm costs | For Pepco, DPL, ACE, and ACEBGE, 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 - 20232027
ACE - 2022$24 million - 2024; $7 million to be determined in next distribution rate case filed with NJBPU
BGE - $55 million to be determined in next multi-year plan filed with MDPSC | Pepco, DPL, BGE - Yes
ACE - No
| Nuclear Decommissioning
the Regulatory Units
| Estimated futureRepresents estimated excess funds at the end of decommissioning costs forthe Regulatory Agreement Units. See below regarding Decommissioning the Regulatory Agreement Units that are less than the associated NDT fund assets. See Note 9 - Asset Retirement Obligations for additional information. | Not currently being refunded. refunded
| 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 | COVID-19 | Represents 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 - $4 million - 2025; $4 million to be determined in the next multi-year plan filed with MDPSC
PECO - 2024
Pepco (District of Columbia) - $8 million to be determined in the next multi-year plan filed with DCPSC
Pepco (Maryland) - $1 million - 2026; $1 million to be determined in the next multi-year plan filed with MDPSC
DPL (Maryland) - $1 million - 2027
DPL (Delaware) - $2 million to be determined in pending distribution rate case filed with DEPSC | ComEd and BGE - Yes
PECO, Pepco, and DPL - No | 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 |
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 | 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. | $743 million to be determined in the ICC annual reconciliation for 2023
$67 million to be determined based on the LTRRPP developed by the IPA | No | Dedicated facilities charge | Represents the timing difference between the recovery of certain transmission-related assets and their depreciable life. | Depreciable life of the related assets | Yes |
Decommissioning the Regulatory Agreement Units The regulatory agreements with the ICC and PAPUC dictate 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. 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 Constellation to ultimately return excess funds to PECO customers (on an aggregate basis for all seven units), decommissioning-related activities prior to separation on February 1, 2022 were generally offset in Exelon’s Consolidated Statements of Operations and Comprehensive Income with an offsetting adjustment to the regulatory liabilities or regulatory assets and an equal noncurrent affiliate receivable from or payable to Generation at PECO. Following the separation, decommissioning-related activities result in an adjustment to the Receivable related to Regulatory Agreement Units and an equal adjustment to the regulatory liabilities or regulatory assets at PECO. For the former ComEd units, given no further recovery from ComEd customers is permitted and Constellation retains an obligation to ultimately return excess funds to ComEd customers (on a unit-by-unit basis), to the extent excess funds are expected for each unit, decommissioning-related activities prior to separation on February 1, 2022 were offset in the Consolidated Statements of Operations and Comprehensive Income with an offsetting adjustment to regulatory liabilities and noncurrent affiliate receivable from Generation at ComEd. Following the separation, decommissioning-related activities result in an adjustment to the Receivable related to Regulatory Agreement Units and an equal adjustment to the regulatory liabilities at ComEd. However, given the asymmetric settlement provision that does not allow for continued recovery from ComEd customers in the event of a shortfall, recognition of a regulatory asset at ComEd is not permissible.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters 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(b) | December 31, 2022 | $ | 57 | | | $ | 8 | | | $ | — | | | $ | 28 | | | $ | 21 | | | $ | 18 | | | $ | 2 | | | $ | 1 | | December 31, 2021 | 43 | | | 1 | | | — | | | 37 | | | 5 | | | 3 | | | 2 | | | — | |
__________ | | (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. |
Generation Regulatory Matters (Exelon and Generation)
Illinois Regulatory Matters(a)Reflects ComEd's unrecognized equity returns earned for ratemaking purposes on its electric distribution formula rate regulatory assets.
Zero Emission Standard.(b)PursuantBGE's and ACE's authorized amounts capitalized for ratemaking purposes primarily relate to FEJA,earnings 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.shareholders' investment on their respective AMI programs.
Generation executed the ZEC procurement contracts with Illinois utilities, including ComEd, effective January 26, 2018(c)Pepco's and began recognizing revenue with compensationDPL's authorized amounts capitalized for the sale of ZECs retroactiveratemaking purposes relate 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 IPAearnings on shareholders' investment on their respective AMI Programs and Energy Efficiency and Demand Response Programs, and 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 revenue related to ZECs generated from June 1, 2017 through December 31, 2017.
On February 14, 2017, two lawsuits were filed in the NorthernPepco District of 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 theColumbia revenue decoupling program. The lawsuits were dismissed by the district courtearnings 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.
New Jersey Regulatory Matters
New Jersey Clean Energy Legislation. On May 23, 2018, New Jersey enacted legislation that established a ZEC program that will provide 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 million for the year ended December 31, 2019. On May 15, 2019, New Jersey Rate Counsel appealed the NJBPU’s decision to the New Jersey Superior Court. The appeal does not prevent implementation of the ZEC program. Exelon and Generation cannot 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.
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). If a resource is subjected to a MOPR, its offer is adjusted to effectively remove the revenues it receives through a 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 apply to certain new gas-fired resources.
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 facilities in PJM and NYISO that are currently receiving ZEC compensation, an expanded MOPR would require exclusion of ZEC 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 the PJM MOPR proceeding that broadly applies the MOPR to all new and existing resources including nuclear, renewables, demand response, energy efficiency storageare on Pepco District of Columbia and all resources owned by vertically-integrated utilities, greatly expanding the breadth and scope of PJM’s MOPR, effective as of PJM’s next capacity auction, 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. 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 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 Illinois and New Jersey can implement an FRR program in their PJM zones, the MOPR will apply to Generation's owned or jointly owned nuclear plants in those states receiving a benefit under the Illinois ZES or the New Jersey ZEC program, as applicable, 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 of FERC’s December 19, 2019 order on the PJM MOPR. FERC routinely extends the deadline by which it must address requests for rehearing. FERC has not yet acted, and has no deadline by which it must act, in the NYISO proceeding.
Exelon is currently working with PJM and other stakeholders to pursue the FRR option prior to the next 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
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 license 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 has 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 contains 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.
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 are modifications to river flows to improve aquatic habitat, eel passage improvements and initiatives to support rare, threatened and endangered wildlife. If FERC approves the Offer of Settlement and incorporates the Proposed License Articles into the new license without modification, then MDE would waive its rights to issue a 401 Certification and Generation would agree, pursuant to a separate agreement with MDE (MDE Settlement), 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 under the various provisions of the Offer of Settlement and MDE Settlement are not effective unless and until FERC approves the Offer of Settlement and issues the new license with the Proposed License Articles.
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 submitted 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 currently licensed to operate through 2033 and 2034, respectively. See Note 7 – Property, Plant and Equipment for additional information regarding the estimated useful life and depreciation provisions for Peach Bottom.DPL Delaware programs only.
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.consideration. 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) | Sales of power and other energy-related commodities to wholesale and retail customers across multiple geographic regions through its customer-facing business, Constellation. | 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) | 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) | 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 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) (a) | Within the month following delivery of the electricity or natural gas to the customer. | Regulated Transmission Services (Exelon and the Utility 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) (b) | 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) | (a)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 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 |
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 4 — Revenue from Contracts with 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) | (b)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 powerthe wholesale grid and gas sales contracts. These costs, which primarily relate to retail broker feesMWhs of energy transported over the wholesale grid is used for scheduling, system control and sales commissions, are capitalized when incurred as contract acquisition costs and were immaterial as of December 31, 2019 and 2018. dispatch services.
The Utility Registrants do not incur any material costs to obtain or fulfill contracts with customers. Contract Balances (All Registrants) Contract Assets and Liabilities
Generation records contract assets for the revenue recognized on the construction and installation of energy efficiency assets and new power generating facilities before Generation has an unconditional right to bill for and receive the consideration from the customer. These contract assets are subsequently reclassified to receivables when the right to payment becomes unconditional. Generation records contract assets and contract receivables within Other current assets and Accounts receivable, net - Customer, respectively, within Exelon’s and Generation’s Consolidated Balance Sheets.
Generation recordsThe Registrants record contract liabilities when consideration is received or due prior to the satisfaction of the performance obligations. TheseThe Registrants record 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 contract liabilities within Other current liabilities and Other noncurrent liabilities within Exelon’s and Generation’sin the Registrants' Consolidated Balance Sheets.
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 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 as of July 1, 2020. 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, 20192022, 2021, and December 31, 2018, the Utility Registrants'2020, ComEd's, PECO's, and BGE's contract liabilities were immaterial.not material.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 4 — Revenue from Contracts with Customers | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exelon(a) | | PHI(a) | | Pepco(a) | | DPL(a) | | ACE(a) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Balance as of December 31, 2020 | $ | 118 | | | $ | 118 | | | $ | 94 | | | $ | 12 | | | $ | 12 | | | | | | | | | | | | Revenues recognized | (9) | | | (9) | | | (7) | | | (1) | | | (1) | | | | | | | | | | | | Balance as of December 31, 2021 | 109 | | | 109 | | | 87 | | | 11 | | | 11 | | | | | | | | | | | | Revenues recognized | (8) | | | (8) | | | (6) | | | (1) | | | (1) | | | | | | | | | | | | Balance as of December 31, 2022 | $ | 101 | | | $ | 101 | | | $ | 81 | | | $ | 10 | | | $ | 10 | | __________(a)Revenues recognized in the years ended December 31, 2022 and 2021, were included in the contract liabilities at December 31, 2021 and 2020, respectively. 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, 2019.2022. This disclosure only includes contracts for which the total consideration is fixed and determinable at contract inception. The average contract term varies by customer type and commodity but ranges from one month to several years. This disclosure excludes Generation’s power and gas sales contracts as they contain variable volumes and/or variable pricing. This disclosure also excludes the Utility Registrants’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 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2023 | | 2024 | | 2025 | | 2026 | | 2027 and thereafter | | Total | Exelon | $ | 8 | | | $ | 6 | | | $ | 5 | | | $ | 5 | | | $ | 77 | | | $ | 101 | | PHI | 8 | | | 6 | | | 5 | | | 5 | | | 77 | | | 101 | | Pepco | 6 | | | 5 | | | 5 | | | 5 | | | 60 | | | 81 | | DPL | 1 | | | — | | | — | | | — | | | 9 | | | 10 | | ACE | 1 | | | 1 | | | — | | | — | | | 8 | | | 10 | |
Revenue Disaggregation (All Registrants) The Registrants disaggregate revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. See Note Note 5 — Segment Information for the presentation of the Registrant's revenue disaggregation. 5. Segment Information (All Registrants) Operating segments for each of the Registrants are determined based on information used by the CODMCODMs in deciding how to evaluate performance and allocate resources at each of the Registrants. Exelon has 11six reportable segments, which include Generation's 5 reportable segments consisting of the Mid-Atlantic, Midwest, New York, ERCOT and all other power regions referred to collectively as “Other Power Regions” and ComEd, PECO, BGE, and PHI's 3three 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 basisseparation of Constellation Energy Corporation, including Generation and its subsidiaries, meets the criteria for Generation'sdiscontinued operations and as such, results of operations are presented as discontinued operations and have been excluded from continuing operations for all periods presented. Furthermore, the reportable segments issegment information related to the integrated management of its electricity business that is located in different geographic regions,discontinued operations has been excluded from the tables presented below. See Note 2 — Discontinued Operations for additional information. An analysis and largely representativereconciliation of the footprints of ISO/RTO and/or NERC regions, which utilize multiple supply sourcesRegistrants' reportable segment information to provide electricity through various distribution channels (wholesalethe respective information in the consolidated financial statements for the years ended December 31, 2022, 2021, and retail). Generation's hedging strategies and risk metrics are also aligned to these same geographic regions. Descriptions of each of Generation’s 5 reportable segments are2020 is as follows: | | • | Mid-Atlantic represents operations in the eastern half of PJM, which includes New Jersey, Maryland, Virginia, West Virginia, Delaware, the District of Columbia and parts of Pennsylvania and North Carolina.
|
| | • | Midwest represents operations in the western half of PJM and the United States footprint of MISO, excluding MISO’s Southern Region.
|
| | • | New York represents operations within NYISO.
|
| | • | ERCOT represents operations within Electric Reliability Council of Texas.
|
Other Power Regions:
| | • | New England represents 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 evaluate the performance of Generation’s electric business activities and allocate resources based on RNF. Generation believes that RNF is a useful measurement of operational performance. RNF is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report. Generation’s operating revenues include all sales to third parties and affiliated sales to the Utility Registrants. Purchased power costs include all costs associated with the procurement and supply of electricity including capacity, energy and ancillary services. Fuel expense includes the fuel costs for Generation’s owned generation and fuel costs associated with tolling agreements. The results of Generation's other business activities are not regularly reviewed by the CODM and are therefore not classified as operating segments or included in the regional reportable segment
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 do 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 consolidated financial statements for the years ended December 31, 2019, 2018, and 2017 is as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ComEd | | PECO | | BGE | | PHI | | Other(a) | | Intersegment Eliminations | | Exelon | Operating revenues(b): | | | | | | | | | | | | | | 2022 | | | | | | | | | | | | | | Electric revenues | $ | 5,761 | | | $ | 3,165 | | | $ | 2,871 | | | $ | 5,317 | | | $ | — | | | $ | (31) | | | $ | 17,083 | | Natural gas revenues | — | | | 738 | | | 1,024 | | | 238 | | | — | | | (5) | | | 1,995 | | Shared service and other revenues | — | | | — | | | — | | | 10 | | | 1,823 | | | (1,833) | | | — | | Total operating revenues | $ | 5,761 | | | $ | 3,903 | | | $ | 3,895 | | | $ | 5,565 | | | $ | 1,823 | | | $ | (1,869) | | | $ | 19,078 | | 2021 | | | | | | | | | | | | | | Electric revenues | $ | 6,406 | | | $ | 2,659 | | | $ | 2,505 | | | $ | 4,860 | | | $ | — | | | $ | (35) | | | $ | 16,395 | | Natural gas revenues | — | | | 539 | | | 836 | | | 168 | | | — | | | — | | | 1,543 | | Shared service and other revenues | — | | | — | | | — | | | 13 | | | 2,213 | | | (2,226) | | | — | | Total operating revenues | $ | 6,406 | | | $ | 3,198 | | | $ | 3,341 | | | $ | 5,041 | | | $ | 2,213 | | | $ | (2,261) | | | $ | 17,938 | | 2020 | | | | | | | | | | | | | | Electric revenues | $ | 5,904 | | | $ | 2,543 | | | $ | 2,336 | | | $ | 4,485 | | | $ | — | | | $ | (44) | | | $ | 15,224 | | Natural gas revenues | — | | | 515 | | | 762 | | | 162 | | | — | | | — | | | 1,439 | | Shared service and other revenues | — | | | — | | | — | | | 16 | | | 2,035 | | | (2,051) | | | — | | Total operating revenues | $ | 5,904 | | | $ | 3,058 | | | $ | 3,098 | | | $ | 4,663 | | | $ | 2,035 | | | $ | (2,095) | | | $ | 16,663 | | | | | | | | | | | | | | | | Intersegment revenues(c): | | | | | | | | | | | | | | 2022 | $ | 16 | | | $ | 7 | | | $ | 15 | | | $ | 10 | | | $ | 1,823 | | | $ | (1,865) | | | $ | 6 | | 2021 | 41 | | | 21 | | | 31 | | | 13 | | | 2,203 | | | (2,252) | | | 57 | | 2020 | 37 | | | 9 | | | 20 | | | 17 | | | 2,024 | | | (2,084) | | | 23 | | Depreciation and amortization: | | | | | | | | | | | | | | 2022 | $ | 1,323 | | | $ | 373 | | | $ | 630 | | | $ | 938 | | | $ | 61 | | | $ | — | | | $ | 3,325 | | 2021 | 1,205 | | | 348 | | | 591 | | | 821 | | | 67 | | | 1 | | | 3,033 | | 2020 | 1,133 | | | 347 | | | 550 | | | 782 | | | 79 | | | — | | | 2,891 | | Operating expenses: | | | | | | | | | | | | | | 2022 | $ | 4,218 | | | $ | 3,102 | | | $ | 3,376 | | | $ | 4,734 | | | $ | 2,093 | | | $ | (1,762) | | | $ | 15,761 | | 2021 | 5,151 | | | 2,547 | | | 2,860 | | | 4,240 | | | 2,045 | | | (1,587) | | | 15,256 | | 2020 | 4,950 | | | 2,512 | | | 2,598 | | | 4,045 | | | 1,882 | | | (1,502) | | | 14,485 | | Interest expense, net: | | | | | | | | | | | | | | 2022 | $ | 414 | | | $ | 177 | | | $ | 152 | | | $ | 292 | | | $ | 415 | | | $ | (3) | | | $ | 1,447 | | 2021 | 389 | | | 161 | | | 138 | | | 267 | | | 335 | | | (1) | | | 1,289 | | 2020 | 382 | | | 147 | | | 133 | | | 268 | | | 380 | | | (3) | | | 1,307 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Income taxes: | | | | | | | | | | | | | | 2022 | $ | 264 | | | $ | 79 | | | $ | 8 | | | $ | 9 | | | $ | — | | | $ | (11) | | | $ | 349 | | 2021 | 172 | | | 12 | | | (35) | | | 42 | | | 8 | | | (161) | | | 38 | | 2020 | 177 | | | (30) | | | 41 | | | (77) | | | 35 | | | (153) | | | (7) | | Net income (loss) from continuing operations: | | | | | | | | | | | | | | 2022 | $ | 917 | | | $ | 576 | | | $ | 380 | | | $ | 608 | | | $ | (393) | | | $ | (34) | | | $ | 2,054 | | 2021 | 742 | | | 504 | | | 408 | | | 561 | | | (156) | | | (443) | | | 1,616 | | 2020 | 438 | | | 447 | | | 349 | | | 495 | | | (184) | | | (446) | | | 1,099 | | Capital expenditures: | | | | | | | | | | | | | | 2022 | $ | 2,506 | | | $ | 1,349 | | | $ | 1,262 | | | $ | 1,709 | | | $ | 95 | | | $ | — | | | $ | 6,921 | | 2021 | 2,387 | | | 1,240 | | | 1,226 | | | 1,720 | | | 67 | | | — | | | 6,640 | | 2020 | 2,217 | | | 1,147 | | | 1,247 | | | 1,604 | | | 74 | | | — | | | 6,289 | | Total assets: | | | | | | | | | | | | | | 2022 | $ | 39,661 | | | $ | 14,502 | | | $ | 13,350 | | | $ | 26,082 | | | $ | 6,014 | | | $ | (4,260) | | | $ | 95,349 | | 2021 | 36,470 | | | 13,824 | | | 12,324 | | | 24,744 | | | 7,626 | | | (8,319) | | | 86,669 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 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 |
|
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 5 — Segment Information
__________
(a)Other primarily includes Exelon’s corporate operations, shared service entities, and other financing and investment activities. (b)Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 22 — Supplemental Financial Information for additional information on total utility taxes. (c)See Note 23 — Related Party Transactions for additional information on intersegment revenues. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 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
PHI:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 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 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Pepco | | DPL | | ACE | | Other(a) | | Intersegment Eliminations | | PHI | Operating revenues(b): | | | | | | | | | | | | 2022 | | | | | | | | | | | | Electric revenues | $ | 2,531 | | | $ | 1,357 | | | $ | 1,431 | | | $ | — | | | $ | (2) | | | $ | 5,317 | | Natural gas revenues | — | | | 238 | | | — | | | — | | | — | | | 238 | | Shared service and other revenues | — | | | — | | | — | | | 391 | | | (381) | | | 10 | | Total operating revenues | $ | 2,531 | | | $ | 1,595 | | | $ | 1,431 | | | $ | 391 | | | $ | (383) | | | $ | 5,565 | | 2021 | | | | | | | | | | | | Electric revenues | $ | 2,274 | | | $ | 1,212 | | | $ | 1,388 | | | $ | — | | | $ | (14) | | | $ | 4,860 | | 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 | | | | | | | | | | | | Electric revenues | $ | 2,149 | | | $ | 1,109 | | | $ | 1,245 | | | $ | — | | | $ | (18) | | | $ | 4,485 | | 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 | | Intersegment revenues(c): | | | | | | | | | | | | 2022 | $ | 5 | | | $ | 6 | | | $ | 2 | | | $ | 380 | | | $ | (383) | | | $ | 10 | | 2021 | 5 | | | 7 | | | 2 | | | 380 | | | (381) | | | 13 | | 2020 | 7 | | | 9 | | | 4 | | | 372 | | | (375) | | | 17 | | Depreciation and amortization: | | | | | | | | | | | | 2022 | $ | 417 | | | $ | 232 | | | $ | 261 | | | $ | 28 | | | $ | — | | | $ | 938 | | 2021 | 403 | | | 210 | | | 179 | | | 29 | | | — | | | 821 | | 2020 | 377 | | | 191 | | | 180 | | | 34 | | | — | | | 782 | | Operating expenses: | | | | | | | | | | | | 2022 | $ | 2,140 | | | $ | 1,359 | | | $ | 1,225 | | | $ | 393 | | | $ | (383) | | | $ | 4,734 | | 2021 | 1,871 | | | 1,161 | | | 1,201 | | | 388 | | | (381) | | | 4,240 | | 2020 | 1,799 | | | 1,120 | | | 1,123 | | | 378 | | | (375) | | | 4,045 | | Interest expense, net: | | | | | | | | | | | | 2022 | $ | 150 | | | $ | 66 | | | $ | 66 | | | $ | 9 | | | $ | 1 | | | $ | 292 | | 2021 | 140 | | | 61 | | | 58 | | | 8 | | | — | | | 267 | | 2020 | 138 | | | 61 | | | 59 | | | 10 | | | — | | | 268 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Income taxes: | | | | | | | | | | | | 2022 | $ | (9) | | | $ | 14 | | | $ | 3 | | | $ | 1 | | | $ | — | | | $ | 9 | | 2021 | 15 | | | 42 | | | (13) | | | (2) | | | — | | | 42 | | 2020 | (7) | | | (25) | | | (41) | | | (4) | | | — | | | (77) | | Net income (loss): | | | | | | | | | | | | 2022 | $ | 305 | | | $ | 169 | | | $ | 148 | | | $ | (14) | | | $ | — | | | $ | 608 | | 2021 | 296 | | | 128 | | | 146 | | | (9) | | | — | | | 561 | | 2020 | 266 | | | 125 | | | 112 | | | (8) | | | — | | | 495 | | Capital expenditures: | | | | | | | | | | | | 2022 | $ | 874 | | | $ | 430 | | | $ | 398 | | | $ | 7 | | | $ | — | | | $ | 1,709 | | 2021 | 843 | | | 429 | | | 445 | | | 3 | | | — | | | 1,720 | | 2020 | 773 | | | 424 | | | 401 | | | 6 | | | — | | | 1,604 | | Total assets: | | | | | | | | | | | | 2022 | $ | 10,657 | | | $ | 5,802 | | | $ | 4,979 | | | $ | 4,677 | | | $ | (33) | | | $ | 26,082 | | 2021 | 9,903 | | | 5,412 | | | 4,556 | | | 4,933 | | | (60) | | | 24,744 | |
__________ | | (a) | See Note 24 (a)Other primarily includes PHI’s corporate operations, shared service entities, and other financing and investment activities.— 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
(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 22 — Supplemental Financial Information for additional information on total utility taxes.
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 |
|
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 | Net income (loss): | | | | | | | | | | |
|
| 2019 | $ | 243 |
| | $ | 147 |
| | $ | 99 |
| | $ | (26 | ) | | $ | 14 |
| | $ | 477 |
| 2018 | 205 |
| | 120 |
| | 75 |
| | (22 | ) | | 15 |
| | $ | 393 |
| 2017 | 198 |
| | 121 |
| | 77 |
| | (91 | ) | | 50 |
| | $ | 355 |
| Capital expenditures: | | | | | | | | | | |
|
| 2019 | $ | 626 |
| | $ | 348 |
| | $ | 375 |
| | $ | 6 |
| | $ | — |
| | $ | 1,355 |
| 2018 | 656 |
| | 364 |
| | 335 |
| | 20 |
| | — |
| | $ | 1,375 |
| 2017 | 628 |
| | 428 |
| | 312 |
| | 28 |
| | — |
| | 1,396 |
| 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 |
|
__________
| | (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. |
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 5 — Segment Information
The following tables disaggregate the Registrants' revenuerevenues recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. For Generation, the disaggregation of revenues reflects Generation's two primary products of power sales and natural gas sales, with further disaggregation of power sales provided by geographic region. For the Utility Registrants, the disaggregation of revenues reflects the two primary utility services of rate-regulated 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): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2022 | | | | | | | | | | | | | | | Revenues from contracts with customers | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Electric revenues | | | | | | | | | | | | | | Residential | $ | 3,304 | | | $ | 2,026 | | | $ | 1,564 | | | $ | 2,590 | | | $ | 1,076 | | | $ | 750 | | | $ | 764 | | Small commercial & industrial | 1,173 | | | 521 | | | 327 | | | 607 | | | 155 | | | 235 | | | 217 | | Large commercial & industrial | 5 | | | 299 | | | 567 | | | 1,422 | | | 1,083 | | | 137 | | | 202 | | Public authorities & electric railroads | 29 | | | 30 | | | 27 | | | 64 | | | 34 | | | 15 | | | 15 | | Other(a) | 955 | | | 271 | | | 398 | | | 695 | | | 208 | | | 227 | | | 252 | | Total electric revenues(b) | $ | 5,466 | | | $ | 3,147 | | | $ | 2,883 | | | $ | 5,378 | | | $ | 2,556 | | | $ | 1,364 | | | $ | 1,450 | | Natural gas revenues | | | | | | | | | | | | | | Residential | $ | — | | | $ | 512 | | | $ | 678 | | | $ | 127 | | | $ | — | | | $ | 127 | | | $ | — | | Small commercial & industrial | — | | | 186 | | | 111 | | | 55 | | | — | | | 55 | | | — | | Large commercial & industrial | — | | | — | | | 183 | | | 12 | | | — | | | 12 | | | — | | Transportation | — | | | 26 | | | — | | | 15 | | | — | | | 15 | | | — | | Other(c) | — | | | 12 | | | 68 | | | 29 | | | — | | | 29 | | | — | | Total natural gas revenues(d) | $ | — | | | $ | 736 | | | $ | 1,040 | | | $ | 238 | | | $ | — | | | $ | 238 | | | $ | — | | Total revenues from contracts with customers | $ | 5,466 | | | $ | 3,883 | | | $ | 3,923 | | | $ | 5,616 | | | $ | 2,556 | | | $ | 1,602 | | | $ | 1,450 | | Other revenues | | | | | | | | | | | | | | Revenues from alternative revenue programs | $ | 267 | | | $ | 2 | | | $ | (47) | | | $ | (59) | | | $ | (31) | | | $ | (9) | | | $ | (19) | | Other electric revenues(e) | 28 | | | 16 | | | 14 | | | 8 | | | 6 | | | 2 | | | — | | Other natural gas revenues(e) | — | | | 2 | | | 5 | | | — | | | — | | | — | | | — | | | | | | | | | | | | | | | | Total other revenues | $ | 295 | | | $ | 20 | | | $ | (28) | | | $ | (51) | | | $ | (25) | | | $ | (7) | | | $ | (19) | | Total revenues for reportable segments | $ | 5,761 | | | $ | 3,903 | | | $ | 3,895 | | | $ | 5,565 | | | $ | 2,531 | | | $ | 1,595 | | | $ | 1,431 | |
| | | | | | | | | | | | | | | | | | | | | | 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 |
|
196 | | | | | | | | | | | | | | | | | | | | | | 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 |
|
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 5 — Segment Information
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2021 | | | | | | | | | | | | | | | Revenues from contracts with customers | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | 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 electric revenues(b) | $ | 6,334 | | | $ | 2,629 | | | $ | 2,499 | | | $ | 4,777 | | | $ | 2,218 | | | $ | 1,196 | | | $ | 1,364 | | 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 natural gas revenues(d) | $ | — | | | $ | 539 | | | $ | 816 | | | $ | 168 | | | $ | — | | | $ | 168 | | | $ | — | | Total 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 electric revenues(e) | 30 | | | 4 | | | 11 | | | 5 | | | 3 | | | 2 | | | — | | Other natural gas revenues(e) | — | | | — | | | 3 | | | — | | | — | | | — | | | — | | | | | | | | | | | | | | | | Total other revenues | $ | 72 | | | $ | 30 | | | $ | 26 | | | $ | 96 | | | $ | 56 | | | $ | 16 | | | $ | 24 | | Total revenues for reportable segments | $ | 6,406 | | | $ | 3,198 | | | $ | 3,341 | | | $ | 5,041 | | | $ | 2,274 | | | $ | 1,380 | | | $ | 1,388 | |
| | | | | | | | | | | | | | | | | | | | | | 2017 | | Revenues from external customers(a) | | | | | | Contracts with customers | | Other(b) | | Total | | Intersegment Revenues | | Total Revenues | Mid-Atlantic | $ | 5,523 |
| | $ | (8 | ) | | $ | 5,515 |
| | $ | 25 |
| | $ | 5,540 |
| Midwest | 3,923 |
| | 283 |
| | 4,206 |
| | (25 | ) | | 4,181 |
| New York | 1,605 |
| | (38 | ) | | 1,567 |
| | (17 | ) | | 1,550 |
| ERCOT | 641 |
| | 317 |
| | 958 |
| | 4 |
| | 962 |
| Other Power Regions | 2,658 |
| | 428 |
| | 3,086 |
| | (35 | ) | | 3,051 |
| Total Competitive Businesses Electric Revenues | 14,350 |
| | 982 |
| | 15,332 |
| | (48 | ) | | 15,284 |
| Competitive Businesses Natural Gas Revenues | 1,658 |
| | 917 |
| | 2,575 |
| | 53 |
| | 2,628 |
| Competitive Businesses Other Revenues(c) | 744 |
| | (151 | ) | | 593 |
| | (5 | ) | | 588 |
| Total Generation Consolidated Operating Revenues | $ | 16,752 |
| | $ | 1,748 |
| | $ | 18,500 |
| | $ | — |
| | $ | 18,500 |
|
__________
| | (a) | Includes all wholesale and retail electric sales to third parties and affiliated sales to the Utility Registrants. |
| | (b) | Includes revenues from derivatives and leases. |
| | (c) | Other represents activities not allocated to a region. See text above for a description of included activities. Includes 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 power and fuel expense (Generation):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2020 | Revenues from contracts with customers | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | 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 electric revenues(b) | $ | 5,933 | | | $ | 2,524 | | | $ | 2,328 | | | $ | 4,478 | | | $ | 2,108 | | | $ | 1,115 | | | $ | 1,257 | | 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 natural gas revenues(d) | $ | — | | | $ | 515 | | | $ | 747 | | | $ | 162 | | | $ | — | | | $ | 162 | | | $ | — | | Total 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 electric revenues(e) | 18 | | | 3 | | | 5 | | | 2 | | | 1 | | | 1 | | | — | | Other natural gas revenues(e) | — | | | — | | | 2 | | | — | | | — | | | — | | | — | | | | | | | | | | | | | | | | Total other revenues | $ | (29) | | | $ | 19 | | | $ | 23 | | | $ | 23 | | | $ | 41 | | | $ | (6) | | | $ | (12) | | Total revenues for reportable segments | $ | 5,904 | | | $ | 3,058 | | | $ | 3,098 | | | $ | 4,663 | | | $ | 2,149 | | | $ | 1,271 | | | $ | 1,245 | |
Electric__________
(a)Includes revenues from transmission revenue from PJM, wholesale electric revenue and Gas Revenue by Customer Class (Utility Registrants):mutual assistance revenue. (b)Includes operating revenues from affiliates in 2022, 2021, and 2020 respectively of: •$16 million, $41 million, and $37 million at ComEd •$7 million, $20 million, and $8 million at PECO •$7 million, $13 million, and $10 million at BGE •$10 million, $13 million, and $17 million at PHI •$5 million, $5 million, and $7 million at Pepco •$6 million, $7 million, and $9 million at DPL •$2 million, $2 million, and $4 million at ACE (c)Includes revenues from off-system natural gas sales. (d)Includes operating revenues from affiliates in 2022, 2021, and 2020 respectively of: •less than $1 million, $1 million, and $1 million at PECO •$8 million, $18 million, and $10 million at BGE (e)Includes late payment charge revenues.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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 |
|
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 56 — Segment InformationAccounts Receivable
6. Accounts Receivable (All Registrants)
Allowance for Credit Losses on Accounts Receivable The following tables present the rollforward of Allowance for Credit Losses on Customer Accounts Receivable. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, 2022 | | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Balance as of December 31, 2021 | $ | 320 | | | $ | 73 | | | $ | 105 | | | $ | 38 | | | $ | 104 | | | $ | 37 | | | $ | 18 | | | $ | 49 | | Plus: Current period provision for expected credit losses(a)(b) | 176 | | | 29 | | | 52 | | | 37 | | | 58 | | | 31 | | | 12 | | | 15 | | Less: Write-offs, net(c)(d)(e) of recoveries(f) | 169 | | | 43 | | | 52 | | | 21 | | | 53 | | | 21 | | | 9 | | | 23 | | | | | | | | | | | | | | | | | | Balance as of December 31, 2022 | $ | 327 | | | $ | 59 | | | $ | 105 | | | $ | 54 | | | $ | 109 | | | $ | 47 | | | $ | 21 | | | $ | 41 | | | | | | | | | | | | | | | | | | | Year Ended December 31, 2021 | | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Balance as of December 31, 2020 | $ | 334 | | | $ | 97 | | | $ | 116 | | | $ | 35 | | | $ | 86 | | | $ | 32 | | | $ | 22 | | | $ | 32 | | Plus: Current period provision for expected credit losses | 96 | | | 21 | | | 23 | | | 15 | | | 37 | | | 13 | | | 6 | | | 18 | | Less: Write-offs, net of recoveries | 110 | | | 45 | | | 34 | | | 12 | | | 19 | | | 8 | | | 10 | | | 1 | | Balance as of December 31, 2021 | $ | 320 | | | $ | 73 | | | $ | 105 | | | $ | 38 | | | $ | 104 | | | $ | 37 | | | $ | 18 | | | $ | 49 | |
_________ (a)For PECO, BGE, Pepco and DPL, the change in current period provision for expected credit losses is primarily a result of increased receivable balances. (b)For ACE, the change in current period provision for expected credit losses is primarily a result of decreased receivable balances. (c)For PECO, the change in write-offs is primarily a result of increased disconnection activities. (d)For PHI, Pepco and ACE, the change in write-offs is primarily related to the termination of the moratoriums in the District of Columbia and New Jersey, which beginning in March 2020, prevented customer disconnections for non-payment. With disconnection activities restarting in January 2022, write-offs of aging accounts receivable increased during the year. (e)For DPL, the change in write-offs is primarily a result of favorable customer payment behavior. (f)Recoveries were not material to the Registrants. The following tables present the rollforward of Allowance for Credit Losses on Other Accounts Receivable. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, 2022 | | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Balance as of December 31, 2021 | $ | 72 | | | $ | 17 | | | $ | 7 | | | $ | 9 | | | $ | 39 | | | $ | 16 | | | $ | 8 | | | $ | 15 | | Plus: Current period provision (benefit) for expected credit losses | 26 | | | 3 | | | 6 | | | 6 | | | 11 | | | 9 | | | (1) | | | 3 | | Less: Write-offs, net of recoveries(a) | 16 | | | 3 | | | 4 | | | 5 | | | 4 | | | — | | | — | | | 4 | | Balance as of December 31, 2022 | $ | 82 | | | $ | 17 | | | $ | 9 | | | $ | 10 | | | $ | 46 | | | $ | 25 | | | $ | 7 | | | $ | 14 | | | | | | | | | | | | | | | | | | | 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 (benefit) for expected credit losses | 11 | | | (2) | | | 3 | | | 4 | | | 6 | | | 3 | | | (1) | | | 4 | | Less: Write-offs, net of recoveries | 10 | | | 2 | | | 4 | | | 4 | | | — | | | — | | | — | | | — | | Balance as of December 31, 2021 | $ | 72 | | | $ | 17 | | | $ | 7 | | | $ | 9 | | | $ | 39 | | | $ | 16 | | | $ | 8 | | | $ | 15 | |
_________ 199 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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 56 — Segment InformationAccounts Receivable (a)Recoveries were not material to the Registrants. Unbilled Customer Revenue The following table provides additional information about unbilled customer revenues recorded in the Registrants' Consolidated Balance Sheets as of December 31, 2022 and 2021. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Unbilled customer revenues(a) | | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | December 31, 2022 | $ | 912 | | | $ | 223 | | | $ | 219 | | | $ | 247 | | | $ | 223 | | | $ | 103 | | | $ | 74 | | | $ | 46 | | December 31, 2021 | 747 | | | 240 | | | 161 | | | 171 | | | 175 | | | 82 | | | 53 | | | 40 | |
_________ (a)Unbilled customer revenues are classified in Customer accounts receivables, net in the Registrants' Consolidated Balance Sheets. Other Purchases of Customer and Other Accounts Receivables 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. The following tables present the total receivables purchased. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total receivables purchased | | Exelon(a) | | ComEd(a) | | PECO(a) | | BGE(a) | | PHI | | Pepco | | DPL | | ACE | Year ended December 31, 2022 | $ | 3,981 | | | $ | 965 | | | $ | 1,081 | | | $ | 792 | | | $ | 1,143 | | | $ | 723 | | | $ | 205 | | | $ | 215 | | Year ended December 31, 2021 | $ | 3,840 | | | $ | 1,031 | | | $ | 1,041 | | | $ | 687 | | | $ | 1,081 | | | $ | 660 | | | $ | 217 | | | $ | 204 | | _________(a)For BGE, includes $4 million of receivables purchased from Generation prior to the separation on February 1, 2022 for the year ended December 31, 2022. For ComEd, PECO, and BGE, includes $1 million, $1 million, and $21 million of receivables purchased from Generation, respectively, for the year ended December 31, 2021.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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 6 — Early Plant Retirements
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 2015 and 2016, Generation identified the Clinton and Quad Cities nuclear plants in Illinois, Ginna and Nine Mile Point nuclear plants in New York 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 Jersey nuclear plants, including Salem, of which Generation owns a 42.59% ownership interest. PSEG is the operator of Salem and also has the decision-making authority to retire Salem.
Assuming the continued effectiveness of the Illinois ZES, New Jersey ZEC program and the New York CES, Generation and CENG, 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. See Note 3 — Regulatory Matters for additional information on the Illinois ZES, New Jersey ZEC program, New York CES and FERC's December 19, 2019 order.
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, Generation permanently ceased generation operations at TMI.
On February 2, 2018, Generation announced that it would permanently cease generation operations at the Oyster Creek nuclear plant at the end of its current operating cycle and permanently ceased generation operations on September 17, 2018.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 6 — Early Plant Retirements
As a result of these early nuclear plant retirement decisions, Exelon and Generation recognized incremental non-cash charges to earnings stemming from shortening the expected economic useful lives primarily related to accelerated depreciation of plant assets (including any ARC) and accelerated amortization of nuclear fuel, as well as operating 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 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.
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 end 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.
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. Property, Plant, and Equipment (All Registrants) The following tables present a summary of property, plant, and equipment by asset category as of December 31, 20192022 and 2018:2021: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Asset Category | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | December 31, 2019 | | | | | | | | | | | | | | | | | | Electric—transmission and distribution | $ | 56,809 |
| | $ | — |
| | $ | 27,566 |
| | $ | 8,957 |
| | $ | 8,326 |
| | $ | 13,809 |
| | $ | 9,734 |
| | $ | 4,464 |
| | $ | 4,207 |
| Electric—generation | 29,839 |
| | 29,839 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Gas—transportation and distribution | 6,147 |
| | — |
| | — |
| | 2,899 |
| | 2,999 |
| | 525 |
| | — |
| | 690 |
| | — |
| Common—electric and gas | 1,907 |
| | — |
| | — |
| | 877 |
| | 991 |
| | 146 |
| | — |
| | 160 |
| | — |
| Nuclear fuel(a) | 5,656 |
| | 5,656 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Construction work in progress | 3,055 |
| | 702 |
| | 662 |
| | 250 |
| | 483 |
| | 921 |
| | 628 |
| | 125 |
| | 166 |
| 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 |
| | | | | | | | | | | | | | | | | | | December 31, 2018 | | | | | | | | | | | | | | | | | | Electric—transmission and distribution | $ | 53,090 |
| | $ | — |
| | $ | 25,991 |
| | $ | 8,359 |
| | $ | 7,951 |
| | $ | 12,664 |
| | $ | 9,217 |
| | $ | 4,195 |
| | $ | 3,866 |
| Electric—generation | 29,170 |
| | 29,170 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Gas—transportation and distribution | 5,530 |
| | — |
| | — |
| | 2,694 |
| | 2,630 |
| | 486 |
| | — |
| | 651 |
| | — |
| Common—electric and gas | 1,627 |
| | — |
| | — |
| | 756 |
| | 860 |
| | 126 |
| | — |
| | 136 |
| | — |
| Nuclear fuel(a) | 5,957 |
| | 5,957 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Construction work in progress | 3,377 |
| | 997 |
| | 705 |
| | 343 |
| | 410 |
| | 912 |
| | 536 |
| | 151 |
| | 209 |
| Other property, plant and equipment(b) | 858 |
| | 63 |
| | 46 |
| | 19 |
| | 25 |
| | 99 |
| | 61 |
| | 17 |
| | 28 |
| Total property, plant and equipment | 99,609 |
| | 36,187 |
| | 26,742 |
| | 12,171 |
| | 11,876 |
| | 14,287 |
| | 9,814 |
| | 5,150 |
| | 4,103 |
| 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 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Asset Category | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | December 31, 2022 | | | | | | | | | | | | | | | | Electric—transmission and distribution | $ | 69,034 | | | $ | 32,906 | | | $ | 10,719 | | | $ | 9,993 | | | $ | 17,165 | | | $ | 11,270 | | | $ | 5,231 | | | $ | 5,219 | | Gas—transportation and distribution | 8,126 | | | — | | | 3,619 | | | 4,074 | | | 696 | | | — | | | 855 | | | — | | Common—electric and gas | 2,521 | | | — | | | 1,071 | | | 1,317 | | | 228 | | | — | | | 206 | | | — | | Construction work in progress | 4,534 | | | 1,174 | | | 744 | | | 487 | | | 2,101 | | | 1,526 | | | 271 | | | 296 | | Other property, plant, and equipment(a) | 791 | | | 106 | | | 50 | | | 50 | | | 114 | | | 65 | | | 29 | | | 26 | | Total property, plant, and equipment | 85,006 | | | 34,186 | | | 16,203 | | | 15,921 | | | 20,304 | | | 12,861 | | | 6,592 | | | 5,541 | | Less: accumulated depreciation | 15,930 | | | 6,673 | | | 4,078 | | | 4,583 | | | 2,618 | | | 4,067 | | | 1,772 | | | 1,551 | | Property, plant, and equipment, net | $ | 69,076 | | | $ | 27,513 | | | $ | 12,125 | | | $ | 11,338 | | | $ | 17,686 | | | $ | 8,794 | | | $ | 4,820 | | | $ | 3,990 | | | | | | | | | | | | | | | | | | December 31, 2021 | | | | | | | | | | | | | | | | Electric—transmission and distribution | $ | 64,771 | | | $ | 31,077 | | | $ | 10,076 | | | $ | 9,352 | | | $ | 16,062 | | | $ | 10,798 | | | $ | 4,957 | | | $ | 4,882 | | Gas—transportation and distribution | 7,429 | | | — | | | 3,339 | | | 3,712 | | | 646 | | | — | | | 806 | | | — | | Common—electric and gas | 2,335 | | | — | | | 1,005 | | | 1,224 | | | 201 | | | — | | | 180 | | | — | | Construction work in progress | 3,698 | | | 918 | | | 620 | | | 554 | | | 1,590 | | | 1,118 | | | 229 | | | 242 | | Other property, plant and equipment(a) | 755 | | | 99 | | | 41 | | | 34 | | | 107 | | | 63 | | | 23 | | | 25 | | Total property, plant and equipment | 78,988 | | | 32,094 | | | 15,081 | | | 14,876 | | | 18,606 | | | 11,979 | | | 6,195 | | | 5,149 | | Less: accumulated depreciation | 14,430 | | | 6,099 | | | 3,964 | | | 4,299 | | | 2,108 | | | 3,875 | | | 1,635 | | | 1,420 | | Property, plant, and equipment, net | $ | 64,558 | | | $ | 25,995 | | | $ | 11,117 | | | $ | 10,577 | | | $ | 16,498 | | | $ | 8,104 | | | $ | 4,560 | | | $ | 3,729 | |
__________ | | (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)Primarily composed of land and non-utility property.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 7 — 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 | | GenerationComEd | | ComEdPECO | | PECOBGE | | BGEPHI | | PHIPepco | | PepcoDPL | | DPL | | ACE | Electric - transmission and distribution | 5-80 | | N/A5-80 | | 5-805-70 | | 5-655-80 | | 5-75 | | 5-75 | | 5-75 | | 5-70 | | 5-655-75 | Electric - generation | 1-56 | | 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 | 1-504-61 | | 1-1031-50 | | 34-5050 | | 5020-50 | | 20-5010-43 | | 3-5010-33 | | 33-5010-43 | | 8-50 | | 13-15 |
Depreciation provisions are based on the estimated useful lives of the stations, which reflect the first renewal of the operating licenses 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 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 Creek depreciation provisions were based on their 2019 expected shutdown dates. Beginning February 2018, Oyster Creek depreciation provisions were based on its announced shutdown date of September 2018. See Note 3 — Regulatory Matters for additional information regarding license renewals and the Illinois ZECs and Note 6 — Early Plant Retirements for additional information on the impacts of early plant retirements.
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 | | 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 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Annual Depreciation Rates | | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | December 31, 2022 | | | | | | | | | | | | | | | | Electric—transmission and distribution | 2.87% | | 3.00% | | 2.29% | | 2.82% | | 2.96% | | 2.58% | | 3.08% | | 3.38% | Gas—transportation and distribution | 2.14% | | N/A | | 1.87% | | 2.53% | | 1.45% | | N/A | | 1.45% | | N/A | Common—electric and gas | 7.54% | | N/A | | 6.31% | | 8.20% | | 8.96% | | N/A | | 10.03% | | N/A | | | | | | | | | | | | | | | | | December 31, 2021 | | | | | | | | | | | | | | | | Electric—transmission and distribution | 2.81% | | 2.94% | | 2.28% | | 2.80% | | 2.87% | | 2.56% | | 2.86% | | 3.21% | 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% | 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 |
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 7 — 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, 2022 | | | | | | | | | | | | | | | | AFUDC debt and equity | $ | 215 | | | $ | 54 | | | $ | 42 | | | $ | 29 | | | $ | 90 | | | $ | 69 | | | $ | 10 | | | $ | 11 | | | | | | | | | | | | | | | | | | December 31, 2021 | | | | | | | | | | | | | | | | AFUDC debt and equity | $ | 189 | | | $ | 47 | | | $ | 34 | | | $ | 36 | | | $ | 72 | | | $ | 59 | | | $ | 8 | | | $ | 5 | | | | | | | | | | | | | | | | | | December 31, 2020 | | | | | | | | | | | | | | | | AFUDC debt and equity | $ | 150 | | | $ | 42 | | | $ | 23 | | | $ | 30 | | | $ | 55 | | | $ | 42 | | | $ | 6 | | | $ | 7 | |
See Note 1 — Significant Accounting Policies for additional information regarding property, plant and equipment policies. See Note 16 — 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.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 8 — Jointly Owned Electric Utility Plant 8. Jointly Owned Electric Utility Plant (Exelon, Generation, PECO, PHI, 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, 20192022 and 20182021 were as follows:
| | | | | | | | | | | | | | | | | | | | | | Nuclear Generation | | Transmission | | Quad Cities | | Peach Bottom | | Salem | | Nine Mile Point Unit 2 | | NJ/DE(a) | Operator | Generation | | Generation | | PSEG Nuclear | | Generation | | PSEG/DPL | Ownership interest | 75.00 | % | | 50.00 | % | | 42.59 | % | | 82.00 | % | | various |
| Exelon’s share at December 31, 2019: | | | | | | | | | | Plant in service | $ | 1,161 |
| | $ | 1,466 |
| | $ | 663 |
| | $ | 951 |
| | $ | 102 |
| Accumulated depreciation | 627 |
| | 571 |
| | 249 |
| | 156 |
| | 53 |
| Construction work in progress | 13 |
| | 21 |
| | 53 |
| | 27 |
| | — |
| Exelon’s share at December 31, 2018: | | | | | | | | | | Plant in service | $ | 1,131 |
| | $ | 1,451 |
| | $ | 648 |
| | $ | 910 |
| | $ | 103 |
| Accumulated depreciation | 587 |
| | 523 |
| | 227 |
| | 126 |
| | 53 |
| Construction work in progress | 13 |
| | 15 |
| | 44 |
| | 56 |
| | — |
|
__________
| | | | | | (a) | PECO, Transmission | | NJ/DE(a) | Operator | PSEG/DPL and ACE own a 42.55%, 1% and 13.9% | Ownership interest | various | Exelon’s share respectivelyas of December 31, 2022: | | Plant in 151.3 milesservice | $ | 103 | | Accumulated depreciation | 56 | | Exelon’s share as of 500kV lines locatedDecember 31, 2021: | | Plant 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.service | $ | 103 | | Accumulated depreciation | 55 | |
Exelon’s, Generation’s, __________
(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 in 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. 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 inExelon's, 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 9 — Asset Retirement Obligations
9. Asset Retirement Obligations (All Registrants) Nuclear Decommissioning Asset Retirement Obligations (Exelon and Generation)
Generation has a legal obligation to decommission its nuclear power plants following the expiration of their operating licenses. To estimate its decommissioning obligation related to its nuclear generating stations for financial accounting and reporting purposes, Generation uses a probability-weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on decommissioning cost studies, cost escalation rates, probabilistic cash flow models and discount rates. Generation updates its ARO annually unless circumstances warrant more frequent 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 within Property, plant and equipment on Exelon’s and Generation’s Consolidated Balance Sheets. If the ARO decreases for a Non-Regulatory Agreement unit without any remaining ARC, the corresponding change is recorded as decrease in Operating and maintenance expense within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. The following table provides a rollforward of the nuclear decommissioning ARO reflected in Exelon’s and Generation’s Consolidated Balance Sheets, from January 1, 2018 to December 31, 2019:
| | | | | 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 million as the current portion of the ARO at December 31, 2019 and 2018, respectively, which is included in Other current liabilities in Exelon’s and Generation’s Consolidated Balance Sheets. |
| | (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. |
The net $864 million increase in the ARO during 2019 for changes in the amounts and timing of estimated decommissioning cash flows was driven by multiple adjustments throughout the year, some with offsetting impacts. These adjustments primarily include:
An increase of approximately $780 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, and current discount rates; partially offset by
Lower estimated costs to decommission TMI, Nine Mile Point, Ginna, Braidwood, Byron and LaSalle nuclear units of approximately $410 million resulting from the completion of updated cost studies.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 9 — 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 million decrease in the ARO during 2018 for changes in the amounts and timing of estimated decommissioning cash flows was driven by multiple adjustments throughout the year, some with offsetting impacts. These adjustments primarily include:
A decrease of approximately $205 million primarily due to lower estimated 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 changes in decommissioning scenarios and their probabilities. These decreases were partially offset by
An increase of approximately $115 million for the impact of the early retirement and the announced pending sale of Oyster Creek which closed on July 1, 2019; and
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 unit to satisfy Generation’s nuclear decommissioning obligations. 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, for decommissioning the former PECO nuclear plants through regulated rates, and these collections are scheduled through the operating lives of the 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. 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 ultimately 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, where any shortfall is required to be funded by both Generation and EDF. Generation, through PECO, has recourse to collect additional amounts from PECO customers related to a shortfall of NDT funds for the former PECO 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 collect 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 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 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 or 50% of any excess funds in the trust funds above the amounts required for decommissioning (including spent fuel management and decommissioning) 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. Generation expects to comply with applicable regulations and timely commence and complete all required decommissioning activities.
At December 31, 2019 and 2018, Exelon and Generation had NDT funds totaling $13,353 millionand $12,695 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 funds include $163 million and $144 million for the current portion of the NDT at December 31, 2019 and 2018, respectively, which are included in Other current assets in Exelon's and Generation's Consolidated Balance Sheets. See Note 23 — 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 and accretion of the decommissioning obligation, are generally offset within 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 as long as the NDT funds are expected to exceed the total estimated decommissioning obligation. For the former PECO units, decommissioning-related activities are generally offset within 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 within the Consolidated Statement of Operations and Comprehensive Income results in an equal adjustment to the noncurrent payables to affiliates at Generation. ComEd and PECO have recorded an equal noncurrent affiliate receivable from Generation and corresponding regulatory liability.
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. As of December 31, 2019, the NDT funds of each of the former 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 used in the NRC minimum funding obligation filings based on NRC guidelines.
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.
The decommissioning-related activities related to the Non-Regulatory Agreement Units are reflected in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.
See Note 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.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 9 — Asset Retirement Obligations
Zion Station Decommissioning
In 2010, Generation completed an Asset Sale Agreement (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 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 as 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 completion 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 from the ARO recorded in Generation’s 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 basis 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 that 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)
Generation has AROs for 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, 2020 to December 31, 2019:2022: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | AROs as of December 31, 2020 | $ | 249 | | | $ | 129 | | | $ | 29 | | | $ | 23 | | | $ | 59 | | | $ | 39 | | | $ | 14 | | | $ | 6 | | Net increase due to changes in, and timing of, estimated future cash flows | 26 | | | 15 | | | — | | | 2 | | | 10 | | | 5 | | | 2 | | | 3 | | | | | | | | | | | | | | | | | | Accretion expense(a) | 7 | | | 4 | | | 1 | | | 1 | | | 1 | | | 1 | | | — | | | — | | | | | | | | | | | | | | | | | | Payments | (8) | | | (2) | | | (1) | | | — | | | — | | | — | | | — | | | — | | AROs as of December 31, 2021 | 274 | | | 146 | | | 29 | | | 26 | | | 70 | | | 45 | | | 16 | | | 9 | | Net (decrease) increase due to changes in, and timing of, estimated future cash flows | (8) | | | 2 | | | (1) | | | 3 | | | (13) | | | (8) | | | (3) | | | (2) | | | | | | | | | | | | | | | | | | Accretion expense(a) | 8 | | | 4 | | | 1 | | | 1 | | | 2 | | | 2 | | | — | | | — | | | | | | | | | | | | | | | | | | Payments | (3) | | | (2) | | | (1) | | | — | | | — | | | — | | | — | | | — | | AROs as of December 31, 2022 | $ | 271 | | | $ | 150 | | | $ | 28 | | | $ | 30 | | | $ | 59 | | | $ | 39 | | | $ | 13 | | | $ | 7 | |
__________ (a)For ComEd, PECO, BGE, PHI, DPL and ACE, the majority of the accretion is recorded as an increase to a regulatory asset due to the associated regulatory treatment. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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 ObligationsLeases
__________
| | (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. 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, 2022. Exelon, ComEd, PECO, and BGE did not have material finance leases. leases in 2022, 2021, or in 2020. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exelon | | GenerationComEd | | ComEdPECO | | PECOBGE | | BGEPHI | | PHIPepco | | PepcoDPL | | DPL | | ACE | Contracted generationReal estate | ● | | ● | | ● | | ● | | ● | | ● | | ● | | | | ● | 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 | 1-83 | | 1-3 | | 1-11 | | 1-83 | | 1-9 | | 1-9 | | 1-9 | | 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 | 3-30 | | N/A | | 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 | 1-10 | | 1 | | N/A | | N/A | | N/A | | N/A | | N/A | | N/A |
The components of operating lease costs for the year ended December 31, 2019 were as follows: | | | | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | For the year ended December 31, 2022 | | For the year ended December 31, 2022 | | | | | | | | | | | | | | | | Operating lease costs | | Operating lease costs | $ | 66 | | | $ | 2 | | | $ | — | | | $ | 15 | | | $ | 42 | | | $ | 10 | | | $ | 12 | | | $ | 6 | | Variable lease costs | | Variable lease costs | 8 | | | 1 | | | — | | | — | | | 2 | | | 1 | | | 1 | | | 1 | | | | | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | | | Total lease costs(a) | | Total lease costs(a) | $ | 74 | | | $ | 3 | | | $ | — | | | $ | 15 | | | $ | 44 | | | $ | 11 | | | $ | 13 | | | $ | 7 | | | For the year ended December 31, 2021 | | For the year ended December 31, 2021 | | Operating lease costs | $ | 320 |
| | $ | 222 |
| | $ | 3 |
| | $ | 1 |
| | $ | 33 |
| | $ | 48 |
| | $ | 12 |
| | $ | 14 |
| | $ | 7 |
| Operating lease costs | $ | 84 | | | $ | 3 | | | $ | — | | | $ | 30 | | | $ | 43 | | | $ | 10 | | | $ | 12 | | | $ | 6 | | Variable lease costs | 300 |
| | 282 |
| | 2 |
| | — |
| | 2 |
| | 6 |
| | 2 |
| | 2 |
| | 1 |
| Variable lease costs | 7 | | | 1 | | | — | | | 1 | | | 1 | | | — | | | — | | | — | | Short-term lease costs | 19 |
| | 19 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | Total lease costs (a) | $ | 639 |
| | $ | 523 |
| | $ | 5 |
| | $ | 1 |
| | $ | 35 |
| | $ | 54 |
| | $ | 14 |
| | $ | 16 |
| | $ | 8 |
| Total lease costs(a) | $ | 91 | | | $ | 4 | | | $ | — | | | $ | 31 | | | $ | 44 | | | $ | 10 | | | $ | 12 | | | $ | 6 | | | For the year ended December 31, 2020 | | For the year ended December 31, 2020 | | Operating lease costs | | Operating lease costs | $ | 98 | | | $ | 3 | | | $ | 1 | | | $ | 33 | | | $ | 46 | | | $ | 11 | | | $ | 13 | | | $ | 6 | | Variable lease costs | | Variable lease costs | 7 | | | 1 | | | — | | | 1 | | | 2 | | | 1 | | | 1 | | | — | | Total lease costs(a) | | Total lease costs(a) | $ | 105 | | | $ | 4 | | | $ | 1 | | | $ | 34 | | | $ | 48 | | | $ | 12 | | | $ | 14 | | | $ | 6 | |
__________ | | (a) | Excludes $51(a)Excludes sublease income recorded at Exelon, PHI, and DPL of $4 million, $4 million, and $4 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 guidance for the years ended December 31, 20182022, 2021, and 2017:2020, respectively.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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 10 — Leases
The components of financing lease costs were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | PHI | | Pepco | | DPL | | ACE | For the year ended December 31, 2022 | | | | | | | | | | | | | | | | Amortization of ROU asset | | | | | | | | | $ | 14 | | | $ | 5 | | | $ | 6 | | | $ | 3 | | Interest on lease liabilities | | | | | | | | | 4 | | | 1 | | | 2 | | | 1 | | Total finance lease cost | | | | | | | | | $ | 18 | | | $ | 6 | | | $ | 8 | | | $ | 4 | | | | | | | | | | | | | | | | | | For the year ended December 31, 2021 | | | | | | | | | | | | | | | | Amortization of ROU asset | | | | | | | | | $ | 11 | | | $ | 4 | | | $ | 4 | | | $ | 3 | | Interest on lease liabilities | | | | | | | | | 2 | | | 1 | | | 1 | | | — | | Total finance lease cost | | | | | | | | | $ | 13 | | | $ | 5 | | | $ | 5 | | | $ | 3 | | | | | | | | | | | | | | | | | | For the year ended December 31, 2020 | | | | | | | | | | | | | | | | Amortization of ROU asset | | | | | | | | | $ | 7 | | | $ | 3 | | | $ | 3 | | | $ | 2 | | Interest on lease liabilities | | | | | | | | | 2 | | | — | | | 1 | | | — | | Total finance lease cost | | | | | | | | | $ | 9 | | | $ | 3 | | | $ | 4 | | | $ | 2 | |
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 Sheets 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 $664 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:Sheets:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Operating Leases | | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | As of December 31, 2022 | | | | | | | | | | | | | | | | Operating lease ROU assets | | | | | | | | | | | | | | | | Other deferred debits and other assets | $ | 265 | | | $ | 2 | | | $ | 1 | | | $ | 2 | | | $ | 180 | | | $ | 36 | | | $ | 39 | | | $ | 9 | | | | | | | | | | | | | | | | | | Operating lease liabilities | | | | | | | | | | | | | | | | Other current liabilities | 40 | | | 2 | | | — | | | — | | | 31 | | | 6 | | | 8 | | | 3 | | Other deferred credits and other liabilities | 266 | | | — | | | 1 | | | 4 | | | 167 | | | 34 | | | 42 | | | 7 | | Total operating lease liabilities | $ | 306 | | | $ | 2 | | | $ | 1 | | | $ | 4 | | | $ | 198 | | | $ | 40 | | | $ | 50 | | | $ | 10 | | | | | | | | | | | | | | | | | | As of December 31, 2021 | | | | | | | | | | | | | | | | Operating lease ROU assets | | | | | | | | | | | | | | | | Other deferred debits and other assets | $ | 271 | | | $ | 5 | | | $ | 1 | | | $ | 16 | | | $ | 209 | | | $ | 43 | | | $ | 46 | | | $ | 11 | | | | | | | | | | | | | | | | | | Operating lease liabilities | | | | | | | | | | | | | | | | Other current liabilities | 52 | | | 2 | | | — | | | 15 | | | 31 | | | 6 | | | 8 | | | 3 | | Other deferred credits and other liabilities | 263 | | | 3 | | | 1 | | | 4 | | | 195 | | | 40 | | | 49 | | | 9 | | Total operating lease liabilities | $ | 315 | | | $ | 5 | | | $ | 1 | | | $ | 19 | | | $ | 226 | | | $ | 46 | | | $ | 57 | | | $ | 12 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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:205 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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 |
|
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 10 — Leases | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Finance Leases | | | | | | | | | | PHI | | Pepco | | DPL | | ACE | As of December 31, 2022 | | | | | | | | | | | | | | | | Finance lease ROU assets | | | | | | | | | | | | | | | | Plant, property and equipment, net | | | | | | | | | $ | 74 | | | $ | 25 | | | $ | 31 | | | $ | 18 | | | | | | | | | | | | | | | | | | Finance lease liabilities | | | | | | | | | | | | | | | | Long-term debt due within one year | | | | | | | | | 12 | | | 4 | | | 5 | | | 3 | | Long-term debt | | | | | | | | | 64 | | | 21 | | | 27 | | | 16 | | Total finance lease liabilities | | | | | | | | | $ | 76 | | | $ | 25 | | | $ | 32 | | | $ | 19 | | | | | | | | | | | | | | | | | | 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 | |
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, 2022 | 9.5 | | 1.0 | | 5.5 | | 70.9 | | 6.8 | | 8.1 | | 7.9 | | 3.3 | As of December 31, 2021 | 8.9 | | 3.3 | | 6.1 | | 13.7 | | 7.5 | | 8.6 | | 8.5 | | 3.5 | As of December 31, 2020 | 9.0 | | 3.8 | | 4.2 | | 8.3 | | 8.2 | | 9.1 | | 9.1 | | 4.0 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Finance Leases | | | | | | | | | | PHI | | Pepco | | DPL | | ACE | As of December 31, 2022 | | | | | | | | | 5.5 | | 5.4 | | 5.5 | | 5.6 | 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, 2022 | 3.9 | % | | 2.6 | % | | 2.3 | % | | 4.5 | % | | 4.2 | % | | 4.0 | % | | 4.0 | % | | 3.3 | % | As of December 31, 2021 | 4.0 | % | | 2.8 | % | | 2.2 | % | | 4.0 | % | | 4.2 | % | | 4.0 | % | | 4.0 | % | | 3.4 | % | As of December 31, 2020 | 4.0 | % | | 3.0 | % | | 2.9 | % | | 3.8 | % | | 4.2 | % | | 4.0 | % | | 4.0 | % | | 3.5 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Finance Leases | | | | | | | | | | PHI | | Pepco | | DPL | | ACE | As of December 31, 2022 | | | | | | | | | 2.3 | % | | 2.3 | % | | 2.3 | % | | 2.4 | % | 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 | % |
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 10 — Leases Future minimum lease payments for operating and finance leases under the prior lease accounting guidance as of December 31, 20182022 were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Operating Leases | Year | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | 2023 | $ | 52 | | | $ | 2 | | | $ | — | | | $ | 1 | | | $ | 37 | | | $ | 7 | | | $ | 10 | | | $ | 4 | | 2024 | 45 | | | — | | | — | | | — | | | 35 | | | 6 | | | 9 | | | 3 | | 2025 | 43 | | | — | | | — | | | — | | | 34 | | | 6 | | | 7 | | | 2 | | 2026 | 39 | | | — | | | — | | | — | | | 30 | | | 5 | | | 5 | | | 1 | | 2027 | 39 | | | — | | | — | | | — | | | 29 | | | 4 | | | 6 | | | 1 | | Remaining years | 161 | | | — | | | 1 | | | 18 | | | 67 | | | 20 | | | 25 | | | — | | Total | 379 | | | 2 | | | 1 | | | 19 | | | 232 | | | 48 | | | 62 | | | 11 | | Interest | 73 | | | — | | | — | | | 15 | | | 34 | | | 8 | | | 12 | | | 1 | | Total operating lease liabilities | $ | 306 | | | $ | 2 | | | $ | 1 | | | $ | 4 | | | $ | 198 | | | $ | 40 | | | $ | 50 | | | $ | 10 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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 | 2023 | | | | | | | | | $ | 14 | | | $ | 5 | | | $ | 6 | | | $ | 3 | | 2024 | | | | | | | | | 14 | | | 5 | | | 6 | | | 3 | | 2025 | | | | | | | | | 15 | | | 5 | | | 6 | | | 4 | | 2026 | | | | | | | | | 15 | | | 5 | | | 6 | | | 4 | | 2027 | | | | | | | | | 12 | | | 4 | | | 5 | | | 3 | | Remaining years | | | | | | | | | 12 | | | 4 | | | 5 | | | 3 | | Total | | | | | | | | | 82 | | | 28 | | | 34 | | | 20 | | Interest | | | | | | | | | 6 | | | 3 | | | 2 | | | 1 | | Total finance lease liabilities | | | | | | | | | $ | 76 | | | $ | 25 | | | $ | 32 | | | $ | 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, 2022 | $ | 66 | | | $ | 3 | | | $ | — | | | $ | 16 | | | $ | 37 | | | $ | 8 | | | $ | 9 | | | $ | 4 | | For the year ended December 31, 2021 | 93 | | | 3 | | | — | | | 46 | | | 39 | | | 8 | | | 9 | | | 4 | | For the year ended December 31, 2020 | 67 | | | 3 | | | 1 | | | 20 | | | 39 | | | 8 | | | 9 | | | 4 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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, 2022 | | | | | | | | | $ | 13 | | | $ | 5 | | | $ | 5 | | | $ | 3 | | 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, 2022 | $ | 46 | | | $ | — | | | $ | — | | | $ | — | | | $ | 2 | | | $ | — | | | $ | 1 | | | $ | 1 | | For the year ended December 31, 2021 | 1 | | | — | | | — | | | (1) | | | 1 | | | — | | | 1 | | | — | | For the year ended December 31, 2020 | (2) | | | — | | | 1 | | | — | | | (1) | | | — | | | (1) | | | — | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Operating leases | $ | 52 |
| | $ | 14 |
| | $ | 6 |
| | $ | — |
| | $ | 2 |
| | $ | (3 | ) | | $ | (1 | ) | | $ | (2 | ) | | $ | (1 | ) |
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 10 — Leases | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Finance Leases | | | | | | | | | | PHI | | Pepco | | DPL | | ACE | For the year ended December 31, 2022 | | | | | | | | | $ | 14 | | | $ | 4 | | | $ | 7 | | | $ | 3 | | 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, 2022. ACE did not have any operating leases for which they are the lessors for the years ended December 31, 2022 and 2021. During 2020, ACE was the lessor for an operating lease, which expired in that year and resulted in less than $1 million in operating lease income. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exelon | | GenerationComEd | | ComEdPECO | | PECOBGE | | BGEPHI | | PHIPepco | | PepcoDPL | | DPL | | ACE | Contracted generationReal estate | ● | | ● | | ● | | ● | | ● | | ● | | ● | | | | | Real estate | ● | | ● | | ● | | ● | | ● | | ● | | ● | | ● | | ● |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (in years) | Exelon | | GenerationComEd | | ComEdPECO | | PECOBGE | | BGEPHI | | PHIPepco | | PepcoDPL | | DPL | | ACE | Remaining lease terms | 1-831-80 | | 1-321-14 | | 1-171-80 | | 1-8320 | | 231-10 | | 1-131-3 | | 1-69-10 | | 12-13 | | 1-2 | Options to extend the term | 1-795-79 | | 1-55-79 | | 5-795-50 | | 5-50N/A | | N/A | | 5N/A | | N/A | | N/A | | | N/A | | | | | | | | | | | | | |
The components of lease income were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | | For the year ended December 31, 2022 | | | | | | | | | | | | | | | | Operating lease income | $ | 4 | | | $ | — | | | $ | — | | | $ | — | | | $ | 4 | | | $ | — | | | $ | 3 | | | | Variable lease income | 1 | | | — | | | — | | | — | | | 1 | | | — | | | 1 | | | | | | | | | | | | | | | | | | | | For the year ended December 31, 2021 | | | | | | | | | | | | | | | | Operating lease income | $ | 5 | | | $ | — | | | $ | — | | | $ | — | | | $ | 4 | | | $ | — | | | $ | 3 | | | | Variable lease income | 1 | | | — | | | — | | | — | | | 1 | | | — | | | 1 | | | | | | | | | | | | | | | | | | | | For the year ended December 31, 2020 | | | | | | | | | | | | | | | | Operating lease income | $ | 5 | | | $ | — | | | $ | — | | | $ | — | | | $ | 3 | | | $ | — | | | $ | 3 | | | | Variable lease income | 1 | | | — | | | — | | | — | | | 1 | | | — | | | 1 | | | |
Future minimum lease payments to be recovered under operating leases as of December 31, 2022 were as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Year | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | | 2023 | $ | 5 | | | $ | 1 | | | $ | — | | | $ | — | | | $ | 4 | | | $ | — | | | $ | 3 | | | | 2024 | 5 | | | 1 | | | — | | | — | | | 3 | | | — | | | 3 | | | | 2025 | 5 | | | — | | | — | | | — | | | 4 | | | — | | | 5 | | | | 2026 | 5 | | | — | | | — | | | — | | | 5 | | | — | | | 4 | | | | 2027 | 5 | | | — | | | — | | | — | | | 5 | | | — | | | 4 | | | | Remaining years | 27 | | | — | | | 4 | | | 1 | | | 23 | | | — | | | 22 | | | | Total | $ | 52 | | | $ | 2 | | | $ | 4 | | | $ | 1 | | | $ | 44 | | | $ | — | | | $ | 41 | | | |
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:Note 11 — Asset Impairments
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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. Asset Impairments (Exelon Generation and PHI) The Registrants evaluate the carrying value of long-lived assets or asset groups for recoverability whenever events or changes in circumstances indicate that the carrying value of those assets may not be recoverable. Indicators of impairment may include a deteriorating business climate, including, but not limited to, declines in energy prices, condition of the asset, specific regulatory disallowance, or plans to dispose of a long-lived asset significantly before the end of its useful life. The Registrants determine if long-lived assets or asset groups are impaired by comparing the undiscounted expected future cash flows to the carrying value. When the undiscounted cash flow analysis indicates a long-lived asset or asset group is not recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset or asset group over its fair value. The fair value analysis is primarily based on the income approach using significant unobservable inputs (Level 3) including revenue and generation forecasts, projected capital and maintenance expenditures and discount rates. A variation in the assumptions used could lead to a different conclusion regarding the recoverability of an asset or asset group and, thus, could potentially result in material future impairments of the Registrant's long-lived assets.
Equity Method Investments in Certain Distributed Energy Companies (Exelon and Generation)BGE)
In the third quarter of 2019, Generation’s equity method investments2022, a review of the impacts of COVID-19 on office use resulted in certain distributed energy companies were fully impaired dueplans to cease the renovation and dispose of an other-than-temporary declineoffice building at BGE before the asset was placed into service. BGE determined that the carrying value was not recoverable and that its fair value was less than carrying value. As a result, in market conditions and underperforming projects. Exelon and Generation recorded2022, a pre-tax impairment charge of $164$48 million was recorded in EquityOperating and maintenance expense in losses of unconsolidated affiliatesExelon’s and an offsetting pre-tax $96 million in Net income attributable to noncontrolling interests in theirBGE’s Consolidated Statements of Operations and Comprehensive Income. As a result, Generation acceleratedThe fair value used in the amortizationanalysis was based on an estimate of investment tax credits associated with these companies and Exelon and Generation recorded a benefit of $46 million in Income taxes. The impairment charge andan expected sales price. However, the accelerated amortization of investment tax credits resulted in a net $15 million decrease to Exelon’s and Generation’s earnings. See Note 22 — 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, sellsoffice building did not meet 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 suchcriteria for classification 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 assetsheld for sale as of December 31, 2019. EGR IV is a wholly owned indirect subsidiary of Exelon2022, and Generationtherefore continues to be reported within Property, plant and includes Generation's interestequipment in EGRPExelon’s 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 assetBGE’s Balance Sheets 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.2022.
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. Intangible Assets Goodwill (Exelon, Generation, ComEd, PHI, Pepco, DPL, and ACE) Goodwill
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, 20192022 and 2018.2021. There were no additions impairments or measurement period adjustmentsimpairments during the years ended December 31, 20192022 and 2018.2021. | | | | | | | | | | | | | | 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 | $ | 8,613 | | | $ | 1,983 | | | $ | 6,630 | | 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
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 12 — Intangible Assets 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 2022 and liabilities of the reporting unit. 2019 and 20182021 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, 20192022 and 2018 for ComEd and as of November 1, 2019 for PHI.2021. 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, 2022 and 2021. 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, 20192022 and 2018.2021. The intangible 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, 2022 | | December 31, 2021 | | | Gross | | Accumulated Amortization | | Net | | Gross | | Accumulated Amortization | | Net | Exelon | | | | | | | | | | | | | Unamortized Energy Contracts | | $ | (1,515) | | | $ | 1,470 | | | $ | (45) | | | $ | (1,515) | | | $ | 1,280 | | | $ | (235) | | Software License | | 81 | | | (61) | | | 20 | | | 81 | | | (53) | | | 28 | | Exelon Total | | $ | (1,434) | | | $ | 1,409 | | | $ | (25) | | | $ | (1,434) | | | $ | 1,227 | | | $ | (207) | | PHI | | | | | | | | | | | | | Unamortized Energy Contracts | | $ | (1,515) | | | $ | 1,470 | | | $ | (45) | | | $ | (1,515) | | | $ | 1,280 | | | $ | (235) | |
The following table summarizes the amortization expense related to intangible assets and liabilities for each of the years ended December 31, 2019, 20182022, 2021, and 2017:2020: | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | | Exelon (a)(b) | | Generation (a) | | ComEd | | PHI(b) | 2019 | | $ | (28 | ) | | $ | 74 |
| | $ | 7 |
| | $ | (119 | ) | 2018 | | (109 | ) | | 63 |
| | 7 |
| | (188 | ) | 2017 | | (237 | ) | | 83 |
| | 7 |
| | (336 | ) |
| | | | | | | | | | | | | | | For the Years Ended December 31, | | Exelon(a) | | PHI(a) | 2022(b) | | $ | (182) | | | $ | (190) | | 2021 | | (83) | | | (92) | | 2020 | | (98) | | | (115) | |
__________ | | (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)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.
(b)On March 23, 2022, the NJBPU approved a petition by ACE to terminate the provisions in its PPAs. As such, the contract was fully amortized during the year ended December 31, 2022. See Note 3 - Regulatory Matters for additional information. The following table summarizes the estimated future amortization expense related to intangible assets and liabilities as of December 31, 2019:2022: | | | | | | | | | | | | | | | For the Years Ending December 31, | | Exelon | | PHI | 2023 | | $ | (2) | | | $ | (10) | | 2024 | | — | | | (8) | | 2025 | | (2) | | | (5) | | 2026 | | (5) | | | (5) | | 2027 | | (4) | | | (4) | |
| | | | | | | | | | | | | | | | | | For the Years Ending December 31, | | Exelon | | Generation | | ComEd | | PHI | 2020 | | $ | (13 | ) | | $ | 85 |
| | $ | 7 |
| | $ | (115 | ) | 2021 | | 2 |
| | 84 |
| | — |
| | (92 | ) | 2022 | | (21 | ) | | 58 |
| | — |
| | (89 | ) | 2023 | | (18 | ) | | 53 |
| | — |
| | (81 | ) | 2024 | | 22 |
| | 50 |
| | — |
| | (38 | ) |
210
Renewable Energy Credits (Exelon and Generation)
Exelon’s and Generation’s RECs are included in Other current assets and Other deferred debits and other assets in the 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 Credits as of December 31, 2019 and 2018:
| | | | | | | | | | | | | | 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 |
|
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 13 — Income Taxes
13. 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, 2022 | | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Included in operations: | | | | | | | | | | | | | | | | Federal | | | | | | | | | | | | | | | | Current | $ | (24) | | | $ | 29 | | | $ | 13 | | | $ | (1) | | | $ | 16 | | | $ | 9 | | | $ | (2) | | | $ | 6 | | Deferred | 106 | | | 117 | | | 18 | | | (3) | | | (23) | | | (2) | | | 2 | | | (15) | | Investment tax credit amortization | (3) | | | (1) | | | — | | | — | | | (1) | | | — | | | — | | | — | | State | | | | | | | | | | | | | | | | Current | (13) | | | (6) | | | (4) | | | — | | | 2 | | | — | | | — | | | — | | Deferred | 283 | | | 125 | | | 52 | | | 12 | | | 15 | | | (16) | | | 14 | | | 12 | | Total | $ | 349 | | | $ | 264 | | | $ | 79 | | | $ | 8 | | | $ | 9 | | | $ | (9) | | | $ | 14 | | | $ | 3 | |
| | | For the Year Ended December 31, 2019 | | For the Year Ended December 31, 2021 | | 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 | $ | (152) | | | $ | (30) | | | $ | 1 | | | $ | (18) | | | $ | 18 | | | $ | 22 | | | $ | 2 | | | $ | 1 | | Deferred | 489 |
| | 346 |
| | 15 |
| | 20 |
| | 95 |
| | (34 | ) | | (6 | ) | | (21 | ) | | (6 | ) | Deferred | 89 | | | 113 | | | 20 | | | 34 | | | (52) | | | (17) | | | (14) | | | (26) | | Investment tax credit amortization | (72 | ) | | (69 | ) | | (2 | ) | | — |
| | — |
| | (1 | ) | | — |
| | — |
| | — |
| Investment tax credit amortization | (2) | | | (1) | | | — | | | — | | | (1) | | | — | | | — | | | — | | State | | | | | | | | | | | | | | | | | | State | | Current | 5 |
| | 10 |
| | (5 | ) | | — |
| | — |
| | 3 |
| | — |
| | — |
| | — |
| Current | (46) | | | (41) | | | — | | | — | | | — | | | 1 | | | 1 | | | — | | Deferred | 267 |
| | 82 |
| | 96 |
| | — |
| | 35 |
| | 27 |
| | 6 |
| | 14 |
| | 9 |
| Deferred | 149 | | | 131 | | | (9) | | | (51) | | | 77 | | | 9 | | | 53 | | | 12 | | Total | $ | 774 |
| | $ | 516 |
| | $ | 163 |
| | $ | 65 |
| | $ | 79 |
| | $ | 38 |
| | $ | 16 |
| | $ | 22 |
| | $ | — |
| Total | $ | 38 | | | $ | 172 | | | $ | 12 | | | $ | (35) | | | $ | 42 | | | $ | 15 | | | $ | 42 | | | $ | (13) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | For the Year Ended December 31, 2020 | | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Included in operations: | | | | | | | | | | | | | | | | Federal | | | | | | | | | | | | | | | | Current | $ | (180) | | | $ | (24) | | | $ | (7) | | | $ | 4 | | | $ | 25 | | | $ | 40 | | | $ | (13) | | | $ | (4) | | Deferred | 10 | | | 112 | | | 1 | | | 10 | | | (129) | | | (62) | | | (20) | | | (43) | | Investment tax credit amortization | (3) | | | (2) | | | — | | | — | | | (1) | | | — | | | — | | | — | | State | | | | | | | | | | | | | | | | Current | (37) | | | (27) | | | — | | | — | | | (5) | | | — | | | — | | | — | | Deferred | 203 | | | 118 | | | (24) | | | 27 | | | 33 | | | 15 | | | 8 | | | 6 | | Total | $ | (7) | | | $ | 177 | | | $ | (30) | | | $ | 41 | | | $ | (77) | | | $ | (7) | | | $ | (25) | | | $ | (41) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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: 211 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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 13 — Income Taxes
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | For the Year Ended December 31, 2022(a) | | Exelon | | ComEd | | PECO(b) | | BGE(b) | | PHI(b) | | Pepco(b) | | 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(c) | 8.8 | | | 8.0 | | | 5.8 | | | 2.6 | | | 2.1 | | | (4.1) | | | 6.5 | | | 6.9 | | Plant basis differences | (4.1) | | | (0.6) | | | (11.9) | | | (1.0) | | | (1.7) | | | (2.7) | | | (0.7) | | | (0.7) | | Excess deferred tax amortization | (11.8) | | | (5.6) | | | (3.0) | | | (19.8) | | | (19.5) | | | (16.8) | | | (18.4) | | | (24.5) | | Amortization of investment tax credit, including deferred taxes on basis differences | (0.1) | | | (0.1) | | | — | | | (0.1) | | | (0.1) | | | — | | | (0.2) | | | (0.2) | | Tax credits(d) | 0.1 | | | (0.3) | | | — | | | (0.7) | | | (0.7) | | | (0.7) | | | (0.6) | | | (0.5) | | Other(e) | 0.6 | | | — | | | 0.2 | | | 0.1 | | | 0.4 | | | 0.3 | | | 0.1 | | | — | | Effective income tax rate | 14.5 | % | | 22.4 | % | | 12.1 | % | | 2.1 | % | | 1.5 | % | | (3.0) | % | | 7.7 | % | | 2.0 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | For the Year Ended December 31, 2021(a) | | Exelon | | ComEd | | PECO(f) | | BGE(f) | | PHI | | Pepco(f) | | DPL(f) | | ACE(f) | U.S. federal statutory rate | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | Increase (decrease) due to: | | | | | | | | | | | | | | | | State income taxes, net of federal income tax benefit | 5.0 | | | 7.8 | | | (1.4) | | | (10.8) | | | 10.1 | | | 2.7 | | | 25.0 | | | 7.4 | | Plant basis differences | (5.4) | | | (0.8) | | | (13.6) | | | (1.7) | | | (1.1) | | | (1.6) | | | (0.8) | | | (0.2) | | Excess deferred tax amortization | (17.2) | | | (7.6) | | | (3.8) | | | (16.3) | | | (22.4) | | | (16.4) | | | (20.0) | | | (37.1) | | Amortization of investment tax credit, including deferred taxes on basis differences | (0.1) | | | (0.1) | | | — | | | (0.1) | | | (0.1) | | | — | | | (0.2) | | | (0.2) | | Tax credits | (0.7) | | | (0.5) | | | — | | | (0.9) | | | (0.5) | | | (0.5) | | | (0.4) | | | (0.5) | | Other | (0.3) | | | (1.0) | | | 0.1 | | | (0.6) | | | — | | | (0.4) | | | 0.1 | | | (0.2) | | Effective income tax rate | 2.3 | % | | 18.8 | % | | 2.3 | % | | (9.4) | % | | 7.0 | % | | 4.8 | % | | 24.7 | % | | (9.8) | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | For the Year Ended December 31, 2020(a) | | Exelon | | ComEd(g) | | PECO(g) | | BGE(h) | | PHI(h) | | Pepco(h) | | DPL(h) | | ACE(h) | 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 | 11.9 | | | 11.6 | | | (4.5) | | | 5.5 | | | 5.1 | | | 4.5 | | | 6.6 | | | 7.0 | | Plant basis differences | (8.6) | | | (0.6) | | | (18.7) | | | (1.5) | | | (1.6) | | | (1.7) | | | (0.4) | | | (3.0) | | Excess deferred tax amortization | (29.1) | | | (11.2) | | | (4.6) | | | (13.9) | | | (42.0) | | | (25.4) | | | (51.7) | | | (82.1) | | Amortization of investment tax credit, including deferred taxes on basis differences | (0.3) | | | (0.3) | | | — | | | (0.1) | | | (0.2) | | | (0.1) | | | (0.3) | | | (0.5) | | Tax credits | (0.5) | | | (0.3) | | | — | | | (0.4) | | | (0.3) | | | (0.3) | | | (0.3) | | | (0.5) | | Deferred Prosecution Agreement payments | 3.8 | | | 6.8 | | | — | | | — | | | — | | | — | | | — | | | — | | Other | 1.2 | | | 1.8 | | | (0.4) | | | (0.1) | | | (0.4) | | | (0.7) | | | 0.1 | | | 0.4 | | Effective income tax rate | (0.6) | % | | 28.8 | % | | (7.2) | % | | 10.5 | % | | (18.4) | % | | (2.7) | % | | (25.0) | % | | (57.7) | % |
__________ (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 partially offset by higher state income taxes, net of federal income tax benefit, related to a one-time expense of $38 million attributable to the change in the Pennsylvania corporate income tax rate. For BGE, PHI, Pepco, DPL, and ACE, the lower effective tax rate is primarily related to the acceleration of certain income tax benefits due to distribution and transmission rate case settlements. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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 | % |
212
__________
| | (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 13 — Income Taxes
(c)For Exelon, the higher state income taxes, net of federal income tax benefit, is primarily due to the long-term marginal state income tax rate change of $67 million and the recognition of a valuation allowance of $40 million against the net deferred tax asset position for certain standalone state filing jurisdictions, partially offset by a one-time impact associated with a state tax benefit of $43 million and indemnification adjustments pursuant to the Tax Matters Agreement of $11 million as a result of the separation. For PECO, the higher state income taxes, net of federal income tax benefit, related to a one-time expense of $38 million attributable to the change in the Pennsylvania corporate income tax rate.
(d)For Exelon, reflects the income tax expense related to the write-off of federal tax credits subject to recapture of $15 million as a result of the separation. (e)For Exelon, reflects the nondeductible transaction costs of approximately $12 million arising as part of the separation and indemnification adjustments pursuant to the Tax Matters Agreement of $9 million. (f)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 Pepco, the lower effective tax rate is primarily related to the acceleration of certain income tax benefits due to distribution and transmission rate case settlements. 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. (g)For ComEd, the higher effective tax rate is primarily related to the nondeductible DPA payments. For 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. (h)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. 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, 20192022 and 20182021 are presented below: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | As of December 31, 2022 | | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Plant basis differences | $ | (12,130) | | | $ | (4,823) | | | $ | (2,119) | | | $ | (1,949) | | | $ | (3,131) | | | $ | (1,394) | | | $ | (906) | | | $ | (813) | | Accrual based contracts | 10 | | | — | | | — | | | — | | | 10 | | | — | | | — | | | — | | Derivatives and other financial instruments | 26 | | | 23 | | | — | | | — | | | 2 | | | — | | | — | | | — | | Deferred pension and postretirement obligation | 551 | | | (300) | | | (31) | | | (31) | | | (80) | | | (76) | | | (39) | | | (3) | | Deferred debt refinancing costs | 132 | | | (5) | | | — | | | (2) | | | 111 | | | (4) | | | (2) | | | (1) | | Regulatory assets and liabilities | (1,107) | | | (131) | | | (169) | | | 57 | | | (50) | | | 7 | | | 43 | | | 11 | | Tax loss carryforward, net of valuation allowances | 250 | | | — | | | 33 | | | 72 | | | 71 | | | 3 | | | 20 | | | 46 | | Tax credit carryforward | 468 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Investment in partnerships | (21) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Other, net | 591 | | | 223 | | | 73 | | | 23 | | | 182 | | | 83 | | | 16 | | | 28 | | Deferred income tax liabilities (net) | $ | (11,230) | | | $ | (5,013) | | | $ | (2,213) | | | $ | (1,830) | | | $ | (2,885) | | | $ | (1,381) | | | $ | (868) | | | $ | (732) | | Unamortized investment tax credits | (14) | | | (8) | | | — | | | (2) | | | (4) | | | (1) | | | (1) | | | (2) | | Total deferred income tax liabilities (net) and unamortized investment tax credits | $ | (11,244) | | | $ | (5,021) | | | $ | (2,213) | | | $ | (1,832) | | | $ | (2,889) | | | $ | (1,382) | | | $ | (869) | | | $ | (734) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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 13 — Income Taxes
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | As of December 31, 2021 | | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Plant basis differences | $ | (11,606) | | | $ | (4,648) | | | $ | (2,271) | | | $ | (1,826) | | | $ | (2,976) | | | $ | (1,321) | | | $ | (853) | | | $ | (777) | | Accrual based contracts | 56 | | | — | | | — | | | — | | | 56 | | | — | | | — | | | — | | Derivatives and other financial instruments | 63 | | | 61 | | | — | | | — | | | 2 | | | — | | | — | | | — | | Deferred pension and postretirement obligation | 641 | | | (308) | | | (32) | | | (37) | | | (90) | | | (76) | | | (40) | | | (6) | | Deferred debt refinancing costs | 146 | | | (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 | 242 | | | — | | | 65 | | | 68 | | | 64 | | | 2 | | | 18 | | | 42 | | Tax credit carryforward | 584 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Investment in partnerships | (21) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Other, net | 449 | | | 216 | | | 97 | | | 21 | | | 212 | | | 99 | | | 19 | | | 34 | | Deferred income tax liabilities (net) | $ | (10,576) | | | $ | (4,677) | | | $ | (2,421) | | | $ | (1,684) | | | $ | (2,662) | | | $ | (1,274) | | | $ | (802) | | | $ | (677) | | Unamortized investment tax credits | (15) | | | (8) | | | — | | | (2) | | | (5) | | | (1) | | | (1) | | | (2) | | Total deferred income tax liabilities (net) and unamortized investment tax credits | $ | (10,591) | | | $ | (4,685) | | | $ | (2,421) | | | $ | (1,686) | | | $ | (2,667) | | | $ | (1,275) | | | $ | (803) | | | $ | (679) | |
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, andas well as, any corresponding valuation allowances as of December 31, 2019.2022. ComEd does not have net operating losses or credit carryforwards for the year ended December 31, 2019.2022. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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(a) | $ | 468 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | State | | | | | | | | | | | | | | State net operating loss carryforwards | 4,991 | | | 970 | | | 1,142 | | | 1,501 | | | 50 | | | 768 | | | 651 | | Deferred taxes on state tax attributes (net of federal taxes) | 307 | | | 37 | | | 72 | | | 104 | | | 3 | | | 52 | | | 46 | | Valuation allowance on state tax attributes (net of federal taxes)(b) | 57 | | | 4 | | | — | | | 33 | | | — | | | 32 | | | — | | 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. |
Tabular Reconciliation(a)For Exelon, the federal general business credit carryforward will begin expiring in 2035.
(b)For Exelon, a full valuation allowance has been recorded against certain separate company state net operating loss carryforwards that are expected to expire before realization. For PECO, a valuation allowance has been recorded against certain Pennsylvania net operating losses that are expected to expire before realization. For 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 Unrecognized Tax Benefits The following table presents changes in unrecognized tax benefits, by Registrant.
Exelon's, BGE's, Pepco's, and DPL's Maryland state net operating loss carryforward have an indefinite carryforward period.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 13 — Income Taxes
Tabular Reconciliation of Unrecognized Tax Benefits
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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 |
|
__________
| | (a) | Exelon established a liability for an uncertain tax position associated with the tax deductibility of certain merger commitments incurred by ExelonThe following table presents changes in connection with the acquisitions of Constellation 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 $33for Exelon, PHI, and ACE. ComEd's, PECO's, BGE's, Pepco's, and DPL's amounts are not material.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exelon(a) | | | | | | | | PHI | | | | | | ACE | Balance at January 1, 2020 | $ | 95 | | | | | | | | | $ | 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 | (5) | | | | | | | | | — | | | | | | | — | | | | | | | | | | | | | | | | | | 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) | | | | | | | | | — | | | | | | | — | | Balance at December 31, 2021 | 143 | | | | | | | | | 56 | | | | | | | 16 | | Change to positions that only affect timing | (1) | | | | | | | | | 1 | | | | | | | 1 | | Increases based on tax positions related to 2022 | 3 | | | | | | | | | 2 | | | | | | | — | | Increases based on tax positions prior to 2022 | 3 | | | | | | | | | — | | | | | | | — | | Decreases based on tax positions prior to 2022 | — | | | | | | | | | — | | | | | | | — | | | | | | | | | | | | | | | | | | Balance at December 31, 2022 | $ | 148 | | | | | | | | | $ | 59 | | | | | | | $ | 17 | |
______ (a)As of December 31, 2022, Exelon recorded a receivable of $50 million and $2 million, respectively,in noncurrent Other assets in the first quarterConsolidated Balance Sheet for Constellation’s share of 2019.unrecognized tax benefits for periods prior to the separation. 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, 2022 | $ | 90 | | | | | | | | | | | | December 31, 2021 | 77 | | | | | | | | | | | | December 31, 2020 | 73 | | | | | | | | | | | |
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, 2022, 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, 2022 (a) (b) | $ | 45 | | December 31, 2021 (c) | 43 | |
| | | | | 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 13 — Income Taxes
__________
(a)As of December 31, 2022, the interest receivable balance is not expected to be settled in cash within the next twelve months and is therefore classified as a noncurrent receivable. (b)As of December 31, 2022, Exelon recorded a receivable of $1 million in noncurrent Other assets in the Consolidated Balance Sheet for Constellation's share of net interest for periods prior to the separation. (c)As of December 31, 2021, the interest receivable balance is not expected to be settled in cash within the next twelve months and is therefore classified as a noncurrent 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) | 2002-20182010-2021 | | 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 | 2016-20182019-2021 | | Exelon, PHI, Pepco | Illinois unitary corporate income tax returns | 2010-20182012-2021 | | 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 | 2019-2021 | | Exelon | New Jersey separate corporate income tax returns | 2014-20182018-2021 | | ACE | New York combined corporate income tax returns | 2010-March 20122015-2021 | | 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 | 2016-20182019-2021 | | Exelon | Pennsylvania separate corporate income tax returns | 2019-2021 | | 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 ChangesSeparation (Exelon)
On December 22, 2017, President Trump signedIn the TCJA into law. Pursuantfirst quarter of 2022, in connection with the separation, Exelon recorded an income tax expense related to continuing operations of $148 million primarily due to the enactment of the TCJA, the Registrants remeasured their existing deferred income tax balances as of December 31, 2017 to reflect the decrease in the corporatelong-term marginal state income tax rate from 35% to 21%, which resulted in a material decrease to theirchange of $67 million discussed further below, the recognition of valuation allowances of approximately $40 million against the net deferred income tax assets positions for certain standalone state filing jurisdictions, the write-off of federal and state tax credits subject to recapture of $17 million, and nondeductible transaction costs for federal and state taxes of $24 million.
Tax Matters Agreement (Exelon) In connection with the separation, Exelon entered into a TMA with Constellation. The TMA governs the respective rights, responsibilities, and obligations between Exelon and Constellation after the separation with respect to tax liabilities, refunds and attributes for open tax years that Constellation was part of Exelon’s consolidated group for U.S. federal, state, and local tax purposes. Indemnification for Taxes. As a former subsidiary of Exelon, Constellation has joint and several liability balances as shown inwith Exelon to the table below. Generation recorded a corresponding net decreaseIRS and certain state jurisdictions relating to income tax expense, while the Utility Registrants recorded corresponding regulatory liabilities or assetstaxable periods prior to the separation. The TMA specifies that Constellation is liable for their share of taxes required to be paid by Exelon with respect to taxable periods prior to the separation to the extent Constellation would have been responsible for such amounts are probable of settlement or recovery through customer rates and an adjustment to incometaxes under the existing Exelon tax expense 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 ratesharing agreement. As a result, as of DecemberMarch 31, 2017 are presented below:2022, Exelon recorded a receivable of $55 million in Current other assets in the Consolidated Balance Sheet for Constellation’s share of taxes for periods
216 | | | | | | | | | | | | | | | | | | | | 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 Changesprior to the separation. As of December 31, 2022, Exelon recorded a payable of $18 million in Current other liabilities that is due to Constellation.
IllinoisTax Refunds. - On June 5, 2019,The TMA specifies that Constellation is entitled to their share of any future tax refunds claimed by Exelon with respect to taxable periods prior to the Governorseparation to the extent that Constellation would have received such tax refunds under the existing Exelon tax sharing agreement.
Tax Attributes. At the date of Illinois signedseparation certain tax attributes, primarily pre-closing tax credit carryforwards, that were generated by Constellation were required by law to be allocated to Exelon. The TMA also provides that Exelon will reimburse Constellation when those allocated tax attribute carryforwards are utilized. As of March 31, 2022, Exelon recorded a tax bill which would increasepayable of $11 million and $484 million in Current other liabilities and Noncurrent other liabilities, respectively, in the Illinois corporate income tax rate from 9.50% to 10.49% effectiveConsolidated Balance Sheet for tax years beginning on or after January 1, 2021. The tax rate is contingent upon ratificationcredit carryforwards that are expected to be utilized and reimbursed to Constellation. As of state constitutional amendments in November 2020. The effect ofDecember 31, 2022, the rate change will be recognized in the period in which the new legislation is enacted. Exelon, Generationcurrent and ComEd do not expect a material impact to their financial statements as a result of the rate change. In 2017, Exelon reviewednoncurrent payable amounts are $169 million 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 |
| | — |
|
$362 million, respectively.Long-Term Marginal State Income Tax Rate (All Registrants) Quarterly, Exelon reviews and updates its marginal state income tax rates 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. | | | | | | | | | | | | | | | | | 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 |
| | — |
|
There were no material adjustments In the first quarter of 2022, Exelon updated its marginal state income tax rates for changes in state apportionment due to the separation, which resulted in an increase of $67 million to the deferred tax liability at Exelon, and a corresponding adjustment to income tax expense, net of federal taxes. The impacts to ComEd, BGE, PHI, Pepco, DPL, and ACE for the years ended December 31, 2022, 2021, and 2020 were not material.
| | | | | | | | | | | | December 31, 2022 | Exelon | | | | | | | Increase to Deferred Income Tax Liability and Income Tax Expense, Net of Federal Taxes | $ | 67 | | | | | | | | | | | | | | | | December 31, 2021 | | | | | | | | 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 | | | | | | | | | | | | | | | |
Pennsylvania Corporate Income Tax Rate Change (Exelon and PECO) On July 8, 2022, Pennsylvania enacted House Bill 1342, which will permanently reduce the corporate income tax rate from 9.99% to 4.99%. The tax rate will be reduced to 8.99% for the 2023 tax year. Starting with the 2024 tax year, the rate is reduced by 0.50% annually until it reaches 4.99% in 2017 as2031. As a result of changesthe rate change, in the third quarter of 2022, Exelon and PECO recorded a one-time decrease to deferred income taxes of $390 million with a corresponding decrease to the deferred income taxes regulatory asset of $428 million for the amounts that are expected to be settled through future customer rates and an increase to income tax expense of $38 million (net of federal taxes). The tax rate decrease is not expected to have a material ongoing impact to Exelon’s and PECO’s financial statements. PECO did not update its marginal state apportionment.income tax rates for the years ended December 31, 2021 and 2020. 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.Agreement, for the year ended December 31, 2022, 2021, and 2020. 217 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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 |
| | — |
| | — |
|
__________
| | (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. |
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 13 — Income Taxes
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ComEd | | PECO | | BGE | | | PHI | | Pepco | | DPL | | ACE | December 31, 2022(a) | $ | 1 | | | $ | 47 | | | $ | — | | | | $ | 28 | | | $ | 23 | | | $ | 3 | | | $ | 2 | | December 31, 2021(b) | 1 | | | 19 | | | — | | | | 17 | | | 16 | | | — | | | — | | December 31, 2020(c) | 14 | | | 17 | | | — | | | | 17 | | | 8 | | | 6 | | | 1 | | __________ | | (c) | ComEd, Pepco, DPL and ACE(a)BGE 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 2019, Exelon and Generation recognized additional tax benefits related to certain researchfrom Exelon under the Tax Sharing Agreement as a result of a tax net operating loss.
(b)BGE, DPL, and development activities that qualify forACE did not record an allocation of federal and state tax incentives forbenefits from Exelon under the 2010 through 2018Tax Sharing Agreement as a result of a tax years, which resulted innet operating loss. (c)BGE did not record an increase to Exelon’s and Generation’sallocation of federal tax benefits from Exelon under the Tax Sharing Agreement as a result of a tax 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.operating loss.
14. 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, 2019,2021, 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 February 1, 2022, in connection with the separation, pension and OPEB obligations and assets for current and former employees of the Constellation business and certain other former employees of Exelon mergedand its subsidiaries transferred to pension and OPEB plans and trusts maintained by Constellation or its subsidiaries. The Exelon New England Union Employees Pension Plan and Constellation Mystic Power, LLC Union Employees Pension Plan Including Plan A and Plan B were transferred. The following OPEB plans were also transferred: Constellation Mystic Power, LLC Post-Employment Medical Savings Account Plan; Exelon New England Union Post-Employment Medical Savings Account Plan; and the Nine Mile Point Nuclear Station, LLC Medical Care and Prescription Drug Plan for Retired Employees. As a result of the separation, Exelon restructured certain of its qualified pension plans. Pension obligations and assets for current and former employees continuing with Exelon and who were participants in the Exelon Corporation Cash BalanceEmployee Pension Plan (CBPP)for Clinton, TMI, and Oyster Creek, Pension Plan of Constellation Energy Nuclear Group, LLC, and Nine Mile Point Pension Plan were merged into the Pension Plan of Constellation Energy Group, Inc, which was subsequently renamed, Exelon Corporation Retirement Program (ECRP)Pension Plan (EPP). Exelon employees who participated in these plans prior to the separation now participate in the EPP. 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.
obligations.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 14 — 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: | | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Qualified Pension Plans: | | | | | | | | | | | | | | | | | Exelon Corporation Retirement Program(a) | | | | X | | X | | X | | X | | X | | X | | X | Exelon Corporation Pension Plan for Bargaining Unit Employees(a) | | | | X | | | | | | | | | | | | | Exelon Pension Plan(b) | | | | X | | X | | X | | X | | X | | X | | X | Pepco Holdings LLC Retirement Plan(d) | | | | X | | X | | X | | X | | X | | X | | X | | | | | | | | | | | | | | | | | | | | Operating Company(e)
| Name of Plan: | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Qualified Pension Plans: | | | | | | | | | | | | | | | | | Exelon Corporation Retirement Program(a)
| | X | | X | | X | | X | | X | | X | | X | | X | Exelon Corporation Pension Plan for Bargaining Unit Employees(a)
| | X | | X | | | | | | | | | | | | | Exelon New England Union Employees Pension Plan(a)
| | X | | | | | | | | | | | | | | | Exelon Employee Pension Plan for Clinton, TMI and Oyster Creek(a)
| | X | | X | | X | | | | X | | | | | | X | Pension Plan of Constellation Energy Group, Inc.(b)
| | X | | X | | X | | X | | X | | X | | X | | | Pension Plan of Constellation Energy Nuclear Group, LLC(c)
| | X | | X | | | | X | | X | | | | | | | Nine Mile Point Pension Plan(c)
| | X | | | | | | | | | | | | | | | Constellation Mystic Power, LLC Union Employees Pension Plan Including Plan A and Plan B(b)
| | X | | | | | | | | | | | | | | | Pepco Holdings LLC Retirement Plan(d)
| | 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 | | | | | | | 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 | | | | | | | Constellation Energy Group, Inc. Supplemental Pension Plan(b) | | X | | | | | | X | | X | | | | | | | Constellation Energy Group, Inc. Benefits Restoration Plan(b) | | X | | X | | X | | X | | X | | | | | | | Constellation Energy Nuclear Plan, LLC Executive Retirement Plan(c)
| | X | | | | | | | | X | | | | | | | Constellation Energy Nuclear Plan, LLC Benefits Restoration Plan(c)
| | X | | | | | | | | | | | | | | | Baltimore Gas & Electric Company Executive Benefit Plan(b) | | X | | | | | | X | | | | | | | | | Baltimore Gas & Electric Company Manager Benefit Plan(b) | | X | | X | | X | | X | | | | | | | | | Pepco Holdings LLC 2011 Supplemental Executive Retirement Plan(d) | | | | | | | | | | X | | X | | X | | X | Conectiv Supplemental Executive Retirement Plan(d) | | X | | | | | | | | X | | | | X | | X | Pepco Holdings LLC Combined Executive Retirement Plan(d) | | | | | | | | | | X | | X | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Operating Company(e) | Name of Plan: | | | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | OPEB Plans: | | | | | | | | | | | | | | | | | Atlantic City Electric Director RetirementPECO Energy Company Retiree Medical Plan(d)(a)
| | | | X | | X | | X | | X | | X | | X | | X | Exelon Corporation Health Care Program(a) | | | | X | | X | | X | | X | | X | | X | | X | Exelon Corporation Employees’ Life Insurance Plan(a) | | | | X | | X | | X | | | | | | | | | Exelon Corporation Health Reimbursement Arrangement Plan(a) | | | | X | | X | | X | | | | | | | | | BGE Retiree Medical Plan(b) | | | | X | | X | | X | | X | | X | | X | | | BGE Retiree Dental Plan(b) | | | | | | | | X | | | | | | | | | Exelon Retiree Medical Plan of Constellation Energy Nuclear Group, LLC(c) | | | | X | | | | X | | X | | | | | | | Exelon Retiree Dental Plan of Constellation Energy Nuclear Group, LLC(c) | | | | X | | | | X | | X | | | | | | | Pepco Holdings LLC Welfare Plan for Retirees(d) | | | | 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.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 14 — Retirement Benefits
| | | | | | | | | | | | | | | | | | | | Operating Company(e)
| Name of Plan: | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | OPEB Plans: | | | | | | | | | | | | | | | | | PECO Energy Company Retiree Medical Plan(a)
| | X | | X | | X | | X | | X | | X | | X | | X | Exelon Corporation Health Care Program(a)
| | X | | X | | X | | X | | X | | X | | | | X | Exelon Corporation Employees’ Life Insurance Plan(a)
| | X | | X | | X | | X | | | | | | | | | Exelon Corporation Health Reimbursement Arrangement Plan(a)
| | X | | X | | X | | X | | | | | | | | | Constellation Energy Group, Inc. Retiree Medical Plan(b)
| | X | | X | | X | | X | | X | | X | | | | | Constellation Energy Group, Inc. Retiree Dental Plan(b)
| | X | | | | | | X | | | | | | | | | Constellation Energy Group, Inc. Employee Life Insurance Plan and Family Life Insurance Plan(b)
| | X | | X | | X | | X | | X | | X | | | | | Constellation Mystic Power, LLC
Post-Employment Medical Account Savings Plan(b)
| | X | | | | | | | | | | | | | | | Exelon New England Union Post-Employment Medical Savings Account Plan(a)
| | X | | | | | | | | | | | | | | | Retiree Medical Plan of Constellation Energy Nuclear Group LLC(c)
| | X | | | | | | X | | | | X | | | | | Retiree Dental Plan of Constellation Energy Nuclear Group LLC(c)
| | X | | | | | | X | | | | X | | | | | Nine Mile Point Nuclear Station, LLC Medical Care and Prescription Drug Plan for Retired Employees(c)
| | X | | | | | | | | | | | | | | | Pepco Holdings LLC Welfare Plan for Retirees(d)
| | 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. |
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 As of February 1, 2022, in connection with the separation, Exelon's pension and OPEB plans were remeasured. The remeasurement and separation resulted in a decrease to the pension obligation, net of plan assets, of $921 million and a decrease to the OPEB obligation of $893 million. Additionally, accumulated other comprehensive loss, decreased by $1,994 million (after-tax) and regulatory assets and liabilities increased by $14 million and $5 million respectively. Key assumptions were held consistent with the year end December 31, 2021 assumptions with the exception of the discount rate. During the first quarter of 2019,2022, Exelon received an updated valuation of its pension and OPEB to reflect actual census data as of JanuaryFebruary 1, 2019.2022. This valuation resulted in a decrease to the pension obligations of $24 million and an increase to the pension and OPEB obligations of $75 million and $36 million, respectively.$5 million. Additionally, accumulated other comprehensive loss increased by $39$5 million (after-tax) and regulatory assets and liabilities increaseddecreased by $53$30 million and decreased by $5$3 million, respectively.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 14 — 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 | | 2022 | | 2021 | | 2022 | | 2021 | Change in benefit obligation: | | | | | | | | Net benefit obligation as of the beginning of year | $ | 14,236 | | | $ | 14,861 | | | $ | 2,502 | | | $ | 2,661 | | Service cost | 236 | | | 294 | | | 41 | | | 51 | | Interest cost | 439 | | | 406 | | | 76 | | | 69 | | Plan participants’ contributions | — | | | — | | | 26 | | | 32 | | Actuarial (gain) loss(a) | (3,379) | | | (442) | | | (604) | | | (116) | | | | | | | | | | | | | | | | | | | | | | | | | | Settlements | — | | | (23) | | | — | | | (5) | | | | | | | | | | Gross benefits paid | (855) | | | (860) | | | (157) | | | (190) | | Net benefit obligation as of the end of year | $ | 10,677 | | | $ | 14,236 | | | $ | 1,884 | | | $ | 2,502 | |
| | | | | | | | | | | | | | | | | | 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 | | 2022 | | 2021 | | 2022 | | 2021 | 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 | $ | 12,165 | | | $ | 11,883 | | | $ | 1,665 | | | $ | 1,635 | | Actual return on plan assets | 3,008 |
| | (945 | ) | | 324 |
| | (136 | ) | Actual return on plan assets | (2,359) | | | 822 | | | (225) | | | 130 | | Employer contributions | 356 |
|
| 337 |
|
| 51 |
|
| 46 |
| Employer contributions | 570 | | | 343 | | | 42 | | | 63 | | Plan participants’ contributions | — |
| | — |
| | 44 |
| | 45 |
| Plan participants’ contributions | — | | | — | | | 26 | | | 32 | | Gross benefits paid | (1,417 | ) |
| (1,239 | ) |
| (282 | ) |
| (275 | ) | Gross benefits paid | (855) | | | (860) | | | (157) | | | (190) | | | Settlements | (35 | ) |
| (48 | ) |
| (4 | ) |
| (4 | ) | Settlements | — | | | (23) | | | — | | | (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 | $ | 9,521 | | | $ | 12,165 | | | $ | 1,351 | | | $ | 1,665 | |
__________ | | (a) | (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. |
Exelon presents its benefit obligations and plan assets net on its balance sheet withinOPEB gains in 2022 and 2021 primarily reflect an increase in the following line items:discount rate.
| | | | | | | | | | | | | | | | | | 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 14 — Retirement Benefits
Exelon presents its benefit obligations and plan assets net on its Consolidated Balance Sheets within the following line items:
| | | | | | | | | | | | | | | | | | | | | | | | | Pension Benefits | | OPEB | | 2022 | | 2021 | | 2022 | | 2021 | Other current liabilities | $ | 47 | | | $ | 20 | | | $ | 26 | | | $ | 26 | | Pension obligations | 1,109 | | | 2,051 | | | — | | | — | | Non-pension postretirement benefit obligations | — | | | — | | | 507 | | | 811 | | Unfunded status (net benefit obligation less plan assets) | $ | 1,156 | | | $ | 2,071 | | | $ | 533 | | | $ | 837 | |
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 | 2022 | | 2021 | | | | | | | | | ABO | $ | 10,108 | | | $ | 13,497 | | | | Fair value of net plan assets | 9,427 | | | 12,165 | | | |
Components of Net Periodic Benefit Costs The majority of the 20192022 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%3.24%. The majority of the 20192022 OPEB cost is calculated using an expected long-term rate of return on plan assets of 6.67%6.44% for funded plans and a discount rate of 4.30%3.20%. 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, 20182022, 2021, and 2017.2020. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Pension Benefits | | OPEB | | 2022 | | 2021 | | 2020 | | 2022 | | 2021 | | 2020 | Components of net periodic benefit cost: | | | | | | | | | | | | Service cost | $ | 236 | | | $ | 294 | | | $ | 251 | | | $ | 41 | | | $ | 51 | | | $ | 56 | | Interest cost | 439 | | | 406 | | | 476 | | | 76 | | | 69 | | | 93 | | Expected return on assets | (822) | | | (843) | | | (796) | | | (99) | | | (99) | | | (101) | | Amortization of: | | | | | | | | | | | | Prior service cost (credit) | 2 | | | 2 | | | 3 | | | (19) | | | (25) | | | (76) | | Actuarial loss | 295 | | | 399 | | | 349 | | | 12 | | | 27 | | | 34 | | Curtailment benefits | — | | | — | | | — | | | — | | | — | | | (1) | | Settlement and other charges | — | | | 7 | | | 6 | | | — | | | 1 | | | 1 | | | | | | | | | | | | | | Net periodic benefit cost | $ | 150 | | | $ | 265 | | | $ | 289 | | | $ | 11 | | | $ | 24 | | | $ | 6 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | Pension Benefits | | OPEB | | 2019 | | 2018 | | 2017(a) | | 2019 | | 2018 | | 2017(a) | Components of net periodic benefit cost: | | | | | | | | | | | | Service cost | $ | 357 |
|
| $ | 405 |
|
| $ | 387 |
|
| $ | 93 |
|
| $ | 112 |
|
| $ | 106 |
| Interest cost | 883 |
|
| 802 |
|
| 842 |
|
| 188 |
|
| 175 |
|
| 182 |
| Expected return on assets | (1,225 | ) | | (1,252 | ) | | (1,196 | ) | | (153 | ) | | (173 | ) | | (162 | ) | Amortization of: | | | | | | | | | | | | Prior service cost (credit) | — |
| | 2 |
| | 1 |
| | (179 | ) | | (186 | ) | | (188 | ) | Actuarial loss | 414 |
| | 629 |
| | 607 |
| | 45 |
| | 66 |
| | 61 |
| Settlement and other charges | 17 |
| | 3 |
| | 3 |
| | 1 |
| | 1 |
| | — |
| Contractual termination benefits | 1 |
| | — |
| | — |
| | — |
| | — |
| | — |
| Net periodic benefit cost | $ | 447 |
| | $ | 589 |
| | $ | 644 |
| | $ | (5 | ) | | $ | (5 | ) | | $ | (1 | ) |
__________
| | (a) | FitzPatrick net benefit costs are included for the period after acquisition. |
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 14 — Retirement Benefits 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
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 14 — Retirement Benefits
in Operating and maintenance expense and Property, plant, and equipment, net onin their consolidated financial statements. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | 2022 | $ | 161 | | | $ | 60 | | | $ | (9) | | | $ | 44 | | | $ | 53 | | | $ | 9 | | | $ | 3 | | | $ | 12 | | 2021 | 288 | | | 129 | | | 8 | | | 64 | | | 49 | | | 6 | | | 2 | | | 11 | | 2020 | 296 | | | 114 | | | 5 | | | 64 | | | 70 | | | 15 | | | 7 | | | 14 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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,Consolidated Balance Sheets, 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, 20182022, 2021, and 20172020 for all plans combined. The tables include amounts related to Generation prior to the separation. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Pension Benefits | | OPEB | | 2022 | | 2021 | | 2020 | | 2022 | | 2021 | | 2020 | Changes in plan assets and benefit obligations recognized in AOCI and regulatory assets (liabilities): | | | | | | | | | | | | Current year actuarial (gain) loss | $ | (226) | | | $ | (700) | | | $ | 941 | | | $ | (271) | | | $ | (270) | | | $ | 22 | | Amortization of actuarial loss | (295) | | | (598) | | | (512) | | | (12) | | | (37) | | | (49) | | Separation of Constellation | (2,631) | | | — | | | — | | | (43) | | | — | | | — | | Current year prior service cost (credit) | — | | | — | | | — | | | — | | | — | | | (111) | | Amortization of prior service (cost) credit | (2) | | | (3) | | | (4) | | | 19 | | | 34 | | | 124 | | | | | | | | | | | | | | | | | | | | | | | | | | Curtailments | — | | | — | | | — | | | — | | | — | | | 1 | | Settlements | — | | | (27) | | | (14) | | | — | | | (1) | | | (1) | | | | | | | | | | | | | | Total recognized in AOCI and regulatory assets (liabilities) | $ | (3,154) | | | $ | (1,328) | | | $ | 411 | | | $ | (307) | | | $ | (274) | | | $ | (14) | | | | | | | | | | | | | | Total recognized in AOCI | $ | (2,719) | | | $ | (747) | | | $ | 271 | | | $ | (74) | | | $ | (130) | | | $ | 6 | | Total recognized in regulatory assets (liabilities) | $ | (435) | | | $ | (581) | | | $ | 140 | | | $ | (233) | | | $ | (144) | | | $ | (20) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | 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 |
|
222
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 14 — Retirement Benefits
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, 20192022 and 2018,2021, respectively, for all plans combined: | | | | | | | | | | | | | | | | | | 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 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | Pension Benefits | | OPEB | | 2022 | | 2021 | | 2022 | | 2021 | Prior service cost (credit) | $ | 19 | | | $ | 32 | | | $ | (55) | | | $ | (111) | | Actuarial loss (gain) | 3,611 | | | 6,752 | | | (133) | | | 230 | | Total | $ | 3,630 | | | $ | 6,784 | | | $ | (188) | | | $ | 119 | | | | | | | | | | Total included in AOCI | $ | 873 | | | $ | 3,592 | | | $ | (21) | | | $ | 53 | | Total included in regulatory assets (liabilities) | $ | 2,757 | | | $ | 3,192 | | | $ | (167) | | | $ | 66 | |
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 | | 2022 | | 2021 | | 2020 | Pension plans | | 11.7 |
| | 12.0 |
| | 11.8 |
| Pension plans | | 12.5 | | | 12.4 | | | 12.3 | | OPEB plans: | | | | | | | OPEB plans: | | Benefit Eligibility Age | | 8.7 |
| | 8.8 |
| | 8.8 |
| Benefit Eligibility Age | | 7.9 | | | 7.6 | | | 9.0 | | Expected Retirement | | 9.3 |
| | 9.5 |
| | 9.6 |
| Expected Retirement | | 9.1 | | | 8.8 | | | 10.2 | |
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 yearyears endedDecember 31, 2018,2022 and 2021, Exelon’s mortality assumption was supported by an actuarial experience study of Exelon's plan participants and utilized the IRS's RP–2000 base table projected to 2012 with improvement scale AA and projected thereafter with generational improvement scale BB two-dimensional adjusted to a 0.75% long-term rate reached in 2027. For the year ended December 31, 2019, Exelon's mortality assumption utilizes the Society of Actuaries'SOA 2019 base table (Pri-2012) and MP-2019MP-2021 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, 20192022 and 2018.2021. Assumptions used to determine year-end benefit obligations are the assumptions used to estimate the subsequent year’s net periodic benefit costs.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 14 — Retirement Benefits
| | | | | | | | | | | | | | | Pension Benefits | | OPEB | | Pension Benefits | OPEB | | 2022 | | 2021 | | 2022 | | 2021 | | 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 |
| | | Discount rate(a) | | Discount rate(a) | 5.53 | % | | 2.92 | % | | 5.51 | % | | 2.88 | % | Investment crediting rate(b) | | Investment crediting rate(b) | 5.07 | % |
| 3.75 | % | | N/A | | N/A | Rate of compensation increase | | (c) | | (c) | | (c) | | (c) | Rate of compensation increase | 3.75 | % | | 3.75 | % | | 3.75 | % | | 3.75 | % | 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) | | Mortality table | Pri-2012 table with MP- 2021 improvement scale (adjusted) | | Pri-2012 table with MP- 2021 improvement scale (adjusted) | | Pri-2012 table with MP- 2021 improvement scale (adjusted) | | Pri-2012 table with MP- 2021 improvement scale (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 | | 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 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. |
(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 5.46% - 5.60% and 5.49% - 5.51% for pension and OPEB plans, respectively, as of December 31, 2022 and 2.55% - 3.02% and 2.84% - 2.92% for pension and OPEB plans, respectively, as of December 31, 2021. (b)The investment crediting rate above represents a weighted average rate.
The following assumptions were used to determine the net periodic benefit cost for Exelon for the years ended December 31, 2019, 20182022, 2021 and 2017:2020: | | | | | | | | | | | | | | | | | | | | | Pension Benefits | | Other Postretirement Benefits | | 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) | Investment Crediting Rate | 4.46 | % | (b) | 4.00 | % | (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) | Rate of compensation increase | |
| (d) | | (d) | | (e) | |
| (d) | | (d) | | (e) | 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) | | 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 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Pension Benefits | | OPEB | | 2022 | | 2021 | | 2020 | | 2022 | | 2021 | | 2020 | Discount rate(a) | 3.24 | % | | 2.58 | % | | 3.34 | % | | 3.20 | % | | 2.51 | % | | 3.31 | % | Investment crediting rate(b) | 3.75 | % | | 3.72 | % | | 3.82 | % | | N/A | | N/A | | N/A | Expected return on plan assets(c) | 7.00 | % | | 7.00 | % | | 7.00 | % | | 6.44 | % | | 6.46 | % | | 6.69 | % | Rate of compensation increase | 3.75 | % |
| 3.75 | % |
| 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 - 2019 improvement scale (adjusted) | | Pri-2012 table with MP- 2021 improvement scale (adjusted) | | Pri-2012 table with MP - 2020 improvement scale (adjusted) | | Pri-2012 table with MP - 2019 improvement scale (adjusted) | 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% | | Initial and ultimate rate of 5.00% |
__________ | | (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 2.55%-3.24% and 2.84%-3.20% for pension and OPEB plans, respectively, for the year ended December 31, 2022; 2.11%-2.73% and 2.45%-2.63% for pension and OPEB plans; respectively, for the year ended December 31, 2021; and 3.02%-3.44% and 3.27%-3.40% for pension and OPEB plans, respectively, for the year ended December 31, 2020.
Combined Notes(c)Not applicable to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 14 — Retirement Benefits
pension and OPEB plans that do not have plan assets.
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). For Exelon, in connection with the separation, additional qualified pension contributions of $207 million and $33 million were completed on February 1, 2022 and March 2, 2022, respectively. The following tables provide contributions to the pension and OPEB plans:
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 14 — Retirement Benefits | | | Pension Benefits | | OPEB | | Pension Benefits | | OPEB | | | 2019(a) | | 2018(a) | | 2017(a) | | 2019 | | 2018 | | 2017 | | 2022 | | 2021 | | 2020 | | 2022 | | 2021 | | 2020 | | Exelon | $ | 356 |
|
| $ | 337 |
|
| $ | 341 |
|
| $ | 51 |
| | $ | 46 |
| | $ | 64 |
| Exelon | $ | 570 | | | $ | 343 | | | $ | 306 | | | $ | 42 | | | $ | 63 | | | $ | 40 | | | Generation | 160 |
| | 128 |
| | 137 |
| | 15 |
| | 11 |
| | 11 |
| | ComEd | 72 |
| | 38 |
| | 36 |
| | 5 |
| | 4 |
| | 5 |
| ComEd | 176 | | | 174 | | | 143 | | | 8 | | | 22 | | | 5 | | | PECO | 27 |
| | 28 |
| | 24 |
| | 1 |
| | — |
| | — |
| PECO | 15 | | | 17 | | | 18 | | | 3 | | | 1 | | | — | | | BGE | 34 |
| | 40 |
| | 39 |
| | 14 |
| | 14 |
| | 14 |
| BGE | 48 | | | 57 | | | 56 | | | 20 | | | 24 | | | 22 | | | PHI | 10 |
| | 62 |
| | 67 |
| | 15 |
| | 12 |
| | 32 |
| PHI | 69 | | | 39 | | | 30 | | | 9 | | | 9 | | | 9 | | | Pepco | 2 |
| | 6 |
| | 62 |
| | 12 |
| | 11 |
| | 10 |
| Pepco | 3 | | | 2 | | | 2 | | | 8 | | | 9 | | | 9 | | | DPL | 1 |
| | — |
| | — |
| | — |
| | — |
| | 2 |
| DPL | 1 | | | 1 | | | — | | | — | | | — | | | — | | | ACE | — |
| | 6 |
| | — |
| | 1 |
| | — |
| | 20 |
| ACE | 7 | | | 3 | | | 2 | | | — | | | — | | | — | | |
__________
| | (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 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$20 million beginning in 2020.2023. 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.
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 2023:
| | | | | | | | | | | | | | | | | | | Qualified Pension Plans | | Non-Qualified Pension Plans | | OPEB | Exelon | $ | 20 | | | $ | 48 | | | $ | 47 | | ComEd | 20 | | | 3 | | | 19 | | PECO | — | | | 1 | | | — | | BGE | — | | | 1 | | | 15 | | PHI | — | | | 9 | | | 11 | | Pepco | — | | | 1 | | | 11 | | DPL | — | | | — | | | — | | ACE | — | | | — | | | — | |
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' planned contributions to the qualified pension plans, planned benefit payments to non-qualified pension plans, and planned contributions to other postretirement plans in 2020:
| | | | | | | | | | | | |
| 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 |
|
| — |
|
| — |
|
Estimated Future Benefit Payments Estimated future benefit payments to participants in all of the pension plans and postretirement benefit plans atas of December 31, 20192022 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 | 2023 | $ | 805 | | | $ | 152 | | 2024 | 775 | | | 152 | | 2025 | 789 | | | 152 | | 2026 | 790 | | | 152 | | 2027 | 798 | | | 153 | | 2028 through 2032 | 3,983 | | | 744 | | Total estimated future benefits payments through 2032 | $ | 7,940 | | | $ | 1,505 | |
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. 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, 20192022 were 18.80%(18.69)% and 14.40%(11.36)%, respectively, compared to an expected long-term return assumption of 7.00% and 6.67%6.44%, respectively. Exelon used an EROA of 7.00% and 6.69%6.50% to estimate its 20202023 pension and OPEB costs, respectively. Exelon’s pension and OPEB plan target asset allocations atas of December 31, 20192022 and 20182021 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, 2022 | | December 31, 2021 | Asset Category | Pension Benefits | | OPEB | | Pension Benefits | | OPEB | Asset Category | Pension Benefits | | OPEB | | Pension Benefits | | OPEB | Equity securities | 33 | % | | 46 | % | | 35 | % | | 47 | % | Equity securities | 28 | % | | 44 | % | | 35 | % | | 44 | % | Fixed income securities | 44 | % | | 32 | % | | 37 | % | | 28 | % | Fixed income securities | 44 | % | | 41 | % | | 41 | % | | 41 | % | Alternative investments(a) | 23 | % | | 22 | % | | 28 | % | | 25 | % | Alternative investments(a) | 28 | % | | 15 | % | | 24 | % | | 15 | % | 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, 2019.2022. 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, 2019,2022, 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 14 — 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, 20192022 and 2018:2021: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2022 | | December 31, 2021 | | 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 and cash equivalents | $ | 200 | | | $ | — | | | $ | — | | | $ | — | | | $ | 200 | | | $ | 260 | | | $ | 91 | | | $ | — | | | $ | — | | | $ | 351 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Equities(b) | 1,448 | | | — | | | — | | | 782 | | | 2,230 | | | 2,699 | | | — | | | 2 | | | 1,273 | | | 3,974 | | Fixed income: | | | | | | | | | | | | | | | | | | | | U.S. Treasury and agencies | 986 | | | 178 | | | — | | | — | | | 1,164 | | | 1,002 | | | 176 | | | — | | | — | | | 1,178 | | State and municipal debt | — | | | 44 | | | — | | | — | | | 44 | | | — | | | 47 | | | — | | | — | | | 47 | | Corporate debt(c) | — | | | 1,975 | | | 12 | | | — | | | 1,987 | | | — | | | 2,523 | | | 325 | | | — | | | 2,848 | | Other(b) | — | | | 63 | | | — | | | 744 | | | 807 | | | 43 | | | 161 | | | 12 | | | 301 | | | 517 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Fixed income subtotal | 986 | | | 2,260 | | | 12 | | | 744 | | | 4,002 | | | 1,045 | | | 2,907 | | | 337 | | | 301 | | | 4,590 | | Private equity | — | | | — | | | — | | | 1,169 | | | 1,169 | | | — | | | — | | | — | | | 1,124 | | | 1,124 | | Hedge funds | — | | | — | | | — | | | 760 | | | 760 | | | — | | | — | | | — | | | 774 | | | 774 | | | | | | | | | | | | | | | | | | | | | | Real estate | — | | | — | | | — | | | 821 | | | 821 | | | — | | | — | | | — | | | 760 | | | 760 | | Private credit | — | | | — | | | — | | | 658 | | | 658 | | | — | | | — | | | 130 | | | 603 | | | 733 | | Pension plan assets subtotal | 2,634 | | | 2,260 | | | 12 | | | 4,934 | | | 9,840 | | | 4,004 | | | 2,998 | | | 469 | | | 4,835 | | | 12,306 | | | | | | | | | | | | | | | | | | | | | | OPEB plan assets(a) | | | | | | | | | | | | | | | | | | | | Cash and cash equivalents | 39 | | | — | | | — | | | — | | | 39 | | | 54 | | | 41 | | | — | | | — | | | 95 | | Equities | 305 | | | 1 | | | — | | | 273 | | | 579 | | | 387 | | | 2 | | | — | | | 324 | | | 713 | | Fixed income: | | | | | | | | | | | | | | | | | | | | U.S. Treasury and agencies | 17 | | | 45 | | | — | | | — | | | 62 | | | 14 | | | 44 | | | — | | | — | | | 58 | | State and municipal debt | — | | | 8 | | | — | | | — | | | 8 | | | — | | | 7 | | | — | | | — | | | 7 | | Corporate debt(c) | — | | | 44 | | | — | | | — | | | 44 | | | — | | | 74 | | | — | | | — | | | 74 | | Other | 161 | | | 5 | | | — | | | 187 | | | 353 | | | 223 | | | 4 | | | — | | | 136 | | | 363 | | Fixed income subtotal | 178 | | | 102 | | | — | | | 187 | | | 467 | | | 237 | | | 129 | | | — | | | 136 | | | 502 | | | | | | | | | | | | | | | | | | | | | | Hedge funds | — | | | — | | | — | | | 120 | | | 120 | | | — | | | — | | | — | | | 175 | | | 175 | | Real estate | — | | | — | | | — | | | 106 | | | 106 | | | — | | | — | | | — | | | 86 | | | 86 | | Private credit | — | | | — | | | — | | | 39 | | | 39 | | | — | | | — | | | — | | | 84 | | | 84 | | OPEB plan assets subtotal | 522 | | | 103 | | | — | | | 725 | | | 1,350 | | | 678 | | | 172 | | | — | | | 805 | | | 1,655 | | Total pension and OPEB plan assets(d) | $ | 3,156 | | | $ | 2,363 | | | $ | 12 | | | $ | 5,659 | | | $ | 11,190 | | | $ | 4,682 | | | $ | 3,170 | | | $ | 469 | | | $ | 5,640 | | | $ | 13,961 | |
227 | | | | | | | | | | | | | | | | | | | | | 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 14 — Retirement Benefits
__________
(a)See Note 17—Fair Value of Financial Assets and Liabilities for a description of levels within the fair value hierarchy. | | | | | | | | | | | | | | | | | | | | | 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 |
|
(b)Includes derivative instruments of $11 million and $(2) million for the years ended December 31, 2022 and 2021, respectively, which have total notional amounts of $3,434 million and $3,481 million as of December 31, 2022 and 2021, 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)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 $(44) million as of December 31, 2021. OPEB equities sold short totaled $(18) million as of December 31, 2021. There were no individually held investments sold short in 2022. | | | | | | | | | | | | | | | | | | | | | 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 |
|
(d)Excludes net liabilities of $318 million and $131 million as of December 31, 2022 and 2021, respectively, which include certain derivative assets that have notional amounts of $69 million and $127 million as of December 31, 2022 and 2021, 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.
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, 20192022 and 2018:2021: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Fixed Income | | Equities | | Private Credit | | Total | Pension Assets | | | | | | | | | | | | | | Balance as of January 1, 2022 | | | | | | | $ | 337 | | | $ | 2 | | | $ | 130 | | | $ | 469 | | Actual return on plan assets: | | | | | | | | | | | | | | Relating to assets still held as of the reporting date | | | | | | | (9) | | | — | | | (15) | | | (24) | | Relating to assets sold during the period | | | | | | | (19) | | | — | | | 13 | | | (6) | | Purchases, sales and settlements: | | | | | | | | | | | | | | Purchases | | | | | | | — | | | — | | | 7 | | | 7 | | | | | | | | | | | | | | | | Settlements(a) | | | | | | | (1) | | | — | | | (52) | | | (53) | | Transfers out of Level 3(b) | | | | | | | (296) | | | (2) | | | (83) | | | (381) | | Balance as of December 31, 2022 | | | | | | | $ | 12 | | | $ | — | | | $ | — | | | $ | 12 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | 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, 2021 | | Balance as of January 1, 2021 | | $ | 348 | | | $ | 1 | | | $ | 136 | | | $ | 485 | | 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 | | (12) | | | — | | | 18 | | | 6 | | | Purchases, sales and settlements: | | Purchases, sales and settlements: | | | Purchases | | Purchases | | 10 | | | — | | | 5 | | | 15 | | | Settlements(a) | | Settlements(a) | | (13) | | | — | | | (29) | | | (42) | | Transfers into Level 3 | | Transfers into Level 3 | | 4 | | | 1 | | | — | | | 5 | | Balance as of December 31, 2021 | | Balance as of December 31, 2021 | | $ | 337 | | | $ | 2 | | | $ | 130 | | | $ | 469 | | | | | 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(a)Represents cash settlements only.
(b)In 2022, transfers between Level 1 and Level 2 duringrelate to changes in investment structure for certain investments due to the year ended December 31, 2019 for the pension and OPEB plan assets.separation.
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 typesused to determine the fair value of investments in NDTFs.financial assets. See Cash Equivalents and NDT Fund Investments in Note 17 - Fair Value of Financial Assets and Liabilities for further information. Below outlines the techniques used to fair value the pension and OPEB assets invested in equities, fixed income, derivatives, private credit, private equity, and real estate investments.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 14 — Retirement Benefits 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 is 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 on the underlying securities and are not classified within the fair value hierarchy. These investments can typically 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 has obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, Exelon selectively corroborates 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, 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 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 income models and typically cannot be redeemed until maturity of the term loan. Private credit investments held directly by Exelon are categorized as Level 3 because they are based largely on inputs that are unobservable and utilize complex valuation models. For managed private credit funds, the fair value is determined using a combination of valuation models including
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 14 — Retirement Benefits cost models, market models, and income models and typically cannot be redeemed until maturity of the term loan. Managed private credit fund investments 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 reported by the fund manager and are generally based on independent appraisals of the underlying investments from sources with professional qualifications, typically using a combination of market based comparable data and discounted cash flows. These valuation inputs are 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. 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. Defined Contribution Savings Plan (All Registrants) The Registrants participate in variousa 401(k) defined contribution savings plansplan that areis sponsored by Exelon. The plans areplan is qualified under applicable sections of the IRC and allowallows employees to contribute a portion of their pre-tax and/or after-tax income in accordance with specified guidelines. All Registrants match a percentage of the employee contributions up to certain limits. The following table presents the employer contributions and employer matching contributions to the savings plan for the years ended December 31, 2019, 20182022, 2021, and 2017:2020: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | 2022 | $ | 91 | | | $ | 39 | | | $ | 13 | | | $ | 11 | | | 14 | | | $ | 4 | | | $ | 3 | | | $ | 2 | | 2021 | 90 | | | 35 | | | 12 | | | 12 | | | 14 | | | 4 | | | 3 | | | 2 | | 2020 | 95 | | | 36 | | | 12 | | | 13 | | | 14 | | | 4 | | | 3 | | | 3 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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. Derivative Financial Instruments (All Registrants) The Registrants use derivative instruments to manage commodity price risk and interest rate risk and foreign exchange risk related to ongoing business operations. The Registrants do not execute derivatives for speculative or proprietary trading purposes. 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. AllAt ComEd, derivative economic hedges related to commodities referred to as economic hedges, are recorded at fair value through earnings at Generation and are offset by a corresponding regulatory asset or liabilityliability. At Exelon, derivative economic hedges related to interest rates are recorded at ComEd. fair value and offsets are recorded to Electric operating revenues or Interest expense based on the activity the transaction is economically hedging.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 15 — Derivative Financial Instruments 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 At Exelon, derivative hedges that qualify and liabilities requires theare designated as cash flow hedges are recorded at fair value of derivative instrumentsand offsets are recorded 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 referencing 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 that 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.AOCI.
Generation’s and ComEd’s use of cash collateral is generally unrestricted unless Generation or ComEd areis downgraded below investment grade. Cash collateral held by PECO, BGE, Pepco, DPL, and ACE must be deposited in an unaffiliated major U.S. commercial bank or foreign bank with a U.S. branch office that meetmeets certain qualifications.
Commodity Price Risk (All Registrants) Each of theThe Registrants employ established policies and procedures to manage their risks associated with market fluctuations in commodity prices by entering into physical and financial derivative contracts, including swaps, futures, forwards, options and short-term and long-term commitments to purchase and sell energy and commodity products. The Registrants believe these instruments, which are either determined to be non-derivative or classified as economic hedges, mitigate exposure to fluctuations in commodity prices.
Generation. To the extent the amount of energy Generation produces differs from the amount of energy it has contracted to sell, Exelon and Generation are exposed to market fluctuations in the prices of electricity, fossil fuels and other commodities. Within Exelon, Generation has the most exposure to commodity price risk. As such, Generation uses a variety of derivative and non-derivative instruments to manage the commodity price risk of its electric generation facilities, including power and gas sales, fuel and power purchases, natural gas transportation and pipeline capacity agreements and other energy-related products marketed and purchased. To manage these risks, Generation may enter into fixed-price derivative or non-derivative contracts to hedge the variability in future cash flows from expected sales of power and gas and purchases of power and fuel. The objectives for executing such hedges include fixing the price for a portion of anticipated future electricity sales at a level that provides an acceptable return. Generation is also exposed to differences between the locational settlement prices of certain economic hedges and the hedged generating units. This price difference is actively managed through other instruments which include derivative congestion products, whose changes in fair value are recognized in earnings each period, and auction revenue rights, which are accounted for on an accrual basis.
Additionally, Generation is exposed to certain market risks through its proprietary trading activities. The proprietary trading activities are a complement to Generation’s energy marketing portfolio but represent a small portion of Generation’s overall energy marketing activities and are subject to limits established by Exelon’s RMC.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 15 — Derivative Financial Instruments
Utility Registrants.hedges. The Utility Registrants procure electric and natural gas supply through a competitive procurement process approved by each of the respective state utility commissions. The Utility Registrants’ hedging programs are intended to reduce exposure to energy and natural 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. | Gas | 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, 2022 and 2021.
The fair value of derivative economic hedges is presented in Other current assets and current and noncurrent Mark-to-market derivative liabilities in Exelon's and ComEd's Consolidated Balance Sheets. Interest Rate and Other Risk (Exelon) Exelon Corporate uses a combination of fixed-rate and variable-rate debt to manage interest rate exposure. Exelon Corporate may utilize interest rate derivatives to lock in rate levels in anticipation of future financings, which are typically designated as cash flow hedges. In addition, Exelon Corporate may also utilize interest rate
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 15 — Derivative Financial Instruments
The following table providesswaps to manage interest rate exposure and manage potential fluctuations in Electric operating revenues at the corporate level in consolidation, which are directly correlated to yields on U.S. Treasury bonds under ComEd's distribution formula rate. These interest rate swaps are accounted for as economic hedges. A hypothetical 50 basis point change in the interest rates associated with Exelon's interest rate swaps as of December 31, 2022 would result in an immaterial impact to Exelon's Consolidated Net Income. Below is a summary of the derivative fair valueinterest rate hedge balances recorded by Exelon, Generation and ComEd as of December 31, 20192022. Exelon had no interest rate hedge activity in 2021.
| | | | | | | | | | | | | | | | | | December 31, 2022 | Derivatives Designated as Hedging Instruments | | Economic Hedges | | Total | | | | | | | Other deferred debits (noncurrent assets) | $ | 6 | | | $ | 5 | | | $ | 11 | | Total derivative assets | 6 | | | 5 | | | 11 | | Mark-to-market derivative liabilities (current liabilities) | — | | | (3) | | | (3) | | Mark-to-market derivative liabilities (noncurrent liabilities) | (4) | | | — | | | (4) | | Total mark-to-market derivative liabilities | (4) | | | (3) | | | (7) | | Total mark-to-market derivative net assets | $ | 2 | | | $ | 2 | | | $ | 4 | |
Cash Flow Hedges (Interest Rate Risk) For derivative instruments that qualify and 2018:are designated as cash flow hedges, the changes in fair value each period are initially recorded in AOCI and reclassified into earnings when the underlying transaction affects earnings. In 2022, Exelon Corporate entered into $635 million notional of 5-year maturity floating-to-fixed swaps and $635 million notional of 10-year maturity floating-to-fixed swaps, for a total of $1,270 million as of December 31, 2022. Exelon had no swaps designated as cash flow hedges as of December 31, 2021. In January 2023, Exelon Corporate entered into $115 million notional of 5-year maturity floating-to-fixed swaps and $115 million notional of 10-year maturity floating-to-fixed swaps, for a total of $230 million designated as cash flow hedges. The total notional of the swaps issued as of the balance sheet date and subsequently are $1,500 million. The AOCI derivative gain is $2 million as of December 31, 2022. There were no amounts reclassified to Net Income in 2022. See Note 21 – Changes in Accumulated Other Comprehensive Income for additional information. Exelon had no swaps designated as cash flow hedges as of December 31, 2021. Economic Hedges (Interest Rate and Other Risk) Exelon Corporate executes derivative instruments to mitigate exposure to fluctuations in interest rates but for which the fair value or cash flow hedge elections were not made. For derivatives intended to serve as economic hedges, fair value is recorded on the balance sheet and changes in fair value each period are recognized in earnings or as a regulatory asset or liability, if regulatory requirements are met, each period. Exelon Corporate enters into floating-to-fixed interest rate cap swaps to manage a portion of interest rate exposure in connection with existing borrowings. In 2022, Exelon Corporate entered into $1,000 million notional of 18-month maturity floating-to-fixed interest rate cap swaps and $850 million notional of 6-month maturity floating-to-fixed interest rate cap swaps, for a total of $1,850 million notional of floating-to-fixed interest rate cap swaps as of December 31, 2022. Exelon had no swaps as of December 31, 2021. Additionally, to manage potential fluctuations in Electric operating revenues related to ComEd's distribution formula rate, Exelon Corporate enters into 30-year constant maturity treasury interest rate (Corporate 30-year treasury) swaps. As of December 31, 2022, Exelon Corporate entered into $500 million notional of calendar year 2023 Corporate 30-year treasury swaps. In January and February 2023, Exelon Corporate entered into a total of $1,500 million notional of calendar year 2023 Corporate 30-year treasury swaps. The total notional of the swaps issued as of the balance sheet date and subsequently are $2,000 million.
232 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exelon | | Generation | | ComEd | December 31, 2019 | Total Derivatives | | Economic Hedges | | Proprietary Trading | | Collateral
(a)(b) | | Netting(a) | | Subtotal | | Economic Hedges | Mark-to-market derivative assets (current assets) | $ | 675 |
| | $ | 3,506 |
| | $ | 72 |
| | $ | 287 |
| | $ | (3,190 | ) | | $ | 675 |
| | $ | — |
| Mark-to-market derivative assets (noncurrent assets) | 508 |
| | 1,238 |
| | 25 |
| | 122 |
| | (877 | ) | | 508 |
| | — |
| Total mark-to-market derivative assets | 1,183 |
| | 4,744 |
|
| 97 |
|
| 409 |
| | (4,067 | ) | | 1,183 |
| | — |
| Mark-to-market derivative liabilities (current liabilities) | (236 | ) | | (3,713 | ) | | (38 | ) | | 357 |
| | 3,190 |
| | (204 | ) | | (32 | ) | Mark-to-market derivative liabilities (noncurrent liabilities) | (380 | ) | | (1,140 | ) | | (11 | ) | | 163 |
| | 877 |
| | (111 | ) | | (269 | ) | Total mark-to-market derivative liabilities | (616 | ) | | (4,853 | ) |
| (49 | ) |
| 520 |
| | 4,067 |
| | (315 | ) | | (301 | ) | Total mark-to-market derivative net assets (liabilities) | $ | 567 |
| | $ | (109 | ) |
| $ | 48 |
|
| $ | 929 |
| | $ | — |
| | $ | 868 |
| | $ | (301 | ) | | | | | | | | | | | | | | | December 31, 2018 | | | | | | | | | | | | | | Mark-to-market derivative assets (current assets) | $ | 801 |
| | $ | 3,505 |
| | $ | 105 |
| | $ | 121 |
| | $ | (2,930 | ) | | $ | 801 |
| | $ | — |
| Mark-to-market derivative assets (noncurrent assets) | 445 |
| | 1,266 |
| | 41 |
| | 51 |
| | (913 | ) | | 445 |
| | — |
| Total mark-to-market derivative assets | 1,246 |
| | 4,771 |
| | 146 |
| | 172 |
| | (3,843 | ) | | 1,246 |
| | — |
| Mark-to-market derivative liabilities (current liabilities) | (473 | ) | | (3,429 | ) | | (74 | ) | | 125 |
| | 2,931 |
| | (447 | ) | | (26 | ) | Mark-to-market derivative liabilities (noncurrent liabilities) | (474 | ) | | (1,203 | ) | | (20 | ) | | 60 |
| | 912 |
| | (251 | ) | | (223 | ) | Total mark-to-market derivative liabilities | (947 | ) | | (4,632 | ) | | (94 | ) | | 185 |
| | 3,843 |
| | (698 | ) | | (249 | ) | Total mark-to-market derivative net assets (liabilities) | $ | 299 |
| | $ | 139 |
| | $ | 52 |
| | $ | 357 |
| | $ | — |
| | $ | 548 |
| | $ | (249 | ) |
_________
| | (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. |
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 yearsyear ended December 31, 2019, 2018 and 2017,2022, Exelon and GenerationCorporate recognized the following net pre-tax commodity mark-to-market gains (losses)losses which are also locatedrecognized in the Net fair value changes related to derivatives line in theExelon's Consolidated Statements of Cash Flows.
| | | | | | | | | | | | | |
| | 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 | ) |
In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on Generation’s owned and contracted generation positions that have not been hedged. Generation hedges commodity price risk on a ratable basis over three-year periods. As of 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.
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, 2018 and 2017, net pre-tax commodity mark-to-market gains (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 and Generation utilize interest ratehad no swaps which are treated as economic hedges, to manage their interest rate exposure. On July 1, 2018, Exelon de-designated its fair value hedges related to interest rate risk 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, which are treated as economic hedges. The notional amounts were $231 million and $268 million at December 31, 2019 and 2018, respectively.
The mark-to-market derivative assets and liabilities as of December 31, 2019 and 2018 and the mark-to-market gains (losses) for the years ended December 31, 2019, 20182021 and 2017 were not material for Exelon and Generation.2020.
| | | | | | | | | | | | | | | Loss | | | | | Income Statement Location | | 2022 | | | | | Electric operating revenues | | $ | 2 | | | | | | Interest expense | | 3 | | | | | | Total | | $ | 5 | | | | | |
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. 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 figures in the tables below exclude credit risk exposure from individual retail counterparties, nuclear fuel procurement contracts and exposure through RTOs, ISOs, NYMEX, ICE, NASDAQ, NGX and Nodal commodity exchanges.
| | | | | | | | | | | | | | | | | | | | Rating as of 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 |
| | — |
| | $ | — |
|
| | | | | 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 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, 2019,2022, the Utility Registrants’ counterparty credit risk with suppliers was immaterial.
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 formamount of cash or credit supportcollateral held with thresholds contingent upon Generation’s credit rating from eachexternal counterparties by Exelon, ComEd, BGE, PHI, Pepco, DPL, and ACE was $297 million, $77 million, $23 million, $197 million, $26 million, $121 million, and $50 million, respectively, which is recorded in Other current liabilities in Exelon's, ComEd's, BGE's, PHI's, Pepco's, DPL's, and ACE's Consolidated Balance Sheets. The amount for PECO was not material as 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:
| | | | | | | | | | | | As of December 31, | Credit-Risk Related Contingent Features | | 2019 | | 2018 | Gross fair value of derivative contracts containing this feature(a) | | $ | (956 | ) | | $ | (1,723 | ) | Offsetting fair value of in-the-money contracts under master netting arrangements(b) | | 649 |
| | 1,105 |
| Net fair value of derivative contracts containing this feature(c) | | $ | (307 | ) | | $ | (618 | ) |
__________
| | (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. |
December 31, 2022. As of December 31, 20192021, the amounts for ComEd and 2018,DPL were $41 million and $43 million, respectively. The amounts for Exelon, PECO, BGE, PHI, Pepco, and Generation posted or held the following amountsACE were not material as of cash collateral and letters of credit on derivative contracts with external counterparties, after giving consideration to offsetting derivative and non-derivative positions under master netting agreements. | | | | | | | | | | | | 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 |
|
Generation entered into supply forward contracts with certain utilities, including PECO and BGE, with one-sided collateral postings only from Generation. If market prices fall below the benchmark price levels in these contracts, the utilities are not required to post collateral. However, when market prices rise above the benchmark price levels, counterparty suppliers, including Generation, are required to post collateral once certain unsecured credit limits are exceeded.
Utility RegistrantsDecember 31, 2021.
The Utility Registrants’ electric supply procurement contracts do not contain provisions that would require them to post collateral. PECO’s, BGE’s, and DPL’s natural gas procurement contracts contain provisions that could require PECO, BGE, and DPL to post collateral in the form of cash or credit support, which vary by contract and counterparty, with thresholds contingent upon PECO’s, BGE,BGE's, and DPL’s credit rating. As of December 31, 2019,2022, PECO, BGE, and DPL were not required to post collateral for any of these agreements. If PECO, BGE, or DPL lost their investment grade credit rating as of December 31, 2019,2022, they could have been required to post incremental collateral to itstheir counterparties of $44$71 million, $50$119 million, and $11$15 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. 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 use their respective credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 16 — Debt and Credit Agreements 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, 20192022 and 2018:2021: | | | 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, | | Credit Facility Size as of December 31, | | Outstanding Commercial Paper as of December 31, | | Average Interest Rate on Commercial Paper Borrowings as of December 31, | Commercial Paper Issuer | 2019(a)(b)(c) | | 2018(a)(b)(c) | | 2019 | | 2018 | | 2019 | | 2018 | Commercial Paper Issuer | 2022(a) | | 2021(a) | | 2022 | | 2021 | | 2022 | | 2021 | Exelon(d) | $ | 9,000 |
| | $ | 9,000 |
| | $ | 870 |
| | $ | 89 |
| | 2.25 | % | | 2.15 | % | | Generation | 5,300 |
| | 5,300 |
| | 320 |
| | — |
| | 1.84 | % | | 1.96 | % | | Exelon(b) | | Exelon(b) | $ | 4,000 | | | $ | 3,700 | | | $ | 1,938 | | | $ | 599 | | | 4.77 | % | | 0.35 | % | ComEd | 1,000 |
| | 1,000 |
| | 130 |
| | — |
| | 2.38 | % | | 2.14 | % | ComEd | 1,000 | | | 1,000 | | | 427 | | | — | | | 4.71 | % | | — | % | PECO | 600 |
| | 600 |
| | — |
| | — |
| | 2.39 | % | | 2.24 | % | PECO | 600 | | | 600 | | | 239 | | | — | | | 4.71 | % | | — | % | BGE | 600 |
| | 600 |
| | 76 |
| | 35 |
| | 2.46 | % | | 2.18 | % | BGE | 600 | | | 600 | | | 409 | | | 130 | | | 4.81 | % | | 0.37 | % | PHI | 900 |
| | 900 |
| | 208 |
| | 54 |
| | N/A |
| | N/A |
| | PHI(c) | | PHI(c) | 900 | | | 900 | | | 414 | | | 469 | | | 4.78 | % | | 0.35 | % | Pepco | 300 |
| | 300 |
| | 82 |
| | 40 |
| | 2.56 | % | | 2.24 | % | Pepco | 300 | | (d) | 300 | | | 299 | | | 175 | | | 4.79 | % | | 0.33 | % | DPL | 300 |
| | 300 |
| | 56 |
| | — |
| | 2.02 | % | | 2.07 | % | DPL | 300 | | (d) | 300 | | | 115 | | | 149 | | | 4.76 | % | | 0.36 | % | ACE | 300 |
| | 300 |
| | 70 |
| | 14 |
| | 2.43 | % | | 2.21 | % | ACE | 300 | | (d) | 300 | | | — | | | 145 | | | — | % | | 0.35 | % |
__________ | | (a) | Excludes $1,400(a)Excludes credit facility agreements arranged at minority and community banks. See below for additional information. (b)Includes revolving credit agreements at Exelon Corporate with a maximum program size of $900 million and $600 million as of December 31, 2022 and December 31, 2021, respectively. Exelon Corporate had $449 million in outstanding commercial paper as of December 31, 2022 and no outstanding commercial paper as of December 31, 2021. (c)Represents the consolidated amounts of Pepco, DPL, and ACE. (d)The standard maximum program size for revolving credit facilities is $300 million each for Pepco, DPL and ACE based on the credit agreements in place. However, the facilities at Pepco, DPL, and ACE have 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. As of December 23, 2022, this ability was utilized to increase Pepco's program size to $400 million. As a result, the program sizes for DPL and ACE were decreased to $250 million each, which prevents the aggregate amount of outstanding short-term debt from potentially exceeding the $900 million limit.
|
| | (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 16 — Debt and Credit Agreements
AtAs of December 31, 2019,2022, 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, 2022 | | | | | | | | | 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 |
| | — |
| | 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 | | $ | 4,000 | | | $ | — | | | $ | 8 | | | $ | 3,992 | | | $ | 2,054 | | ComEd | Syndicated Revolver | | 1,000 |
| | — |
| | 2 |
| | 998 |
| | 868 |
| ComEd | Syndicated Revolver | | 1,000 | | | — | | | 5 | | | 995 | | | 568 | | PECO | Syndicated Revolver | | 600 |
| | — |
| | — |
| | 600 |
| | 600 |
| PECO | Syndicated Revolver | | 600 | | | — | | | — | | | 600 | | | 361 | | BGE | Syndicated Revolver | | 600 |
| | — |
| | — |
| | 600 |
| | 524 |
| BGE | Syndicated Revolver | | 600 | | | — | | | — | | | 600 | | | 191 | | PHI | Syndicated Revolver | | 900 |
| | — |
| | — |
| | 900 |
| | 692 |
| | PHI(d) | | PHI(d) | Syndicated Revolver | | 900 | | | — | | | — | | | 900 | | | 486 | | Pepco | Syndicated Revolver | | 300 |
| | — |
| | — |
| | 300 |
| | 218 |
| Pepco | Syndicated Revolver | | 300 | | | — | | | — | | | 300 | | | 1 | | DPL | Syndicated Revolver | | 300 |
| | — |
| | — |
| | 300 |
| | 244 |
| DPL | Syndicated Revolver | | 300 | | | — | | | — | | | 300 | | | 185 | | ACE | Syndicated Revolver | | 300 |
| | — |
| | — |
| | 300 |
| | 230 |
| ACE | Syndicated Revolver | | 300 | | | — | | | — | | | 300 | | | 300 | |
__________ | | (a) | 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. |
| | (b) | 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. |
(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)Excludes credit facility agreements arranged at minority and community banks. See below for additional information. (c)Includes $900 million aggregate bank commitment related to Exelon Corporate. Exelon Corporate had $3 million outstanding letters of credit as of December 31, 2022. Exelon Corporate had $448 million in available capacity to support additional commercial paper as of December 31, 2022. (d)Represents the consolidated amounts of Pepco, DPL, and ACE. The following table reflects the Registrants' credit facility agreements arranged at minority and community banks as of December 31, 2022 and 2021. These are excluded from the Maximum Program Size and Aggregate Bank Commitment amounts within the two tables above and the facilities are solely used to issue letters of credit. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Aggregate Bank Commitments | | Outstanding Letters of Credit | Borrower | | 2022(a) | | 2021 | | 2022 | | 2021 | Exelon(b) | | $ | 140 | | | $ | 98 | | | $ | 10 | | | $ | 8 | | ComEd | | 40 | | | 33 | | | 7 | | | 5 | | PECO | | 40 | | | 33 | | | 1 | | | 1 | | BGE | | 15 | | | 8 | | | 2 | | | 2 | | PHI(c) | | 45 | | | 24 | | | — | | | — | | Pepco | | 15 | | | 8 | | | — | | | — | | DPL | | 15 | | | 8 | | | — | | | — | | ACE | | 15 | | | 8 | | | — | | | — | | __________(a)These facilities were entered into on October 7, 2022 and expire on October 6, 2023. (b)Represents the consolidated amounts of ComEd, PECO, BGE, Pepco, DPL, and ACE. (c)Represents the consolidated amounts of Pepco, DPL, and ACE. 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:
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 16 — 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)Borrower | | Includes $3 million and Aggregate Bank Commitment | | $4 millionInterest Rate | 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, and900 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 at December 31, 2019:
| | | | | | | | | | | 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 |
__________ | | SOFR plus 1.275 | % | (a)ComEd | 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. |
1,000 | | | SOFR plus 1.000 | % | (b)PECO | 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. |
600 | | | SOFR plus 0.900 | % | (c)BGE | Bilateral credit agreements solely support the issuance of letters of credit and do not back Generation's commercial paper program. | 600 | | | SOFR plus 0.900 | % | Pepco | | 300 | | | SOFR plus 1.075 | % | DPL | | 300 | | | SOFR plus 1.000 | % | ACE | | 300 | | | SOFR plus 1.075 | % |
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-basedSOFR-based rate, plus an adder based upon the particular Registrant’s credit rating. The adders for the prime based borrowings and LIBOR-basedSOFR-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 | | SOFR-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 SOFR-based borrowings, respectively.
If any registrant loses its investment grade rating, the maximum adders for prime rate borrowings and LIBOR-basedSOFR-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 14, 2022 and will expire on March 16, 2023. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to SOFR plus 0.65% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Exelon's Consolidated Balance Sheets within Short-term borrowings. On March 31, 2021, Exelon Corporate entered into a 364-day term loan agreement for $150 million with a variable interest rate of LIBOR plus 0.65% and an expiration date of March 30, 2022. Exelon Corporate repaid the term loan on March 30, 2022. 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 had an expiration date of January 23, 2023. Pursuant to the loan agreement, loans made thereunder bore interest at a variable rate equal to SOFR plus 0.75% until July 23, 2022 and a rate of SOFR plus 0.975% thereafter. All indebtedness pursuant to the loan agreement was unsecured. On August 11, 2022, Exelon Corporate made a partial repayment of $575 million on the term loan. On October 11, 2022, the remaining $575 million outstanding balance was repaid in conjunction with the $500 million 18-month term loan that was entered into on October 7, 2022. On October 4, 2022, ComEd entered into a 364-day term loan agreement for $150 million with a variable rate equal to SOFR plus 0.75% and an expiration date of October 3, 2023. The proceeds from this loan were used to repay outstanding commercial paper obligations. The loan agreement is reflected in Exelon's and ComEd's Consolidated Balance Sheets within Short-term borrowings. The balance of the loan was repaid on January 13, 2023 in conjunction with the $400 million and $575 million First Mortgage Bond agreements that were entered into on January 3, 2023. 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
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 16 — Debt and Credit Agreements 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, 20192022 and December 31, 2018,2021, $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.Sheets.
Long-Term Debt
The following tables present the outstanding long-term debt at the Registrants as of December 31, 2022 and 2021: Exelon | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Maturity Date | | December 31, | | Rates | | 2022 | | 2021 | Long-term debt | | | | | | | | | | | | | | | | | | | | First mortgage bonds(a)(b) | 1.05 | % | - | 7.90 | % | | 2023 - 2052 | | $ | 22,651 | | | $ | 20,751 | | Senior unsecured notes | 2.75 | % | - | 7.60 | % | | 2025 - 2052 | | 8,324 | | | 6,324 | | Unsecured notes | 2.25 | % | - | 6.35 | % | | 2023 - 2052 | | 4,250 | | | 4,000 | | | | | | | | | | | | Notes payable and other | 1.64 | % | - | 7.49 | % | | 2025 - 2053 | | 86 | | | 86 | | Junior subordinated notes | | | 3.50 | % | | 2022 | | — | | | 1,150 | | | | | | | | | | | | Long-term software licensing agreement | 2.30 | % | - | 3.95 | % | | 2024 - 2025 | | 25 | | | 9 | | Unsecured tax-exempt bonds | 4.00 | % | - | 4.05 | % | | 2024 | | 33 | | | 143 | | Medium-terms notes (unsecured) | | | 7.72 | % | | 2027 | | 10 | | | 10 | | Loan agreement | 2.00 | % | | 5.15 | % | | 2023 - 2024 | | 1,400 | | | 50 | | Total long-term debt | | | | | | | 36,779 | | | 32,523 | | Unamortized debt discount and premium, net | | | | | | | (74) | | | (70) | | Unamortized debt issuance costs | | | | | | | (257) | | | (220) | | Fair value adjustment | | | | | | | 626 | | | 669 | | | | | | | | | | | | Long-term debt due within one year(c) | | | | | | | (1,802) | | | (2,153) | | Long-term debt | | | | | | | $ | 35,272 | | | $ | 30,749 | | Long-term debt to financing trusts(d) | | | | | | | | | | Subordinated debentures to ComEd Financing III | | | 6.35 | % | | 2033 | | $ | 206 | | | $ | 206 | | Subordinated debentures to PECO Trust III | 7.38 | % | - | 9.50 | % | | 2028 | | 81 | | | 81 | | Subordinated debentures to PECO Trust IV | | | 5.75 | % | | 2033 | | 103 | | | 103 | | | | | | | | | | | | Total 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)On January 3, 2023, ComEd entered into a purchase agreement of First Mortgage Bonds of $400 million and $575 million at 4.90% and 5.30% due on February 1, 2033 and February 1, 2053, respectively. The closing date of the issuance occurred on January 10, 2023. (c)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%. (d)Amounts owed to these financing trusts are recorded as Long-term debt to financing trusts within Exelon’s Consolidated Balance Sheets.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 16 — Debt and Credit Agreements
ComEd
Long-Term Debt
The following tables present the outstanding long-term debt at the Registrants as of December 31, 2019 and 2018:
Exelon
| | | | | | | | | | | | | | | | | | | | | | Maturity Date | | December 31, | | Rates | | 2019 | | 2018 | Long-term debt | | | | | | | | | | First mortgage bonds(a) | 1.70 | % | - | 7.90 | % | | 2020 - 2049 | | $ | 17,486 |
| | $ | 16,496 |
| Senior unsecured notes | 2.45 | % | - | 7.60 | % | | 2020 - 2046 | | 10,685 |
| | 11,285 |
| Unsecured notes | 2.40 | % | - | 6.35 | % | | 2021 - 2049 | | 3,300 |
| | 2,900 |
| 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 |
| Junior subordinated notes |
| | 3.50 | % | | 2022 | | 1,150 |
| | 1,150 |
| Long-term software licensing agreement | | | 3.95 | % | | 2024 | | 55 |
| | 73 |
| 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 | | | 5.55 | % | | 2023 | | 40 |
| | 59 |
| Loan Agreement | | | 2.00 | % | | 2023 | | 50 |
| | 50 |
| 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 | | | | | | | 35,560 |
| | 34,911 |
| Unamortized debt discount and premium, net | | | | | | | (72 | ) | | (66 | ) | Unamortized debt issuance costs | | | | | | | (214 | ) | | (216 | ) | Fair value adjustment | | | | | | | 765 |
| | 795 |
| Long-term debt due within one year | | | | | | | (4,710 | ) | | (1,349 | ) | Long-term debt | | | | | | | $ | 31,329 |
| | $ | 34,075 |
| Long-term debt to financing trusts(c) | | | | | | | | | | 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 IV | | | 5.75 | % | | 2033 | | 103 |
| | 103 |
| Total long-term debt to financing trusts | | | | | | | 390 |
| | 390 |
| Unamortized debt issuance costs | | | | | | | — |
| | — |
| Long-term debt to financing trusts | | | | | | | $ | 390 |
| | $ | 390 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Maturity Date | | December 31, | | Rates | | 2022 | | 2021 | Long-term debt | | | | | | | | | | First mortgage bonds(a)(b) | 2.20 | % | - | 6.45 | % | | 2024 - 2052 | | $ | 10,629 | | | $ | 9,879 | | Other | | | 7.49 | % | | 2053 | | 8 | | | 8 | | Total long-term debt | | | | | | | 10,637 | | | 9,887 | | Unamortized debt discount and premium, net | | | | | | | (27) | | | (27) | | Unamortized debt issuance costs | | | | | | | (92) | | | (87) | | | | | | | | | | | | Long-term debt | | | | | | | $ | 10,518 | | | $ | 9,773 | | Long-term debt to financing trust(c) | | | | | | | | | | 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 | |
__________ | | (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, are subject to the lien of its mortgage indenture.
(b)On January 3, 2023, ComEd entered into a purchase agreement of First Mortgage Bonds of $400 million and $575 million at 4.90% and 5.30% due on February 1, 2033 and February 1, 2053, respectively. The closing date of the issuance occurred on January 10, 2023.
(c)Amount owed to this financing trust is recorded as Long-term debt to financing trust within ComEd’s Consolidated Balance Sheets.
PECO
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Maturity Date | | December 31, | | Rates | | 2022 | | 2021 | Long-term debt | | | | | | | | | | First mortgage bonds(a) | 2.80 | % | - | 5.95 | % | | 2025 - 2052 | | $ | 4,625 | | | $ | 4,200 | | Loan agreement | | | 2.00 | % | | 2023 | | 50 | | | 50 | | Total long-term debt | | | | | | | 4,675 | | | 4,250 | | Unamortized debt discount and premium, net | | | | | | | (24) | | | (20) | | Unamortized debt issuance costs | | | | | | | (39) | | | (33) | | Long-term debt due within one year | | | | | | | (50) | | | (350) | | Long-term debt | | | | | | | $ | 4,562 | | | $ | 3,847 | | Long-term debt to financing trusts(b) | | | | | | | | | | Subordinated debentures to PECO Trust III | 7.38 | % | - | 9.50 | % | | 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.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 16 — Debt and Credit Agreements
BGE
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Maturity Date | | December 31, | | Rates | | 2022 | | 2021 | Long-term debt | | | | | | | | | | | | | | | | | | | | Unsecured notes | 2.25 | % | - | 6.35 | % | | 2023 - 2052 | | $ | 4,250 | | | $ | 4,000 | | Total long-term debt | | | | | | | 4,250 | | | 4,000 | | Unamortized debt discount and premium, net | | | | | | | (13) | | | (12) | | Unamortized debt issuance costs | | | | | | | (30) | | | (27) | | Long-term debt due within one year | | | | | | | (300) | | | (250) | | Long-term debt | | | | | | | $ | 3,907 | | | $ | 3,711 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
GenerationPHI
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Maturity Date | | December 31, | | Rates | | 2022 | | 2021 | Long-term debt | | | | | | | | | | First mortgage bonds(a) | 1.05 | % | - | 7.90 | % | | 2023 - 2052 | | $ | 7,397 | | | $ | 6,672 | | Senior unsecured notes | | | 7.45 | % | | 2032 | | 185 | | | 185 | | Unsecured tax-exempt bonds | 4.00 | % | - | 4.05 | % | | 2024 | | 33 | | | 143 | | Medium-terms notes (unsecured) | | | 7.72 | % | | 2027 | | 10 | | | 10 | | Finance leases | | | 5.59 | % | | 2025 - 2030 | | 76 | | | 74 | | Other(b) | 7.28 | % | - | 7.49 | % | | 2022 | | — | | | — | | Total long-term debt | | | | | | | 7,701 | | | 7,084 | | Unamortized debt discount and premium, net | | | | | | | 4 | | | 4 | | Unamortized debt issuance costs | | | | | | | (47) | | | (36) | | Fair value adjustment | | | | | | | 462 | | | 495 | | Long-term debt due within one year | | | | | | | (591) | | | (399) | | Long-term debt | | | | | | | $ | 7,529 | | | $ | 7,148 | |
_________ (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 zero and less than $1 million as of December 31, 2022 and December 31, 2021, respectively. Pepco | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Maturity Date | | December 31, | | Rates | | 2022 | | 2021 | Long-term debt | | | | | | | | | | First mortgage bonds(a) | 2.32 | % | - | 7.90 | % | | 2024 - 2052 | | $ | 3,775 | | | $ | 3,350 | | Unsecured tax-exempt bonds | | | 1.70 | % | | 2022 | | — | | | 110 | | Finance leases | | | 5.59 | % | | 2025 - 2029 | | 25 | | | 26 | | Other(b) | 7.28 | % | - | 7.49 | % | | 2022 | | — | | | — | | Total long-term debt | | | | | | | 3,800 | | | 3,486 | | Unamortized debt discount and premium, net | | | | | | | 2 | | | 2 | | Unamortized debt issuance costs | | | | | | | (51) | | | (43) | | Long-term debt due within one year | | | | | | | (4) | | | (313) | | Long-term debt | | | | | | | $ | 3,747 | | | $ | 3,132 | | ________(a)Substantially all of Pepco's assets are subject to the lien of its mortgage indenture. (b)The amount in the Other category was zero and less than $1 million as of December 31, 2022 and December 31, 2021, respectively. | | | | | | | | | | | | | | | | | | | | | | 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 |
|
239
ComEd
| | | | | | | | | | | | | | | | | | | | | | Maturity Date | | December 31, | | Rates | | 2019 | | 2018 | Long-term debt | | | | | | | | | | First mortgage bonds(a) | 2.55 | % | - | 6.45 | % | | 2020 - 2049 | | $ | 8,578 |
| | $ | 8,179 |
| Notes payable and other |
|
| | 7.49 | % | | 2053 | | 8 |
| | 8 |
| Total long-term debt | | | | | | | 8,586 |
| | 8,187 |
| Unamortized debt discount and premium, net | | | | | | | (27 | ) | | (23 | ) | Unamortized debt issuance costs | | | | | | | (68 | ) | | (63 | ) | Long-term debt due within one year | | | | | | | (500 | ) | | (300 | ) | Long-term debt | | | | | | | $ | 7,991 |
| | $ | 7,801 |
| 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 |
|
__________
| | (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. |
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 16 — Debt and Credit Agreements
DPL
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 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Maturity Date | | December 31, | | Rates | | 2022 | | 2021 | Long-term debt | | | | | | | | | | First mortgage bonds(a) | 1.05 | % | - | 4.27 | % | | 2023 - 2052 | | $ | 1,874 | | | $ | 1,749 | | Unsecured tax-exempt bonds | 4.00 | % | - | 4.05 | % | | 2024 | | 33 | | | 33 | | Medium-terms notes (unsecured) | | | 7.72 | % | | 2027 | | 10 | | | 10 | | Finance leases | | | 5.39 | % | | 2025 - 2030 | | 32 | | | 29 | | Total long-term debt | | | | | | | 1,949 | | | 1,821 | | Unamortized debt discount and premium, net(b) | | | | | | | — | | | — | | Unamortized debt issuance costs | | | | | | | (11) | | | (11) | | Long-term debt due within one year | | | | | | | (584) | | | (83) | | Long-term debt | | | | | | | $ | 1,354 | | | $ | 1,727 | |
__________ | | (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(a)Substantially all of DPL's assets are subject to the lien of its mortgage indenture.
(b)The amount in the Unamortized debt discount and premium, net category was less than $1 million as of December 31, 2022 and 2021. ACE | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Maturity Date | | December 31, | | Rates | | 2022 | | 2021 | Long-term debt | | | | | | | | | | First mortgage bonds(a) | 2.25 | % | - | 5.80 | % | | 2024 - 2052 | | $ | 1,748 | | | $ | 1,573 | | Finance leases | | | 5.59 | % | | 2025 - 2030 | | 19 | | | 19 | | Total long-term debt | | | | | | | 1,767 | | | 1,592 | | Unamortized debt discount and premium, net | | | | | | | (1) | | | (1) | | Unamortized debt issuance costs | | | | | | | (9) | | | (9) | | Long-term debt due within one year | | | | | | | (3) | | | (3) | | Long-term debt | | | | | | | $ | 1,754 | | | $ | 1,579 | |
__________ (a)Substantially all of ACE's assets are subject to the lien of its mortgage indenture. Long-term debt maturities at the Registrants in the periods 2023 through 2027 and thereafter are as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Year | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | 2023 | $ | 1,802 | | | $ | — | | | $ | 50 | | | $ | 300 | | | $ | 591 | | | $ | 4 | | | $ | 584 | | | $ | 3 | | 2024 | 1,317 | | | 250 | | | — | | | — | | | 564 | | | 405 | | | 6 | | | 153 | | 2025 | 1,414 | | | — | | | 350 | | | — | | | 242 | | | 5 | | | 84 | | | 153 | | 2026 | 1,613 | | | 500 | | | — | | | 350 | | | 13 | | | 4 | | | 6 | | | 3 | | 2027 | 1,021 | | | 350 | | | — | | | — | | | 21 | | | 3 | | | 15 | | | 3 | | Thereafter | 30,002 | | (a) | 9,743 | | (b) | 4,459 | | (c) | 3,600 | | | 6,270 | | | 3,379 | | | 1,254 | | | 1,452 | | Total | $ | 37,169 | | | $ | 10,843 | | | $ | 4,859 | | | $ | 4,250 | | | $ | 7,701 | | | $ | 3,800 | | | $ | 1,949 | | | $ | 1,767 | |
__________ (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. Long-Term Debt to Affiliates In connection with the debt obligations assumed by Exelon as part of the Constellation merger, Exelon and subsidiaries of Generation (former Constellation subsidiaries) entered into intercompany loan agreements that mirror the terms and amounts of the third-party debt obligations of Exelon, resulting in intercompany notes | | | | | | | | | | | | | | | | | | | | | | 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 |
|
240
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 16 — Debt and Credit Agreements
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, | | Rates | | 2019 | | 2018 | 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 |
| Total long-term debt | | | | | | | 2,897 |
|
| 2,751 |
| Unamortized debt discount and premium, net | | | | | | | 2 |
| | 2 |
| Unamortized debt issuance costs | | | | | | | (35 | ) | | (34 | ) | Long-term debt due within one year | | | | | | | (2 | ) | | (15 | ) | Long-term debt | | | | | | | $ | 2,862 |
|
| $ | 2,704 |
|
__________
| | (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. |
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 16 — Debt and Credit Agreements
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
(Dollars in millions, except per share data unless otherwise noted)
Note 16 — Debt and Credit Agreements
Long-term debt maturitiesreceivable at Exelon Corporate from Generation. As of December 31, 2021, Exelon Corporate had $319 million 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, 2019,2022, the Registrants are in compliance with debt covenants, except for Antelope Valley's nonrecourse debt event of default as discussed below. Nonrecourse Debt
Exelon and Generation have issued nonrecourse debt financing, in which approximately $2.8 billion of generating assets have been pledged as collateral at December 31, 2019. 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.covenants.
Antelope Valley Solar Ranch One. In December 2011, the DOE Loan Programs Office issued a guarantee for up to $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, approximately $485 million was outstanding. In addition, Generation has issued letters of credit to support its equity investment in the project. As of December 31, 2019, Generation had $38 million in letters of credit outstanding related to the project. In 2017, Generation’s interests in Antelope Valley were also contributed to and are pledged as collateral for the EGR IV financing structure 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. 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. 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, $447 million was outstanding.
In addition, Continental Wind entered into a $131 million letter of credit facility and $10 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, the Continental Wind letter of credit facility had $115 million in letters of credit outstanding related to the project.
In 2017, Generation’s interests in Continental Wind were contributed to EGRP. Refer to Note 22 - Variable Interest Entities for additional information on EGRP.
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 bears interest at a fixed rate of 4.11% payable semi-annually. As of December 31, 2019, $106 million was outstanding.
In 2017, Generation’s interests in Renewable Power Generation were contributed to EGRP. Refer to Note 22 - Variable Interest Entities for additional information on EGRP.
SolGen. 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 rate 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 collateral for the EGR IV financing structure referenced below.
ExGen Renewables IV. In November 2017, EGR IV, an indirect subsidiary of Exelon and Generation, entered into an $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 proceeds 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 IV 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 is in default, it is nonrecourse to EGR IV. However, if in the future Antelope Valley were to file for bankruptcy protection as a result 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. See Note 22 - Variable Interest Entities for additional information on EGRP.
17. 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. 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, 20192022 and 2018.2021. The Registrants have no financial liabilities classified as Level 1.1 or measured using the NAV practical expedient. 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.
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 | | | | December 31, 2019 | | December 31, 2018 | | December 31, 2022 | | December 31, 2021 | | | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value | | | Level 2 | | Level 3 | | Total | | Level 2 | | Level 3 | | Total | | Level 2 | | Level 3 | | Total | | Level 2 | | Level 3 | | Total | Long-Term Debt, including amounts due within one year(a)
| Long-Term Debt, including amounts due within one year(a)
| Long-Term Debt, including amounts due within one year(a) | Exelon | | $ | 36,039 |
| | $ | 37,453 |
| | $ | 2,580 |
| | $ | 40,033 |
| | $ | 35,424 |
| | $ | 33,711 |
| | $ | 2,158 |
| | $ | 35,869 |
| Exelon | | $ | 37,074 | | | $ | 29,902 | | | $ | 2,327 | | | $ | 32,229 | | | $ | 32,902 | | | $ | 34,897 | | | $ | 2,217 | | | $ | 37,114 | | 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 |
| ComEd | | 10,518 | | | 9,006 | | | — | | | 9,006 | | | 9,773 | | | 11,305 | | | — | | | 11,305 | | PECO | | 3,405 |
| | 3,868 |
| | 50 |
| | 3,918 |
| | 3,084 |
| | 3,157 |
| | 50 |
| | 3,207 |
| PECO | | 4,612 | | | 3,864 | | | 50 | | | 3,914 | | | 4,197 | | | 4,740 | | | 50 | | | 4,790 | | BGE | | 3,270 |
| | 3,649 |
| | — |
| | 3,649 |
| | 2,876 |
| | 2,950 |
| | — |
| | 2,950 |
| BGE | | 4,207 | | | 3,613 | | | — | | | 3,613 | | | 3,961 | | | 4,406 | | | — | | | 4,406 | | PHI | | 6,563 |
| | 5,902 |
| | 1,164 |
| | 7,066 |
| | 6,259 |
| | 5,436 |
| | 665 |
| | 6,101 |
| PHI | | 8,120 | | | 4,507 | | | 2,277 | | | 6,784 | | | 7,547 | | | 5,970 | | | 2,167 | | | 8,137 | | Pepco | | 2,864 |
| | 3,198 |
| | 388 |
| | 3,586 |
| | 2,719 |
| | 2,901 |
| | 196 |
| | 3,097 |
| Pepco | | 3,751 | | | 2,229 | | | 1,205 | | | 3,434 | | | 3,445 | | | 3,201 | | | 975 | | | 4,176 | | DPL | | 1,567 |
| | 1,408 |
| | 311 |
| | 1,719 |
| | 1,494 |
| | 1,303 |
| | 193 |
| | 1,496 |
| DPL | | 1,938 | | | 1,164 | | | 458 | | | 1,622 | | | 1,810 | | | 1,426 | | | 552 | | | 1,978 | | ACE | | 1,327 |
| | 1,026 |
| | 464 |
| | 1,490 |
| | 1,188 |
| | 987 |
| | 275 |
| | 1,262 |
| ACE | | 1,757 | | | 909 | | | 614 | | | 1,523 | | | 1,582 | | | 1,091 | | | 641 | | | 1,732 | | Long-Term Debt to Financing Trusts(a)
| | Long-Term Debt to Financing Trusts | | Long-Term Debt to Financing Trusts | Exelon | | $ | 390 |
| | $ | — |
| | $ | 428 |
| | $ | 428 |
| | $ | 390 |
| | $ | — |
| | $ | 400 |
| | $ | 400 |
| Exelon | | $ | 390 | | | $ | — | | | $ | 384 | | | $ | 384 | | | $ | 390 | | | $ | — | | | $ | 470 | | | $ | 470 | | ComEd | | 205 |
| | — |
| | 227 |
| | 227 |
| | 205 |
| | — |
| | 209 |
| | 209 |
| ComEd | | 205 | | | — | | | 204 | | | 204 | | | 205 | | | — | | | 248 | | | 248 | | PECO | | 184 |
| | — |
| | 201 |
| | 201 |
| | 184 |
| | — |
| | 191 |
| | 191 |
| PECO | | 184 | | | — | | | 180 | | | 180 | | | 184 | | | — | | | 222 | | | 222 | | 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 16 — 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 10 — Leases for finance lease 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 | 2 | Exelon, Generation | The carrying amount is derived from a contract with the DOE to provide for disposal of SNF from Generation’s nuclear generating stations. 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’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. |
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, 20192022 and 2018:2021. The Registrants have no financial assets or liabilities measured using the NAV practical expedient: Exelon | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | As of December 31, 2022 | | As of December 31, 2021 | | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total | Assets | | | | | | | | | | | | | | | | Cash equivalents(a) | $ | 664 | | | $ | — | | | $ | — | | | $ | 664 | | | $ | 524 | | | $ | — | | | $ | — | | | $ | 524 | | Rabbi trust investments | | | | | | | | | | | | | | | | Cash equivalents | 62 | | | — | | | — | | | 62 | | | 60 | | | — | | | — | | | 60 | | Mutual funds | 49 | | | — | | | — | | | 49 | | | 60 | | | — | | | — | | | 60 | | Fixed income | — | | | 7 | | | — | | | 7 | | | — | | | 10 | | | — | | | 10 | | Life insurance contracts | — | | | 58 | | | 40 | | | 98 | | | — | | | 61 | | | 37 | | | 98 | | Rabbi trust investments subtotal | 111 | | | 65 | | | 40 | | | 216 | | | 120 | | | 71 | | | 37 | | | 228 | | | | | | | | | | | | | | | | | | Interest rate derivative assets | | | | | | | | | | | | | | | | Derivatives designated as hedging instruments | — | | | 6 | | | — | | | 6 | | | — | | | — | | | — | | | — | | Economic hedges | — | | | 5 | | | — | | | 5 | | | — | | | — | | | — | | | — | | Interest rate derivative assets subtotal | — | | | 11 | | | — | | | 11 | | | — | | | — | | | — | | | — | | Total assets | 775 | | | 76 | | | 40 | | | 891 | | | 644 | | | 71 | | | 37 | | | 752 | | Liabilities | | | | | | | | | | | | | | | | Mark-to-market derivative liabilities | — | | | — | | | (84) | | | (84) | | | — | | | — | | | (219) | | | (219) | | Interest rate derivative liabilities | | | | | | | | | | | | | | | | Derivatives designated as hedging instruments | — | | | (4) | | | — | | | (4) | | | — | | | — | | | — | | | — | | Economic hedges | — | | | (3) | | | — | | | (3) | | | — | | | — | | | — | | | — | | Interest rate derivative liabilities subtotal | — | | | (7) | | | — | | | (7) | | | — | | | — | | | — | | | — | | Deferred compensation obligation | — | | | (75) | | | — | | | (75) | | | — | | | (131) | | | — | | | (131) | | Total liabilities | — | | | (82) | | | (84) | | | (166) | | | — | | | (131) | | | (219) | | | (350) | | Total net assets (liabilities) | $ | 775 | | | $ | (6) | | | $ | (44) | | | $ | 725 | | | $ | 644 | | | $ | (60) | | | $ | (182) | | | $ | 402 | |
__________ (a)Excludes cash of $345 million and $464 million as of December 31, 2022 and 2021, respectively, and restricted cash of $81 million and $49 million as of December 31, 2022 and 2021, respectively, and includes long-term restricted cash of $117 million and $44 million as of December 31, 2022 and 2021, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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 |
|
243
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
ComEd, PECO, and BGE
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ComEd | | PECO | | BGE | As of December 31, 2022 | 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) | $ | 392 | | | $ | — | | | $ | — | | | $ | 392 | | | $ | 10 | | | $ | — | | | $ | — | | | $ | 10 | | | $ | 23 | | | $ | — | | | $ | — | | | $ | 23 | | Rabbi trust investments | | | | | | | | | | | | | | | | | | | | | | | | Mutual funds | — | | | — | | | — | | | — | | | 7 | | | — | | | — | | | 7 | | | 7 | | | — | | | — | | | 7 | | Life insurance contracts | — | | | — | | | — | | | — | | | — | | | 15 | | | — | | | 15 | | | — | | | — | | | — | | | — | | Rabbi trust investments subtotal | — | | | — | | | — | | | — | | | 7 | | | 15 | | | — | | | 22 | | | 7 | | | — | | | — | | | 7 | | | | | | | | | | | | | | | | | | | | | | | | | | Total assets | 392 | | | — | | | — | | | 392 | | | 17 | | | 15 | | | — | | | 32 | | | 30 | | | — | | | — | | | 30 | | Liabilities | | | | | | | | | | | | | | | | | | | | | | | | Mark-to-market derivative liabilities(b) | — | | | — | | | (84) | | | (84) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Deferred compensation obligation | — | | | (8) | | | — | | | (8) | | | — | | | (7) | | | — | | | (7) | | | — | | | (4) | | | — | | | (4) | | Total liabilities | — | | | (8) | | | (84) | | | (92) | | | — | | | (7) | | | — | | | (7) | | | — | | | (4) | | | — | | | (4) | | Total net assets (liabilities) | $ | 392 | | | $ | (8) | | | $ | (84) | | | $ | 300 | | | $ | 17 | | | $ | 8 | | | $ | — | | | $ | 25 | | | $ | 30 | | | $ | (4) | | | $ | — | | | $ | 26 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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 | |
__________ (a)ComEd excludes cash of $42 million and $105 million as of December 31, 2022 and 2021, respectively, and restricted cash of $77 million and $42 million as of December 31, 2022 and 2021, respectively, and includes long-term restricted cash of $117 million and $43 million as of December 31, 2022 and 2021, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. PECO excludes cash of $58 million and $35 million as of December 31, 2022 and 2021, respectively. BGE excludes cash of $43 million and $51 million as of December 31, 2022 and 2021, respectively, and restricted cash of $1 million and $4 million as of December 31, 2022 and 2021, respectively. (b)The Level 3 balance consists of the current and noncurrent liability of $5 million and $79 million, respectively, as of December 31, 2022, and $18 million and $201 million, respectively, as of December 31, 2021 related to floating-to-fixed energy swap contracts with unaffiliated suppliers. PHI, Pepco, DPL, and ACE | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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 |
|
244
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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 17 — Fair Value of Financial Assets and Liabilities
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | As of December 31, 2022 | | As of December 31, 2021 | PHI | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total | Assets | | | | | | | | | | | | | | | | Cash equivalents(a) | $ | 205 | | | $ | — | | | $ | — | | | $ | 205 | | | $ | 110 | | | $ | — | | | $ | — | | | $ | 110 | | Rabbi trust investments | | | | | | | | | | | | | | | | Cash equivalents | 59 | | | — | | | — | | | 59 | | | 59 | | | — | | | — | | | 59 | | Mutual funds | 11 | | | — | | | — | | | 11 | | | 14 | | | — | | | — | | | 14 | | Fixed income | — | | | 7 | | | — | | | 7 | | | — | | | 10 | | | — | | | 10 | | Life insurance contracts | — | | | 22 | | | 39 | | | 61 | | | — | | | 27 | | | 35 | | | 62 | | Rabbi trust investments subtotal | 70 | | | 29 | | | 39 | | | 138 | | | 73 | | | 37 | | | 35 | | | 145 | | Total assets | 275 | | | 29 | | | 39 | | | 343 | | | 183 | | | 37 | | | 35 | | | 255 | | Liabilities | | | | | | | | | | | | | | | | Deferred compensation obligation | — | | | (14) | | | — | | | (14) | | | — | | | (18) | | | — | | | (18) | | Total liabilities | — | | | (14) | | | — | | | (14) | | | — | | | (18) | | | — | | | (18) | | Total net assets | $ | 275 | | | $ | 15 | | | $ | 39 | | | $ | 329 | | | $ | 183 | | | $ | 19 | | | $ | 35 | | | $ | 237 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Pepco | | DPL | | ACE | As of December 31, 2022 | 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) | $ | 51 | | | $ | — | | | $ | — | | | $ | 51 | | | $ | 121 | | | $ | — | | | $ | — | | | $ | 121 | | | $ | 1 | | | $ | — | | | $ | — | | | $ | 1 | | Rabbi trust investments | | | | | | | | | | | | | | | | | | | | | | | | Cash equivalents | 59 | | | — | | | — | | | 59 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Life insurance contracts | — | | | 22 | | | 38 | | | 60 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Rabbi trust investments subtotal | 59 | | | 22 | | | 38 | | | 119 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Total assets | 110 | | | 22 | | | 38 | | | 170 | | | 121 | | | — | | | — | | | 121 | | | 1 | | | — | | | — | | | 1 | | Liabilities | | | | | | | | | | | | | | | | | | | | | | | | Deferred compensation obligation | — | | | (1) | | | — | | | (1) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total liabilities | — | | | (1) | | | — | | | (1) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Total net assets | $ | 110 | | | $ | 21 | | | $ | 38 | | | $ | 169 | | | $ | 121 | | | $ | — | | | $ | — | | | $ | 121 | | | $ | 1 | | | $ | — | | | $ | — | | | $ | 1 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
__________ | | (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 |
(a)PHI excludes cash of $165 million and $100 million as of December 31, 2022 and 2021, respectively, and restricted cash of $3 million and $3 million as of December 31, 2022 and 2021, respectively. Pepco excludes cash of $45 million and $34 million as of December 31, 2022 and 2021, respectively, and restricted cash of $3 million and $3 million as of December 31, 2022 and 2021, respectively. DPL excludes cash of $31 million and $28 million as of December 31, 2022 and 2021, respectively. ACE excludes cash of $71 million and $29 million as of December 31, 2022 and 2021, respectively.
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
counterparties totaled $57 million, $224 million and $76 million allocated to Level 1, Level 2 andReconciliation of Level 3 mark-to-market derivatives, 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 equity and real estate investments of approximately $85 million, $166 million, $375 million and $427 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 millionas of December 31, 2019. Changes were immaterial in fair value, cumulative adjustments and impairments for the year ended December 31, 2019.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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 17 — Fair Value of Financial Assets and Liabilities
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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 17 — 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 | 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) | $ | 38 |
| | $ | — |
| | $ | — |
| | $ | 38 |
| | $ | 16 |
| | $ | — |
| | $ | — |
| | $ | 16 |
| | $ | 23 |
| | $ | — |
| | $ | — |
| | $ | 23 |
| Rabbi trust investments | | | | | | |
|
| | | | | | | |
|
| | | | | | | |
|
| Cash equivalents | 41 |
| | — |
| | — |
| | 41 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Fixed income | — |
| | 5 |
| | — |
| | 5 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Life insurance contracts | — |
| | 22 |
| | 37 |
| | 59 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Rabbi trust investments subtotal | 41 |
|
| 27 |
|
| 37 |
|
| 105 |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
| Total assets | 79 |
|
| 27 |
|
| 37 |
|
| 143 |
|
| 16 |
|
| — |
|
| — |
|
| 16 |
|
| 23 |
|
| — |
|
| — |
|
| 23 |
| Liabilities | | | | | | | | | | | | | | | | | | | | | | | | Deferred compensation obligation | — |
| | (3 | ) | | — |
| | (3 | ) | | — |
| | (1 | ) | | — |
| | (1 | ) | | — |
| | — |
| | — |
| | — |
| Total liabilities | — |
|
| (3 | ) |
| — |
|
| (3 | ) |
| — |
|
| (1 | ) |
| — |
|
| (1 | ) |
| — |
|
| — |
|
| — |
|
| — |
| Total net assets | $ | 79 |
|
| $ | 24 |
|
| $ | 37 |
|
| $ | 140 |
|
| $ | 16 |
|
| $ | (1 | ) |
| $ | — |
|
| $ | 15 |
|
| $ | 23 |
|
| $ | — |
|
| $ | — |
|
| $ | 23 |
|
__________
| | (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, 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 Financial 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, 20192022 and 2018:2021: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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 |
| | $ | — |
|
| | | | | | | | | | | | | | | | | | | Exelon | | ComEd | | PHI and Pepco | For the year ended December 31, 2022 | Total | | Mark-to-Market Derivatives | | Life Insurance Contracts | Balance as of December 31, 2021 | $ | (182) | | | $ | (219) | | | $ | 35 | | Total realized / unrealized gains (losses) | | | | | | Included in net income(a) | 5 | | | — | | | 5 | | Included in regulatory assets/liabilities | 135 | | | 135 | | (b) | — | | Purchases, sales, and settlements | | | | | | Settlements | — | | | — | | | — | | | | | | | | Transfers out of Level 3 | (2) | | | — | | | — | | Balance as of December 31, 2022 | $ | (44) | | | $ | (84) | | (c) | $ | 40 | | 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, 2022 | 5 | | | $ | — | | | $ | 5 | |
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
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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) |
|
| |
|
|
|
|
|
| | | | | | | Included in net income | (101 | ) | | — |
|
| (105 | ) | (a) | (105 | ) | | — |
| | 4 |
| | — |
| Included in noncurrent payables to affiliates | — |
| | (1 | ) |
| — |
| | (1 | ) | | — |
| | — |
| | 1 |
| Included in regulatory assets/liabilities | 6 |
| | — |
| | — |
| | — |
| | 7 |
| (b) | — |
| | (1 | ) | Change in collateral | (5 | ) | | — |
|
| (5 | ) | | (5 | ) | | — |
| | — |
| | — |
| Purchases, sales, issuances and settlements |
|
| |
|
|
| |
|
| | | | | | | Purchases | 226 |
| | 36 |
|
| 190 |
| | 226 |
| | — |
| | — |
| | — |
| Sales | (4 | ) | | — |
|
| (4 | ) |
| (4 | ) | | — |
| | — |
| | — |
| Settlements | (123 | ) | | (140 | ) |
| 5 |
|
| (135 | ) | | — |
| | 12 |
| | — |
| Transfers into Level 3 | (22 | ) | | — |
|
| (22 | ) | (c) | (22 | ) | | — |
| | — |
| | — |
| Transfers out of Level 3 | (36 | ) | | — |
|
| (36 | ) | (c) | (36 | ) | | — |
| | — |
| | — |
| 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 |
| | $ | — |
| | $ | — |
| | $ | — |
|
| | | | | | | | | | | | | | | | | | | Exelon | | ComEd | | PHI and Pepco | For the year ended December 31, 2021 | Total | | Mark-to-Market Derivatives | | Life Insurance Contracts | Balance as of December 31, 2020 | $ | (267) | | | $ | (301) | | | $ | 34 | | Total realized / unrealized gains (losses) | | | | | | Included in net income(a) | 3 | | | — | | | 3 | | Included in regulatory assets/liabilities | 82 | | | 82 | | (b) | — | | Purchases, sales, and settlements | | | | | | Settlements | (2) | | | — | | | (2) | | Transfers into Level 3 | 2 | | | — | | | — | | | | | | | | Balance as of December 31, 2021 | $ | (182) | | | $ | (219) | | | $ | 35 | | 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, 2021 | $ | 3 | | | $ | — | | | $ | 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(a)Classified in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income. (b)Includes $136 million of increases in fair value and a decrease for realized losses due to settlements of $1 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. |
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, 20192022. Includes $62 million of increases in fair value and 2018: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.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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 17 — Fair Valuethe current and noncurrent asset was effectively zero as of Financial AssetsDecember 31, 2022. The balance consists of a current 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 | ) | | — |
|
noncurrent liability of $5 million and $79 million, respectively, as of December 31, 2022.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). The trust fund investments have been established to satisfy Generation’s and CENG'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 are 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 of the underlying securities 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.
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 have 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 corroborate 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 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 and include unobservable inputs such as cost, operating results, and discounted cash flows. 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. 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. 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. 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 valued by investment managers on a periodic basis using pricing models that use independent appraisals from sources with professional qualifications. These valuation inputs are not highly observable. 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.
Generation evaluated its NDT portfolios for the existence of significant concentrations of credit risk as of December 31, 2019. 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, there were no significant concentrations (generally defined as greater than 10 percent) of risk in Generation's NDT assets.
See Note 9 — Asset Retirement Obligations for additional information on the NDT fund investments. See Note 14 — 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
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 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
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
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. Interest Rate Derivatives (Exelon) Exelon may utilize fixed-to-floating or floating-to-fixed interest rate swaps as a means to manage interest rate risk. These interest rate swaps are typically accounted for as economic hedges. In addition, Exelon may utilize interest rate derivatives to lock in interest rate levels in anticipation of future financings. These interest rate derivatives are typically designated as cash flow hedges. Exelon determines the current fair value by calculating the net present value of expected payments and receipts under the swap agreement, based on and discounted by the market's expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk and other market parameters. As these inputs are based on observable data and valuations of similar instruments, the interest rate swaps are categorized as Level 2 in the fair value hierarchy. See Note 15 — Derivative Financial Instrumentsfor additional information on mark-to-market derivatives. 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. 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 nonperformance risk in the valuation of derivative contracts categorized in Level 2 and 3, including both historical and current market data in its 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’s Level 3 balance generally consists of forward sales and purchases of power and natural gas and certain transmission congestion contracts. Generation 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, Generation 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 and $0.54 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 15 — Derivative Financial Instruments for additional information.Delivery under the contracts began in June 2012. The fair value of these swaps has been designated as a Level 3 valuation due to the long tenure of the positions and the 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. prices. See Note 15 — Derivative Financial Instruments for additional information on mark-to-market derivatives. The following table discloses the significant unobservable inputs to the forward curve used to value mark-to-market derivatives: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Type of trade | | Fair Value as of December 31, 2022 | | Fair Value as of December 31, 2021 | | Valuation Technique | | Unobservable Input | | 2022 Range & Arithmetic Average | | 2021 Range & Arithmetic Average | Mark-to-market derivatives | | $ | (84) | | | $ | (219) | | | Discounted Cash Flow | | Forward power price(a) | | $ | 34.78 | | - | $ | 75.71 | | $ | 48.44 | | | $ | 28.65 | | - | $ | 47.10 | | $ | 33.96 | |
__________ (a)An increase to the forward power price would increase the fair value.
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
The following table presents the significant inputs to the forward curve used to value these positions:
| | | | | | | | | | | | | | | | | | | 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) | 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. |
The inputs listed above, which are as of the balance sheet date, would have a direct impact on the fair values of the above instruments if they were adjusted. The significant unobservable inputs used in the fair value measurement of Generation’s commodity derivatives are forward commodity prices and for options is price volatility. Increases (decreases) in the forward commodity price in isolation would result in significantly higher (lower) fair values for long positions (contracts that give Generation the obligation or option to purchase a commodity), with offsetting impacts to short positions (contracts that give Generation the obligation or right to sell a commodity). Increases (decreases) in volatility would increase (decrease) the value for the holder of the option (writer of the option). Generally, a change in the estimate of forward commodity prices is unrelated to a change in the estimate of volatility of prices. An increase to the reserves listed above would decrease the fair value of the positions. An increase to the heat rate or renewable 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 18 — Commitments and Contingencies
18. 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, 2019:2022: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Description | Exelon | | PHI | | Pepco | | DPL | | ACE | Total commitments | $ | 513 | | | $ | 320 | | | $ | 120 | | | $ | 89 | | | $ | 111 | | Remaining commitments(a) | 52 | | | 45 | | | 39 | | | 4 | | | 2 | |
| | | | | | | | | | | | | | | | | | | | | 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. 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, 27 MWs of new generation were developed and Exelon and Generation have incurred costs of $120 million. 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 ofcompleted the three required 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 bewas conducted in 2022.
2022 and did not result in a purchase agreement. On December 14, 2022, the DEPSC issued an order recognizing DPL’s completion of all obligations under this merger commitment.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 18 — Commitments and Contingencies
Commercial Commitments (All Registrants). The Registrants'Registrants' commercial commitments as of December 31, 2019,2022, representing commitments potentially triggered by future events were as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Expiration within | Exelon | Total | | 2023 | | 2024 | | 2025 | | 2026 | | 2027 | | 2028 and beyond | Letters of credit | $ | 19 | | | $ | 17 | | | $ | 2 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | Surety bonds(a) | 205 | | | 203 | | | 2 | | | — | | | — | | | — | | | — | | Financing trust guarantees | 378 | | | — | | | — | | | — | | | — | | | — | | | 378 | | Guaranteed lease residual values(b) | 29 | | | — | | | 6 | | | 6 | | | 5 | | | 4 | | | 8 | | Total commercial commitments | $ | 631 | | | $ | 220 | | | $ | 10 | | | $ | 6 | | | $ | 5 | | | $ | 4 | | | $ | 386 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ComEd | | | | | | | | | | | | | | Letters of credit | $ | 12 | | | $ | 10 | | | $ | 2 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | Surety bonds(a) | 46 | | | 44 | | | 2 | | | — | | | — | | | — | | | — | | Financing trust guarantees | 200 | | | — | | | — | | | — | | | — | | | — | | | 200 | | Total commercial commitments | $ | 258 | | | $ | 54 | | | $ | 4 | | | $ | — | | | $ | — | | | $ | — | | | $ | 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) | 2 | | | 2 | | | — | | | — | | | — | | | — | | | — | | Total commercial commitments | $ | 4 | | | $ | 4 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | | | | | | | | | | | | | | PHI | | | | | | | | | | | | | | | | | | | | | | | | | | | | Surety bonds(a) | $ | 96 | | | $ | 96 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | Guaranteed lease residual values(b) | 29 | | | — | | | 6 | | | 6 | | | 5 | | | 4 | | | 8 | | Total commercial commitments | $ | 125 | | | $ | 96 | | | $ | 6 | | | $ | 6 | | | $ | 5 | | | $ | 4 | | | $ | 8 | | | | | | | | | | | | | | | | Pepco | | | | | | | | | | | | | | | | | | | | | | | | | | | | Surety bonds(a) | $ | 84 | | | $ | 84 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | Guaranteed lease residual values(b) | 10 | | | — | | | 2 | | | 2 | | | 2 | | | 1 | | | 3 | | Total commercial commitments | $ | 94 | | | $ | 84 | | | $ | 2 | | | $ | 2 | | | $ | 2 | | | $ | 1 | | | $ | 3 | | | | | | | | | | | | | | | | DPL | | | | | | | | | | | | | | | | | | | | | | | | | | | | Surety bonds(a) | $ | 7 | | | $ | 7 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | Guaranteed lease residual values(b) | 12 | | | — | | | 3 | | | 2 | | | 2 | | | 2 | | | 3 | | Total commercial commitments | $ | 19 | | | $ | 7 | | | $ | 3 | | | $ | 2 | | | $ | 2 | | | $ | 2 | | | $ | 3 | | | | | | | | | | | | | | | | ACE | | | | | | | | | | | | | | Surety bonds(a) | $ | 5 | | | $ | 5 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | Guaranteed lease residual values(b) | 7 | | | — | | | 1 | | | 2 | | | 1 | | | 1 | | | 2 | | Total commercial commitments | $ | 12 | | | $ | 5 | | | $ | 1 | | | $ | 2 | | | $ | 1 | | | $ | 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 |
|
249
_________
| | (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 18 — Commitments and Contingencies
__________
| | (b) | (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 $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)
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, the current liability limit per incident is $13.9 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 that the fair value of an incident. Effective Januarycertain 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 2017,to 8 years. The maximum potential obligation at the required amountend 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 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’s share of this secondary layerminimum lease term would be approximately $2.9 billion, however any amounts payable under this secondary layer would be capped at $434$68 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 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 EDFguaranteed by Exelon 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 companyPHI, 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. Generation's portion of the annual distribution declared by NEIL is estimated to be $136$22 million for 2019, and was $58, $28 million, and $60$18 million for 2018is guaranteed by Pepco, DPL, and 2017,ACE, 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’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)
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) 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 2030 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’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 extended during 2017 to provide for the reimbursement of SNF storage costs through December 31, 2019. Generation expects the terms for each 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 accepting the SNF.
Under the settlement agreements, Generation has received cumulative cash reimbursements for costs incurred as follows:
| | | | | | | | | | Total | | Net(a) | Cumulative cash reimbursements
| $ | 1,288 |
| | $ | 1,113 |
|
__________
| | (a) | Total after considering amounts due to co-owners of certain nuclear stations and to the former owner of Oyster Creek. |
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 18 — Commitments and Contingencies
As of December 31, 2019 and 2018, the amount of SNF storage costs for which reimbursement has been or will be requested from the DOEHistorically, payments under the DOE settlement agreementsguarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is as follows:remote.
| | | | | | | | | | December 31, 2019 | | December 31, 2018 | DOE receivable - current(a) | $ | 249 |
| | $ | 124 |
| DOE receivable - noncurrent(b) | 30 |
| | 15 |
| Amounts owed to co-owners(a)(c) | (37 | ) | | (17 | ) |
__________
| | (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. |
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, 2019 and 2018:
| | | | | | | | | | 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. |
| | (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, 2019 was 1.551% for the deferred amount transferred from ComEd and 1.879% for the deferred FitzPatrick amount.
The following table summarizes sites for which Exelon and Generation do 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 Federalfederal and state environmental laws, the Registrants are generally liable for the costs of remediating environmental contamination of property now or formerly owned by them and of property contaminated by hazardous substances generated by them. The Registrants own or lease a number of real estate parcels, including parcels on which their operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws. In addition, the Registrants are currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and may be subject to additional proceedings in the future. Unless otherwise disclosed, the Registrants cannot reasonably estimate whether they will incur significant liabilities for additional investigation and remediation costs at these or additional sites identified by the Registrants, environmental agencies
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 thesesome sites, there are additional PRPs that may share responsibility for the ultimate remediation of each location. •ComEd has 2120 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 2025.2031. •PECO has 86 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 2022.2024. •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 2021.2025. •DPL has 1 site that is currently under study and the required cost at the site is not expected to be material. The historical nature of the MGP and gas purification sites and the fact that many of the sites have been buried and built over, impacts the ability to determine a precise estimate of the ultimate costs prior to initial sampling and determination of the exact scope and method of remedial activity. Management determines its best estimate of remediation costs using all available information at the time of each study, including probabilistic and deterministic modeling for ComEd and PECO, and the remediation standards currently required by the applicable state environmental agency. Prior to completion of any significant clean up, each site remediation plan is approved by the appropriate state environmental agency. ComEd, pursuant to an ICC order, and PECO, pursuant to settlements of natural gas distribution rate cases with thea PAPUC order, are currently recovering environmental remediation costs of former MGP facility sites through customer rates. While BGE and DPL do not have riders for MGP clean-up costs, they have historically received recovery of actual clean-up costs in distribution rates. AsIn 2022, ComEd and PECO completed an annual study of December 31, 2019their future estimated MGP remediation requirements. The study resulted in a $60 million increase to the environmental liability and 2018,related regulatory asset for ComEd. The increase was primarily due to increased costs due to inflation and changes in remediation plans. The study did not result in a material change to the Registrants had accrued the following undiscounted amountsenvironmental liability for environmental liabilities in Other current liabilities and Other deferred credits and other liabilities within their respective Consolidated Balance Sheets:PECO.
| | | | | | | | | | | | | | | | | | 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 |
| | — |
|
250
Cotter Corporation (Exelon and Generation).The EPA has advised Cotter Corporation (Cotter), a former ComEd subsidiary, that it is potentially liable in connection with radiological contamination at a site known as the West Lake Landfill in Missouri. In 2000, ComEd sold Cotter to an unaffiliated third-party. As part of the sale, ComEd agreed to indemnify Cotter for any liability arising in connection with the West Lake Landfill. In connection with Exelon’s 2001 corporate restructuring, this responsibility to indemnify Cotter was transferred to Generation. Including Cotter, there are three PRPs participating in the West Lake Landfill remediation proceeding. Investigation by Generation has identified a number of other parties who also may be PRPs and could be liable to contribute to the final remedy. Further investigation is ongoing.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 18 — Commitments and Contingencies
As of December 31, 2022 and 2021, the Registrants had accrued the following undiscounted amounts for environmental liabilities in Accrued expenses, Other current liabilities, and Other deferred credits and other liabilities in their respective Consolidated Balance Sheets:
In September 2018, the EPA issued its Record of Decision (ROD) Amendment for the selection of the final remedy. The ROD modified the EPA’s previously proposed plan for partial excavation of the radiological materials by reducing the depths of the excavation. The ROD 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. In March 2019 the PRPs received Special Notice Letters from the EPA to perform the Remedial Action work. On October 8, 2019, Generation 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 million, including cost escalation on an undiscounted basis, which would be allocated among the final group of PRPs. Generation has determined that a loss associated with the EPA’s partial excavation and enhanced landfill cover remedy is probable and has recorded a liability included in the table above, that reflects management’s best estimate of Cotter’s allocable share of the ultimate cost. Given the joint and several nature of this liability, the magnitude of Generation’s ultimate liability will depend on the actual costs incurred to implement the required 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’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.
One of the other PRPs has indicated it will be making a contribution claim against Cotter for costs that it has incurred to prevent the subsurface fire from spreading to those areas of the West Lake Landfill where radiological materials are believed to have been disposed. At this time, Exelon and Generation do not possess sufficient information to assess this claim and therefore are unable to estimate a range of loss, if any. As such, no liability has been recorded for the potential contribution claim. It is reasonably possible, however, that resolution of this matter could have a material, unfavorable impact 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)/Feasibility Study (FS). The purpose of this RI/FS is to define the nature and extent of any groundwater contamination from the West Lake Landfill site and evaluate remedial alternatives. Generation estimates the undiscounted cost for the groundwater RI/FS to be approximately $20 million. Generation determined a loss associated with the RI/FS is probable and has recorded a liability included in the table above that reflects management’s best estimate of Cotter’s allocable share of the cost among the PRPs. At this time Generation cannot predict the likelihood or the extent to which, if any, remediation activities may be required and therefore cannot estimate a reasonably possible range of loss for response costs beyond those associated with the RI/FS component. It is reasonably possible, however, that resolution of this matter could have a material, unfavorable impact 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 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. Pursuant to a series of annual agreements since 2011, the DOJ and the PRPs have tolled the statute of limitations until February 2020 so that settlement discussions could proceed. Generation has determined that a loss associated with this matter is probable under its indemnification agreement with Cotter and has recorded an estimated liability, which is included in the table above. | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2022 | | December 31, 2021 | | Total environmental investigation and remediation liabilities | | Portion of total related to MGP investigation and remediation | | Total environmental investigation and remediation liabilities | | Portion of total related to MGP investigation and remediation | Exelon | $ | 409 | | | $ | 355 | | | $ | 352 | | | $ | 303 | | ComEd | 325 | | | 324 | | | 279 | | | 279 | | PECO | 25 | | | 23 | | | 22 | | | 20 | | BGE | 9 | | | 8 | | | 6 | | | 4 | | PHI | 46 | | | — | | | 42 | | | — | | Pepco | 44 | | | — | | | 40 | | | — | | DPL | 1 | | | — | | | 1 | | | — | | ACE | 1 | | | — | | | 1 | | | — | |
Benning Road Site (Exelon, Generation, PHI, and Pepco).. In September 2010, PHI received a letter from EPA identifying the Benning Road site as one of six land-based sites potentially contributing to contamination of the lower Anacostia River. A portion of the site, which is owned by Pepco, was formerly the location of aan electric generating facility owned by Pepco subsidiary, Pepco Energy Services electric(PES), which became a part of Generation, following the 2016 merger between PHI and Exelon. This generating facility which was deactivated in June 2012. The remaining portion of the site consists of a Pepco transmission and distribution service center that remains in operation. In December 2011, the U.S. District Court for the District of Columbia approved a Consent Decree entered into by Pepco and Pepco Energy Services (hereinafter "Pepco Entities") with the DOEE, which
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 18 — Commitments and Contingencies
requires the Pepco and Pepco Energy ServicesEntities to conduct a RI/FSRemedial Investigation and Feasibility Study (RI/FS) for the Benning Road site and an approximately 10 to 15-acre portion of the adjacent Anacostia River. The purpose of this RI/FS is to define the nature and extent of contamination from the Benning Road site and to evaluate remedial alternatives. SincePursuant to an internal agreement between the Pepco Entities, since 2013, Pepco has performed the work required by the Consent Decree and has been reimbursed for that work by an agreed upon allocation of costs between the Pepco Energy Services (now Generation, pursuant to Exelon's 2016 acquisition of PHI) have been performing RI work and have submitted multiple draft RI reports to the DOEE.Entities. In September 2019, the Pepco and GenerationEntities issued a draft “final” RI report which DOEE approved and on October 4, 2019 released this document for review and comment by the public.February 3, 2020. The 45 day comment period ended on November 18, 2019 and a public meeting was held by Pepco on November 2, 2019. Pepco and Generation will proceed to developEntities are completing a FS to evaluate possible remedial alternatives for submission to DOEE. The Court has established aIn October, 2022, DOEE approved dividing the work to complete the landside portion of the FS from the waterside portion to expedite the overall schedule for completion of the FS,project. After completion and approval byof the DOEE, bylandside FS, now scheduled for September 16, 2021.
2023, DOEE will then prepare a Proposed Plan for public comment and then issue a Record of Decision (ROD) identifying any further response actions determined to be necessary after considering public comment onto address any landside issues. The DOEE will issue a separate ROD for the Proposed Plan.waterside FS when that work is completed which is now anticipated to be by March 31, 2024. As part of the separation between Exelon and Constellation in February 2022, the internal agreement between the Pepco Entities for completion and payment for the remaining Consent Decree work was memorialized in a formal agreement for post-separation activities. A second post-separation assumption agreement between Exelon and Constellation transferred any of the potential remaining remediation liability, if any, of PES/Generation to a non-utility subsidiary of Exelon which going forward will be responsible for those liabilities. Exelon, PHI, Pepco and GenerationPepco have determined that a loss associated with this matter is probable and have accrued an estimated liability, which is included in the table above. Anacostia River Tidal Reach (Exelon, PHI, and Pepco).. Contemporaneous with the Benning Road site RI/FS being performed by the Pepco and Generation,Entities, DOEE and the National Park ServiceNPS have been conducting a separate RI/FS focused on the entire tidal reach of the Anacostia River extending from just north of the Maryland-District of Columbia boundary line to the confluence of the Anacostia and Potomac Rivers. The river-wide RI incorporated the results of the river sampling performed by the Pepco and Pepco Energy ServicesEntities as part of the Benning RI/FS, as well as similar sampling efforts conducted by owners of other sites adjacent to this segment of the river and supplemental river sampling conducted by DOEE’s contractor. DOEE asked Pepco, along with parties responsible for other sites along the river,
Combined Notes to participateConsolidated Financial Statements (Dollars in a "Consultative Working Group" to provide input into the process for future remedial actionsmillions, except per share data unless otherwise noted)
Note 18 — Commitments 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,Contingencies On September 30, 2020, 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. On December 27, 2019, 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 theInterim 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 July 15, 2022, Pepco received a letter from the District of Columbia's Office of the Attorney General (D.C. OAG) on March 2, 2020behalf of DOEE conveying a settlement offer to resolve all PRPs' liability to the District of Columbia (District) for their past costs and a public meetingtheir anticipated future costs to complete the work for the Interim ROD. Pepco responded on July 27, 2022 to enter into settlement discussions. Since that time Exelon and the other PRP’s at the site have exchanged letters with the D.C. OAG exploring potential settlement options. Those discussions are ongoing. Exelon, PHI, and Pepco have determined that it is probable that costs for remediation will be held on January 23, 2021.incurred and have accrued a liability for management's best estimate of its share of the costs. Pepco concluded that incremental exposure remains reasonably possible, howeverbut management cannot reasonably estimate a range of loss beyond the amounts recorded, which are included in the table above. 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 entered into negotiations with the Trustees to evaluate possible incorporation of NRD assessment and restoration as part of its remedial activities associated with the Benning site to accelerate the NRD benefits for that portion of the Anacostia River Sediment Project (ARSP) assessment. Pepco has concluded that a loss associated with the eventual NRD assessment is reasonably possible. Due to the very early stage of the assessment process, Pepco cannot reasonably estimate the final range of loss.loss potentially resulting from this process.
As noted in the Benning Road Site disclosure above, as part of the separation of Exelon and Constellation in February 2022, an assumption agreement was executed transferring any potential future remediation liabilities associated with the Benning Site remediation to a non-utility subsidiary of Exelon. Similarly, any potential future liability associated with the ARSP was also assumed by this entity.
Combined Notesthe District's stormwater discharge and waste disposal requirements related to Consolidated Financial Statements
(Dollarsoperations at the Buzzard Point facility, a 9-acre parcel of waterfront property in millions, except per share data unless otherwise noted)
Note 18 — CommitmentsWashington, D.C. occupied by an active substation and Contingenciesformer steam plant building. The letter also alleged wholly past violations by Pepco of stormwater discharge requirements related to its district-wide system of underground vaults. The D.C. OAG invited Pepco to resolve the threatened enforcement action through a court-approved consent decree, and Pepco is engaged in discussions with the D.C. OAG regarding a potential resolution. Exelon, PHI, and Pepco have determined that a loss associated with this matter is probable and have accrued an estimated liability. Due to the very early stage of the assessment process, Pepco concluded that incremental exposure is reasonably possible, but the range of loss cannot be reasonably estimated beyond the amounts included in the table above.
Litigation and Regulatory Matters Asbestos Personal Injury Claims (Exelon and Generation). Generation maintains a reserve for claims associated with asbestos-related personal injury actions in certain facilities that are currently owned by Generation or were previously owned by ComEd and PECO. The estimated liabilities are recorded on an undiscounted basis and exclude the estimated legal costs associated with handling these matters, which could be material.
At December 31, 2019 and 2018, Exelon and Generation had recorded estimated liabilities of approximately $83 million and $79 million, respectively, in total for asbestos-related bodily injury claims. As of December 31, 2019, approximately $26 million of this amount related to 263 open claims presented to Generation, while the remaining $57 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.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 18 — Commitments and Contingencies 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 Marylandby the MDPSC and the District of Columbia.DCPSC that prohibit 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 underpursuant to the MDPSC's and DCPSC's 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 Delawareby the DEPSC and Maryland.MDPSC that prohibit 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 underpursuant to the DCPSC's and MDPSC's ratemaking precedents, of the DPSC and MDPSC or (b) DPL’s corporate issuer or senior unsecured credit rating, or its equivalent, is rated by oneany of the three major credit rating agencies below the generally accepted definition of investment grade. No such event has occurred. ACE is subject to certain dividend restrictions established by settlements approved in New Jersey.by the NJBPU that prohibit ACE is prohibited from paying a dividend on its common shares if (a) after the dividend payment, ACE's common equity ratio would be 48% as equity levels are calculated underpursuant to the NJBPU's ratemaking precedents, of the NJBPU or (b) ACE's senior corporate issuer or senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. ACE is also subject to a
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 18 — Commitments and Contingencies
dividend restriction which requires ACE to notify and 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 Financing Agreement (ExelonDPA 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 former 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
Combined Notes to estimate a range of reasonably possible loss as these matters are subject to change.Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 18 — Commitments and Contingencies 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 lawsuitlawsuits 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 appealed dismissal of the federal law claim to the Seventh Circuit Court of Appeals. Plaintiffs and CUB also refiled their state law claims in state court and moved to consolidate them with the already pending consumer state court class action, discussed below. On August 22, 2022, the Seventh Circuit affirmed the dismissal of the consolidated federal cases in their entirety. The time to further appeal has beenpassed and the Seventh Circuit’s decision is final. •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 CUB's request to stay these cases. Plaintiffs subsequently filed a consolidated complaint, and ComEd and Exelon filed a motion to dismiss on jurisdictional and substantive grounds on January 11, 2021. Briefing on that motion was completed on March 2, 2021. The parties agreed, on March 25, 2021, along with the federal court plaintiffs discussed above, to jointly engage in mediation. The parties participated in a one-day mediation on June 7, 2021 but no settlement was reached. 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 asserted in their motion to dismiss the original state court plaintiffs' complaint. The court granted dismissal of the refiled state claims on February 16, 2022. The original federal plaintiffs appealed that dismissal on February 18, 2022. The two state appeals were consolidated on March 21, 2022. Plaintiffs' opening appellate brief was filed on August 5, 2022. Exelon and ComEd's response was filed on November 18, 2022. Plaintiffs filed their reply brief on January 13, 2023. •On November 3, 2022, a plaintiff filed a complaint with the Lake County, Illinois Circuit Court against ComEd and Exelon for unjust enrichment and deceptive business practices in connection with the conduct giving rise to the DPA. Plaintiff seeks an accounting and disgorgement of any benefits ComEd allegedly obtained from said conduct. ComEd and Exelon filed a motion to dismiss the Complaint on February 3, 2023. Plaintiff’s response is due March 3, 2023, and ComEd and Exelon’s reply is due March 24, 2023. Oral argument on the motion to dismiss is currently set for April 21, 2023. Plaintiffs served initial discovery requests on ComEd in December 2022, to which ComEd has responded. •A putative class action lawsuit 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
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 18 — Commitments and Contingencies 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 court further amended the protective order on October 17, 2022 and extended it until May 15, 2023. The next court status is set for May 8, 2023. Discovery remains ongoing. •Several shareholders have sent letters to the Exelon Board of Directors from 2020 through May 2022 demanding, among other things, that the Exelon Board of Directors investigate and address alleged breaches of fiduciary duties and other alleged violations by Exelon 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 SEC investigation.same claims made in its demand letter. On October 12, 2021, the parties to the derivative action filed an agreed motion to stay that litigation for 120 days in order to allow the SLC to continue its investigation, which the court granted. The stay has been extended, by agreement of the parties several times and is currently in effect until March 17, 2023. The Parties have scheduled a mediation of this action for February 2023. •Two separate shareholder requests seeking review of certain Exelon believes that these claims lack meritbooks and intendsrecords were received in August 2021 and January 2022. Exelon responded to defend against them,both requests and thoughboth shareholders have since sent formal shareholder demands to the costs or anyExelon Board, as discussed above. No loss associated with the lawsuit cannot be reasonably estimated at this time, Exelon does not believe that the lawsuit willcontingencies have a material adverse impact onbeen reflected in Exelon’s orand ComEd’s consolidated financial statements.statements with respect to these matters, as such contingencies are neither probable nor reasonably estimable at this time. In August 2022, the ICC concluded its investigation initiated on August 12, 2021 into rate impacts of conduct admitted in the DPA, including the costs recovered from customers related to the DPA and Exelon's funding of the fine paid by ComEd. On August 17, 2022, the ICC issued its final order accepting ComEd's voluntary customer refund offer of approximately $38 million (of which about $31 million is ICC jurisdictional; the remaining balance is FERC jurisdictional) that resolves the question of whether customer funds were used for DPA related activities. The customer refund includes the cost of every individual or entity that was either (i) identified in the DPA or (ii) identified by ComEd as an associate of the former Speaker of the Illinois House of Representatives in the ICC proceeding. The ICC rejected an argument by the Illinois Attorney General, City of Chicago, and CUB that a costly permanent adjustment also needed to be made to ComEd's ratemaking capital structure on account of Exelon having funded ComEd's payment of the DPA fine with an equity infusion. On October 6, the ICC denied the application for rehearing filed by the Illinois Attorney General, City of Chicago, and CUB that specifically focused on their capital structure argument. The window to file an appeal on the ICC final order has expired and the ICC’s DPA investigation is now closed. An accrual for the amount of the voluntary customer refund has been recorded in Regulatory liabilities and Regulatory assets in Exelon’s and ComEd’s Consolidated Balance Sheets as of December 31, 2022. The ICC jurisdictional refund must be made in April 2023; the FERC jurisdictional refund will be made as part of the next transmission formula rate update proceeding in 2023. The customer refund will not be recovered in rates or charged to customers and ComEd will not seek or accept reimbursement or indemnification from any source other than Exelon. 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
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 18 — Commitments and Contingencies 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 filed a motion to dismiss the complaint on February 25, 2022. On March 4, 2022, the Chamber of Commerce filed a brief of amicus curiae in support of the defendants' motion to dismiss. On September 22, 2022, the court granted Exelon’s motion to dismiss without prejudice. The court granted plaintiffs leave until October 31, 2022 to file an amended complaint, which was later extended to November 30, 2022. Plaintiffs filed their amended complaint on November 30, 2022. Defendants filed their motion to dismiss the amended complaint on January 20, 2023. Plaintiffs' response is due February 17, 2023, and defendants' reply is due February 24, 2023. 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 Registrants are also from time to time subject to audits and investigations by the FERC and other regulators. 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.
19. Shareholders' Equity (All Registrants) Equity Securities Offering (Exelon) On August 4, 2022, Exelon entered into an agreement with certain underwriters in connection with an underwritten public offering (the “Offering”) of 11.3 million shares (the “Shares”) of its common stock, no par value (“Common Stock”). The Shares were sold to the underwriters at a price per share of $43.32. Exelon also granted the underwriters an option to purchase an additional 1.695 million shares of Common Stock also at the price per share of $43.32. On August 5, 2022, the underwriters exercised the option in full. The net proceeds from the Offering and the exercise of the underwriters’ option were $563 million before expenses paid by Exelon. Exelon used the proceeds, together with available cash balances, to repay $575 million in borrowings under a $1.15 billion term loan credit facility. See Note 16 — Debt and Credit Agreements for additional information on Exelon’s term loan. At-the-Market (ATM) Program(Exelon) On August 4, 2022, Exelon executed an equity distribution agreement (“Equity Distribution Agreement”), with certain sales agents and forward sellers and certain forward purchasers, establishing an ATM equity distribution program under which it may offer and sell shares of its Common Stock, having an aggregate gross sales price of up to $1.0 billion. Exelon has no obligation to offer or sell any shares of Common Stock under the Equity Distribution Agreement and may, at any time, suspend or terminate offers and sales under the Equity Distribution Agreement. As of December 31, 2022, Exelon has not issued any shares of Common Stock under the ATM program and has not entered into any forward sale agreements.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 19 — Shareholders' Equity
19. Shareholders' Equity (Exelon and Utility 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, | | 2022 | | 2021 | Warrants outstanding | 60,052 | | | 60,061 | | Common Stock reserved for conversion | 20,017 | | | 20,020 | |
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, 20192022 and 2018: 2021. There are no shares of preferred securities authorized for DPL. | | | | | | | 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, 2019 and 2018, respectively. | _________(a)Includes 799,979 shares of cumulative preferred stock and 2,000,000 of no-par preferred stock as of December 31, 2022 and 2021. The following table presents ComEd's, BGE's, and ACE's preference securities authorized, none of which arewere outstanding as of December 31, 20192022 and 2018:2021. There are no shares of preference securities authorized for Exelon, PECO, Pepco, and DPL. | | | | | | | Preference Securities Authorized | ComEd - Cumulative preference securities | 6,810,451 |
| BGE(a) | 6,500,000 |
| ACE | 3,000,000 |
|
__________
| | (a)ACE | 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.3,000,000 | |
__________
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 19 — Shareholders' Equity
20. 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, 2019,2022, there were approximately 1234 million shares authorized for issuance under the LTIP. For the years ended December 31, 2019, 20182022, 2021, and 2017,2020, exercised and distributed stock-based awards were primarily issued from authorized but unissued common stock shares. Separation-related Adjustments. In connection with the separation, Exelon and Constellation entered into an Employee Matters Agreement, effective February 1, 2022. Under the terms of the Employee Matters Agreement,
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 20 — Stock-Based Compensation Plans and pursuant to the terms of the LTIP, the Compensation Committee of the Board of Exelon approved an adjustment to outstanding awards granted under the LTIP in order to preserve the intrinsic aggregate value of such awards before the separation. The separation-related adjustments did not have a material impact on either compensation expense or the potentially dilutive securities to be considered in the calculation of diluted earnings per share of common stock. Former Exelon employees transferred to Constellation as a result of the separation surrendered their outstanding unvested Exelon awards effective February 1, 2022. 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, 20182022, 2021, and 20172020 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 | 2022 | | 2021 | | 2020 | Total stock-based compensation expense included in operating and maintenance expense | $ | 41 | | | $ | 95 | | | $ | 37 | | Income tax benefit | (10) | | | (25) | | | (9) | | Total after-tax stock-based compensation expense | $ | 31 | | | $ | 70 | | | $ | 28 | | | | | | | | | | | | | | | | | | | | | | | | | |
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 |
|
| | | | | | | | | | | | | | | | | | | Year Ended December 31, | | 2022 | | 2021 | | 2020 | Performance share awards | $ | 6 | | | $ | 6 | | | $ | 15 | | Restricted stock units | 6 | | | 6 | | | 8 | |
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:
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 20 — Stock-Based Compensation Plans | | | | | | | 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, 2021(a) | | Nonvested at December 31, 2021(a) | 1,222,516 | | | $ | 44.96 | | Granted | 1,089,903 |
| | 47.37 |
| Granted | 727,697 | | | 43.05 | | Change in performance | (799,618 | ) | | 40.85 |
| Change in performance | (216,981) | | | 42.73 | | Vested | (1,610,146 | ) | | 28.90 |
| Vested | (233,318) | | | 47.39 | | Forfeited | (25,249 | ) | | 45.03 |
| Forfeited | (86,128) | | | 42.61 | | Undistributed vested awards(b) | (348,363 | ) | | 48.82 |
| | Nonvested at December 31, 2019(a) | 1,709,755 |
| | $ | 39.21 |
| | Awards surrendered as a result of the separation | | Awards surrendered as a result of the separation | (2,308,745) | | | Awards granted in conversion as a result of the separation | | Awards granted in conversion as a result of the separation | 1,870,990 | | | Undistributed vested awards(b)(c) | | Undistributed vested awards(b)(c) | (109,226) | | | 4.55 | | Nonvested at December 31, 2022(a) | | Nonvested at December 31, 2022(a) | 866,805 | | | $ | 41.86 | |
__________ | | (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 1,539,819 and 1,934,238 of performance share awards issued to retirement-eligible employees as of December 31, 2022 and 2021, respectively, as they are fully vested. (b)The significant reduction in weighted average grant date fair value during 2022 primarily resulted from more pre-separation shares being surrendered than shares issued to Exelon retirement eligible employees post-separation. (c)Represents performance share awards that vested but were not distributed to retirement-eligible employees during 2022. 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 | | 2022(a) | | 2021 | | 2020 | Weighted average grant date fair value (per share) | $ | 47.37 |
| | $ | 38.15 |
| | $ | 35.00 |
| Weighted average grant date fair value (per share) | $ | 43.05 | | | $ | 43.37 | | | $ | 46.61 | | Total fair value of performance shares settled | 158 |
| | 61 |
| | 72 |
| | Total fair value of performance shares vested | | Total fair value of performance shares vested | 29 | | | 44 | | | 39 | | Total fair value of performance shares settled in cash | 131 |
| | 49 |
| | 56 |
| Total fair value of performance shares settled in cash | 25 | | | 28 | | | 63 | |
__________ | | (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, 2022, $12 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 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.
The following table summarizes Exelon’s nonvested restricted stock unit activity:
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 20 — Stock-Based Compensation Plans
| | | | | | | | | | | | | Shares | | Weighted Average Grant Date Fair Value (per share) | Nonvested at December 31, 2021(a) | 1,142,049 | | | $ | 43.52 | | Granted | 468,514 | | | 42.97 | | Vested | (499,621) | | | 42.28 | | Forfeited | (71,816) | | | 41.89 | | Awards surrendered as a result of the separation | (943,509) | | | Awards granted in conversion as a result of the separation | 643,994 | | | Undistributed vested awards(b) | (178,450) | | | 38.24 | | Nonvested at December 31, 2022(a) | 561,161 | | $ | 41.98 | |
The following table summarizes Exelon’s nonvested__________
(a)Excludes 476,592 and 609,934 of restricted stock unit activity:units issued to retirement-eligible employees as of December 31, 2022 and 2021, respectively, as they are fully vested. (b)Represents restricted stock units that vested but were not distributed to retirement-eligible employees during 2022. | | | | | | | | | Shares | | Weighted Average Grant Date Fair Value (per share) | Nonvested at December 31, 2018(a) | 2,293,341 |
| | $ | 35.06 |
| Granted | 902,857 |
| | 45.65 |
| Vested | (1,232,704 | ) | | 32.83 |
| Forfeited | (33,603 | ) | | 39.01 |
| Undistributed vested awards (b) | (431,178 | ) | | 44.75 |
| Nonvested at December 31, 2019(a) | 1,498,713 |
| | $ | 40.35 |
|
__________
| | (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. |
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 | | 2022(a) | | 2021 | | 2020 | Weighted average grant date fair value (per share) | $ | 45.65 |
| | $ | 38.60 |
| | $ | 34.98 |
| Weighted average grant date fair value (per share) | $ | 42.97 | | | $ | 44.21 | | | $ | 46.33 | | Total fair value of restricted stock units vested | 92 |
| | 106 |
| | 88 |
| Total fair value of restricted stock units vested | 23 | | | 34 | | | 54 | |
__________ | | (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, 2022, $11 million of total unrecognized compensation costs related to nonvested restricted stock units are expected to be recognized over the remaining weighted-average period of 1.90 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, 20192022 all stock options were vested and there were no unrecognized compensation costs.exercised. 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, 2021 | 27,007 | | | $ | 46.47 | | | 0.15 | | $ | — | | Options exercised | (27,644) | | | 38.56 | | | | | — | | | | | | | | | | Options expired | — | | | — | | | | | | Awards surrendered as a result of the separation | (2,000) | | | | | | | | Awards granted in conversion as a result of the separation | 2,637 | | | | | | | | Balance of shares outstanding at December 31, 2022 | — | | | $ | — | | | 0 | | $ | — | | Exercisable at December 31, 2022 | — | | | $ | — | | | 0 | | $ | — | |
| | | | | | | | | | | | | | | 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. |
The following table summarizes additional information regarding stock options exercised:
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 additional information regarding stock options exercised:
| | | Year Ended December 31, | | Year Ended December 31, | | 2019 | | 2018 | | 2017 | | 2022 | | 2021 | | 2020 | Intrinsic value(a) | $ | 9 |
| | $ | 12 |
| | $ | 15 |
| Intrinsic value(a) | $ | — | | | $ | 11 | | | $ | 5 | | Cash received for exercise price | 59 |
| | 56 |
| | 107 |
| Cash received for exercise price | 1 | | | 37 | | | 18 | |
__________ | | (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. Changes in Accumulated Other Comprehensive Income (Exelon) The following tables present changes in Exelon's AOCI, net of tax, by component: | | | | | | | | | | | | | | | | Cash Flow Hedges | | | Pension and Non-Pension Postretirement Benefit Plan Items (a) | | Foreign Currency Items | | | 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 | ) | | Balance at December 31, 2019 | | Balance at December 31, 2019 | $ | (2) | | | | $ | (3,165) | |
| $ | (27) | | | | $ | (3,194) | | OCI before reclassifications | (1 | ) | | 6 |
| | 11 |
| | 7 |
| | 6 |
| | 29 |
| OCI before reclassifications | (3) | | | | (357) | | | 4 | | | | (356) | | Amounts reclassified from AOCI | 4 |
| | — |
| | 140 |
| | — |
| | — |
| | 144 |
| Amounts reclassified from AOCI | — | | | | 150 | | | — | | | | 150 | | Net current-period OCI | 3 |
| | 6 |
| | 151 |
| | 7 |
| | 6 |
| | 173 |
| Net current-period OCI | (3) | | | | (207) | | | 4 | | | | (206) | | 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 | ) | | Balance at December 31, 2020 | | Balance at December 31, 2020 | $ | (5) | | | | $ | (3,372) | | | $ | (23) | | | | $ | (3,400) | | OCI before reclassifications | 11 |
| | — |
| | (143 | ) | | (10 | ) | | 1 |
| | (141 | ) | OCI before reclassifications | (1) | | | | 432 | | | — | | | | 431 | | Amounts reclassified from AOCI | 1 |
|
| — |
|
| 181 |
|
| — |
| | — |
|
| 182 |
| Amounts reclassified from AOCI | — | | | | 219 | | | — | | | | 219 | | Net current-period OCI | 12 |
|
| — |
|
| 38 |
|
| (10 | ) |
| 1 |
| | 41 |
| Net current-period OCI | (1) | | | | 651 | | | — | | | | 650 | | 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, 2021 | | Balance at December 31, 2021 | $ | (6) | | | | $ | (2,721) | | | $ | (23) | | | | $ | (2,750) | | Separation of Constellation | | Separation of Constellation | 6 | | | | 1,994 | | | 23 | | | | 2,023 | | OCI before reclassifications | — |
| | — |
| | (289 | ) | | 6 |
| | (2 | ) | | (285 | ) | OCI before reclassifications | 2 | | | | 46 | | | — | | | | 48 | | Amounts reclassified from AOCI | — |
| | — |
| | 84 |
| | — |
| | 2 |
| | 86 |
| Amounts reclassified from AOCI | — | | | | 41 | | | — | | | | 41 | | Net current-period OCI | — |
| | — |
| | (205 | ) | | 6 |
| | — |
| | (199 | ) | Net current-period OCI | 2 | | | | 87 | | | — | | | | 89 | | Balance at December 31, 2019 | $ | (2 | ) |
| $ | — |
|
| $ | (3,165 | ) |
| $ | (27 | ) |
| $ | — |
|
| $ | (3,194 | ) | | Balance at December 31, 2022 | | Balance at December 31, 2022 | $ | 2 | | | | $ | (640) | | | $ | — | | | | $ | (638) | |
__________ | | (a) | (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. |
Combined Notes to Consolidated Financial Statements
(Dollarsnet periodic pension and OPEB cost. Additionally, as of February 1, 2022, in millions, except per share data unless otherwise noted)
connection with the separation, Exelon's pension and OPEB plans were remeasured. See Note 2114 — Changes in Accumulated OtherRetirement Benefits for additional information. See Exelon's Statements of Operations and Comprehensive Income
for individual components of AOCI.
The following table presents income tax benefit (expense) allocated to each component of Exelon's other comprehensive income (loss): | | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | | 2022 | | 2021 | | 2020 | Pension and non-pension postretirement benefit plans: | | | | | | Prior service benefit reclassified to periodic benefit cost | $ | — | | | $ | 4 | | | $ | 16 | | Actuarial loss reclassified to periodic benefit cost | (14) | | | (76) | | | (66) | | Pension and non-pension postretirement benefit plans valuation adjustment | (14) | | | (153) | | | 122 | |
| | | | | | | | | | | | | | 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 |
|
261
22. Variable Interest Entities (Exelon, Generation, PHI and ACE)
At December 31, 2019 and 2018, Exelon, Generation, PHI and ACE collectively consolidated several VIEs or VIE groups for which the applicable Registrant was the primary beneficiary (see Consolidated VIEs below) and had significant interests in several other VIEs for which the applicable Registrant does not have the power to direct the entities’ activities and, accordingly, was not the primary beneficiary (see Unconsolidated VIEs below). Consolidated and unconsolidated VIEs are aggregated to the extent that the entities have similar risk profiles.
Consolidated VIEs
The table below shows the carrying amounts and classification of the consolidated VIEs’ assets and liabilities included in the consolidated financial statements of Exelon, Generation, PHI and ACE as of December 31, 2019 and 2018. 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 | | Exelon(a) | | Generation | | PHI(a) | | ACE | | Exelon | | Generation | | PHI | | ACE | Cash and cash equivalents | $ | 163 |
| | $ | 163 |
| | $ | — |
| | $ | — |
| | $ | 414 |
| | $ | 414 |
| | $ | — |
| | $ | — |
| Restricted cash and cash equivalents | 88 |
| | 85 |
| | 3 |
| | 3 |
| | 66 |
| | 62 |
| | 4 |
| | 4 |
| Accounts receivable, net | | | | | | | | | | | | | | | | Customer | 151 |
| | 151 |
| | — |
| | — |
| | 146 |
| | 146 |
| | — |
| | — |
| Other | 39 |
| | 39 |
| | — |
| | — |
| | 23 |
| | 23 |
| | — |
| | — |
| Unamortized energy contract asset (b) | 23 |
| | 23 |
| | — |
| | — |
| | 25 |
| | 25 |
| | — |
| | — |
| Inventories, net | | | | | | | | | | | | | | | | Materials and supplies | 227 |
| | 227 |
| | — |
| | — |
| | 212 |
| | 212 |
| | — |
| | — |
| Other current assets | 32 |
| | 31 |
| | 1 |
| | — |
| | 52 |
| | 49 |
| | 3 |
| | — |
| Total current assets | 723 |
|
| 719 |
|
| 4 |
|
| 3 |
| | 938 |
| | 931 |
| | 7 |
| | 4 |
| Property, plant and equipment, net (c) | 6,022 |
| | 6,022 |
| | — |
| | — |
| | 6,188 |
| | 6,188 |
| | — |
| | — |
| Nuclear decommissioning trust funds | 2,741 |
| | 2,741 |
| | — |
| | — |
| | 2,351 |
| | 2,351 |
| | — |
| | — |
| Unamortized energy contract asset (b) | 250 |
| | 250 |
| | — |
| | — |
| | 274 |
| | 274 |
| | — |
| | — |
| Other noncurrent assets | 89 |
| | 73 |
| | 16 |
| | 14 |
| | 258 |
| | 232 |
| | 26 |
| | 19 |
| Total noncurrent assets | 9,102 |
|
| 9,086 |
|
| 16 |
|
| 14 |
| | 9,071 |
| | 9,045 |
| | 26 |
| | 19 |
| Total assets | $ | 9,825 |
|
| $ | 9,805 |
|
| $ | 20 |
|
| $ | 17 |
| | $ | 10,009 |
| | $ | 9,976 |
| | $ | 33 |
| | $ | 23 |
| | | | | | | | | | | | | | | | | Long-term debt due within one year | $ | 544 |
| | $ | 523 |
| | $ | 21 |
| | $ | 20 |
| | $ | 87 |
| | $ | 66 |
| | $ | 21 |
| | $ | 18 |
| Accounts payable | 106 |
| | 106 |
| | — |
| | — |
| | 96 |
| | 96 |
| | — |
| | — |
| Accrued expenses | 70 |
| | 70 |
| | — |
| | — |
| | 73 |
| | 72 |
| | 1 |
| | 1 |
| Unamortized energy contract liabilities | 8 |
| | 8 |
| | — |
| | — |
| | 15 |
| | 15 |
| | — |
| | — |
| Other current liabilities | 3 |
| | 3 |
| | — |
| | — |
| | 3 |
| | 3 |
| | — |
| | — |
| Total current liabilities | 731 |
|
| 710 |
|
| 21 |
|
| 20 |
| | 274 |
| | 252 |
| | 22 |
| | 19 |
| Long-term debt | 527 |
| | 504 |
| | 23 |
| | 21 |
| | 1,072 |
| | 1,025 |
| | 47 |
| | 40 |
| Asset retirement obligations (d) | 2,128 |
| | 2,128 |
| | — |
| | — |
| | 2,165 |
| | 2,165 |
| | — |
| | — |
| Unamortized energy contract liabilities | 1 |
| | 1 |
| | — |
| | — |
| | 1 |
| | 1 |
| | — |
| | — |
| Other noncurrent liabilities | 89 |
| | 89 |
| | — |
| | — |
| | 42 |
| | 42 |
| | — |
| | — |
| Total noncurrent liabilities | 2,745 |
|
| 2,722 |
|
| 23 |
|
| 21 |
| | 3,280 |
| | 3,233 |
| | 47 |
| | 40 |
| Total liabilities | $ | 3,476 |
|
| $ | 3,432 |
|
| $ | 44 |
|
| $ | 41 |
| | $ | 3,554 |
| | $ | 3,485 |
| | $ | 69 |
| | $ | 59 |
|
__________
| | (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. |
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 22 — Variable Interest EntitiesSupplemental Financial Information
As of December 31, 2019 and 2018, Exelon's and Generation's consolidated VIEs consist of:
| | | | Consolidated VIE or VIE groups: | Reason entity is a VIE: | Reason Generation is primary beneficiary: | CENG - A joint venture between Generation and EDF. Generation has a 50.01% equity ownership in CENG. See additional discussion below. | Disproportionate relationship between equity interest and operational control as a result of the Nuclear Operating Services Agreement (NOSA) described further below. | Generation conducts the operational activities. | EGRP - A collection of wind and solar project entities. Generation has a 51% equity ownership in EGRP. See additional discussion below. | Similar structure to a limited partnership and the limited partners do not have kick out rights with respect to the general partner. | Generation conducts the operational activities. | Blue Stem Wind - A Tax Equity structure which is consolidated by EGRP. Generation is a minority interest holder. | Similar structure to a limited partnership and the limited partners do not have kick out rights with respect to the general partner. | Generation conducts the operational activities. | Antelope Valley - A solar generating facility, which is 100% owned by Generation. Antelope Valley sells all of its output to PG&E through a PPA. | The PPA contract absorbs variability through a performance guarantee. | Generation conducts all activities. | Equity investment in distributed energy company - Generation has a 31% equity ownership. This distributed energy company has an interest in an unconsolidated VIE. (See Unconsolidated VIEs disclosure below).
Generation fully impaired this investment in the third quarter of 2019. See note 11- 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. |
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 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 to CENG. The remaining balance was fully paid by CENG in January 2019.
Generation executed an Indemnity Agreement pursuant to which Generation agreed to indemnify EDF against third-party claims that may arise from any future nuclear incident (as defined in the Price-Anderson Act) in connection with the CENG nuclear plants or their operations. Exelon guarantees Generation’s obligations under this Indemnity Agreement. (See Note 18 — Commitments and Contingencies for more 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.
EGRP - EGRP is a collection of wind and solar project entities and some of these project entities are VIEs that are consolidated by EGRP. Generation owns a number of limited liability companies that build, own, and operate solar and wind power facilities some of which are owned by EGRP. While Generation or EGRP owns 100% of the solar entities and 100% of the majority of the wind entities, it has been determined that certain of the solar and wind entities are VIEs because the entities require additional subordinated financial support in the form of a parental guarantee of debt, loans from the customers in order to obtain the necessary funds for construction of the solar
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 22 — Variable Interest Entities
facilities, or the customers absorb price variability from the entities through the fixed price power and/or REC purchase agreements. Generation is the primary beneficiary of these solar and wind entities that qualify as VIEs because Generation controls the design, construction, and operation of the facilities. Generation provides operating and capital funding to the solar and wind entities for ongoing construction, operations and maintenance and there is limited recourse related to Generation related to certain solar and wind entities.
In 2017, Generation’s interests in EGRP were contributed to and are pledged for the ExGen Renewables IV non-recourse debt project financing structure. Refer to Note 16 — Debt and Credit Agreements for additional information on ExGen Renewables IV.
As of December 31, 2019 and 2018, 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. Proceeds from the sale of each series of transition bonds by ATF were transferred to ACE in exchange for the transfer by ACE to ATF of the right to collect a non-bypassable Transition Bond Charge from ACE customers pursuant to bondable stranded costs rate orders issued by the NJBPU in an amount sufficient to fund the principal and interest payments on transition bonds and related taxes, expenses and fees. | ACE’s equity investment is a variable interest as, by design, it absorbs any initial variability of ACETF. The bondholders also have a variable interest for the investment made to purchase the transition bonds. | ACE controls the servicing activities. |
Unconsolidated VIEs
Exelon’s and Generation’s variable interests in unconsolidated VIEs generally include equity investments and energy purchase and sale contracts. For the equity investments, the carrying amount of the investments is reflected in Exelon’s and Generation’s Consolidated Balance Sheets in Investments. For the energy purchase and sale contracts (commercial agreements), the carrying amount of assets and liabilities in Exelon’s and Generation’s Consolidated Balance Sheets that relate to their involvement with the VIEs are predominately related to working capital accounts and generally represent the amounts owed by, or owed to, Exelon and Generation for the deliveries associated with the current billing cycles under the commercial agreements.
As of December 31, 2019 and 2018, 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’s significant unconsolidated VIE entities:
| | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2019 | | December 31, 2018 | | 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 liabilities(a) | 33 |
| | 227 |
| | 260 |
| | 37 |
| | 222 |
| | 259 |
| Exelon's ownership interest in VIE(a) | — |
| | 191 |
| | 191 |
| | — |
| | 223 |
| | 223 |
| Other ownership interests in VIE(a) | 604 |
| | 25 |
| | 629 |
| | 560 |
| | 27 |
| | 587 |
| Registrants’ maximum exposure to loss: | | | | |
|
| | | | | |
|
| Carrying amount of equity method investments | — |
| | — |
| | — |
| | — |
| | 223 |
| | 223 |
|
__________
| | (a) | These items represent amounts on 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, Exelon and Generation have assessed the risk of a loss equal to their maximum exposure to be remote and, accordingly, Exelon and Generation have not recognized a liability associated with any portion of the maximum exposure to loss.
As of December 31, 2019 and 2018, Exelon's and Generation's unconsolidated VIEs consist of:
| | | | Unconsolidated VIE groups: | Reason entity is a VIE: | Reason Generation is not the primary beneficiary: | Equity investments in distributed energy companies -
1) Generation has a 90% equity ownership in a distributed energy company.
2) Generation, via a consolidated VIE, has a 90% equity ownership in a distributed energy company (See Consolidated VIEs disclosure above).
Generation fully impaired this investment in the third quarter of 2019. See note 11- 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. |
23.22. 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 | | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | | For the year ended December 31, 2019 | | | | | | | | | | | | | | | | | | | For the year ended December 31, 2022 | | For the year ended December 31, 2022 | | | | | | | | | | | | | | | | Utility(a) | $ | 881 |
| | $ | 112 |
| | $ | 242 |
| | $ | 132 |
| | $ | 90 |
| | $ | 304 |
| | $ | 286 |
| | $ | 18 |
| | $ | — |
| Utility(a) | $ | 878 | | | $ | 306 | | | $ | 166 | | | $ | 94 | | | $ | 312 | | | $ | 283 | | | $ | 25 | | | $ | 4 | | Property | 595 |
| | 274 |
| | 29 |
| | 17 |
| | 153 |
| | 122 |
| | 85 |
| | 34 |
| | 2 |
| Property | 377 | | | 31 | | | 17 | | | 191 | | | 138 | | | 94 | | | 42 | | | 2 | | Payroll | 232 |
| | 115 |
| | 27 |
| | 15 |
| | 17 |
| | 24 |
| | 7 |
| | 4 |
| | 2 |
| Payroll | 117 | | | 28 | | | 16 | | | 17 | | | 25 | | | 6 | | | 4 | | | 3 | | | | | | | | | | | | | | | | | | | | | For the year ended December 31, 2018 | | | | | | | | | | | | | | | | | | | For the year ended December 31, 2021 | | For the year ended December 31, 2021 | | Utility(a) | $ | 919 |
| | $ | 114 |
| | $ | 243 |
| | $ | 131 |
| | $ | 94 |
| | $ | 337 |
| | $ | 316 |
| | $ | 21 |
| | $ | — |
| Utility(a) | $ | 774 | | | $ | 246 | | | $ | 139 | | | $ | 88 | | | $ | 301 | | | $ | 278 | | | $ | 22 | | | $ | 3 | | Property | 557 |
| | 273 |
| | 30 |
| | 15 |
| | 143 |
| | 94 |
| | 58 |
| | 32 |
| | 3 |
| Property | 364 | | | 39 | | | 18 | | | 176 | | | 131 | | | 88 | | | 40 | | | 3 | | Payroll | 247 |
| | 130 |
| | 27 |
| | 16 |
| | 17 |
| | 24 |
| | 5 |
| | 3 |
| | 2 |
| Payroll | 124 | | | 27 | | | 16 | | | 18 | | | 27 | | | 7 | | | 5 | | | 3 | | | | | | | | | | | | | | | | | | | | | For the year ended December 31, 2017 | | | | | | | | | | | | | | | | | | | For the year ended December 31, 2020 | | For the year ended December 31, 2020 | | Utility(a) | $ | 898 |
| | $ | 126 |
| | $ | 240 |
| | $ | 125 |
| | $ | 89 |
| | $ | 318 |
| | $ | 300 |
| | $ | 18 |
| | $ | — |
| Utility(a) | $ | 759 | | | $ | 238 | | | $ | 135 | | | $ | 87 | | | $ | 299 | | | $ | 275 | | | $ | 21 | | | $ | 3 | | Property | 545 |
| | 269 |
| | 28 |
| | 14 |
| | 132 |
| | 101 |
| | 62 |
| | 32 |
| | 3 |
| Property | 336 | | | 30 | | | 16 | | | 164 | | | 126 | | | 84 | | | 39 | | | 3 | | Payroll | 230 |
| | 121 |
| | 26 |
| | 15 |
| | 15 |
| | 26 |
| | 6 |
| | 4 |
| | 2 |
| Payroll | 121 | | | 27 | | | 16 | | | 17 | | | 25 | | | 7 | | | 5 | | | 3 | |
__________ | | (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)The 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. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Other, net | | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | For the year ended December 31, 2022 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | AFUDC—Equity | $ | 150 | | | $ | 35 | | | $ | 31 | | | $ | 21 | | | $ | 63 | | | $ | 48 | | | $ | 7 | | | $ | 8 | | Non-service net periodic benefit cost | 63 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | For the year ended December 31, 2021 | | | | | | | | | | | | | | | | AFUDC—Equity | $ | 136 | | | $ | 34 | | | $ | 26 | | | $ | 27 | | | $ | 49 | | | $ | 40 | | | $ | 6 | | | $ | 3 | | Non-service net periodic benefit cost | 91 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | | | | | | | | | | | | | | | | For the year ended December 31, 2020 | | | | | | | | | | | | | | | | AFUDC—Equity | $ | 104 | | | $ | 29 | | | $ | 17 | | | $ | 22 | | | $ | 36 | | | $ | 28 | | | $ | 4 | | | $ | 4 | | Non-service net periodic benefit cost | 53 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 2322 — Supplemental Financial Information
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Other, Net | | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | For the year ended December 31, 2019 | | | | | | | | | | | | | | | | | | Decommissioning-related activities: | Net realized income on NDT funds(a) | Regulatory agreement units | $ | 297 |
| | $ | 297 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| Non-regulatory agreement units | 363 |
| | 363 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Net unrealized gains on NDT funds | | | | | | | | | | | | | | | | | | Regulatory agreement units | 795 |
| | 795 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Non-regulatory agreement units | 411 |
| | 411 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Regulatory offset to NDT fund-related activities(b) | (876 | ) | | (876 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Decommissioning-related activities | 990 |
|
| 990 |
|
| — |
|
| — |
|
| — |
| | — |
|
| — |
|
| — |
|
| — |
| AFUDC—Equity | 85 |
| | — |
| | 17 |
| | 13 |
| | 21 |
| | 34 |
| | 25 |
| | 4 |
| | 5 |
| 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. |
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 23 — 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(a) | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | For the year ended December 31, 2022 | | | | | | | | | | | | | | | Property, plant, and equipment(b) | $ | 2,690 | | | $ | 1,031 | | | $ | 359 | | | $ | 476 | | | $ | 680 | | | $ | 288 | | | $ | 191 | | | $ | 173 | | Amortization of regulatory assets(b) | 718 | | | 292 | | | 14 | | | 154 | | | 258 | | | 129 | | | 41 | | | 88 | | Amortization of intangible assets, net(b) | 12 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Amortization of energy contract assets and liabilities(c) | 3 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Nuclear fuel(d) | 66 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | ARO accretion(e) | 44 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Total depreciation, amortization, and accretion | $ | 3,533 | | | $ | 1,323 | | | $ | 373 | | | $ | 630 | | | $ | 938 | | | $ | 417 | | | $ | 232 | | | $ | 261 | | | | | | | | | | | | | | | | | | For the year ended December 31, 2021 | | | | | | | | | | | | | | | Property, plant, and equipment(b) | $ | 5,384 | | | $ | 970 | | | $ | 336 | | | $ | 439 | | | $ | 627 | | | $ | 274 | | | $ | 169 | | | $ | 155 | | Amortization of regulatory assets(b) | 594 | | | 235 | | | 12 | | | 152 | | | 194 | | | 129 | | | 41 | | | 24 | | Amortization of intangible assets, net(b) | 58 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Amortization of energy contract assets and liabilities(c) | 31 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Nuclear fuel(d) | 992 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | ARO accretion(e) | 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(b) | $ | 4,364 | | | $ | 922 | | | $ | 319 | | | $ | 397 | | | $ | 586 | | | $ | 257 | | | $ | 155 | | | $ | 140 | | Amortization of regulatory assets(b) | 588 | | | 211 | | | 28 | | | 153 | | | 196 | | | 120 | | | 36 | | | 40 | | Amortization of intangible assets, net(b) | 62 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Amortization of energy contract assets and liabilities(c) | 30 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Nuclear fuel(d) | 983 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | ARO accretion(e) | 500 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Total depreciation, amortization, and accretion | $ | 6,527 | | | $ | 1,133 | | | $ | 347 | | | $ | 550 | | | $ | 782 | | | $ | 377 | | | $ | 191 | | | $ | 180 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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)Exelon's amounts include amounts related to Generation prior to the separation. See Note 2 — Discontinued Operations for additional information.
| | (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 Depreciation and amortization in the Registrants' Consolidated Statements of Operations and Comprehensive Income.
(c)Included in Electric operating revenues or Purchased power expense in Exelon’s Consolidated Statements of Operations and Comprehensive Income. (d)Included in Purchased fuel expense in Exelon’s Consolidated Statements of Operations and Comprehensive Income. (e)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 2322 — Supplemental Financial Information
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Cash paid (refunded) during the year: | | Exelon(a) | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | For the year ended December 31, 2022 | | | | | | | | | | | | | | | | Interest (net of amount capitalized) | $ | 1,434 | | | $ | 396 | | | $ | 166 | | | $ | 147 | | | $ | 274 | | | $ | 141 | | | $ | 63 | | | $ | 60 | | Income taxes (net of refunds) | 73 | | | 23 | | | 31 | | | 16 | | | 19 | | | 28 | | | (2) | | | (6) | | | | | | | | | | | | | | | | | | 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) | | __________(a)Exelon's amounts include amounts related to Generation prior to the separation. See Note 2 — Discontinued Operations for additional information. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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 | ) |
264
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 2322 — Supplemental Financial Information
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Amortization of operating ROU asset | 244 |
| | 172 |
| | 3 |
| | — |
| | 30 |
| | 33 |
| | 8 |
| | 8 |
| | 4 |
| 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 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Other non-cash operating activities: | | Exelon(a) | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | For the year ended December 31, 2022 | | | | | | | | | | | | | | | | Pension and non-pension postretirement benefit costs | $ | 164 | | | $ | 60 | | | $ | (9) | | | $ | 44 | | | $ | 53 | | | $ | 9 | | | $ | 3 | | | $ | 12 | | Allowance for credit losses | 173 | | | 46 | | | 45 | | | 25 | | | 58 | | | 29 | | | 12 | | | 16 | | Other decommissioning-related activity | 36 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Energy-related options | 60 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | True-up adjustments to decoupling mechanisms and formula rates(b) | (168) | | | (267) | | | (2) | | | 47 | | | 54 | | | 31 | | | 7 | | | 16 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Long-term incentive plan | 42 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Amortization of operating ROU asset | 56 | | | 2 | | | — | | | 14 | | | 27 | | | 7 | | | 8 | | | 3 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | AFUDC - Equity | (150) | | | (35) | | | (31) | | | (21) | | | (63) | | | (48) | | | (7) | | | (8) | | | | | | | | | | | | | | | | | | For the year ended December 31, 2021 | | | | | | | | | | | | | | | | Pension and non-pension postretirement benefit costs | $ | 411 | | | $ | 129 | | | $ | 8 | | | $ | 61 | | | $ | 49 | | | $ | 6 | | | $ | 2 | | | $ | 11 | | Allowance for credit losses | 160 | | | 47 | | | 39 | | | 17 | | | 24 | | | 9 | | | 5 | | | 10 | | Other decommissioning-related activity | (946) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Energy-related options | 125 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | True-up adjustments to decoupling mechanisms and formula rates(b) | (171) | | | (42) | | | (26) | | | (12) | | | (91) | | | (53) | | | (14) | | | (24) | | Severance costs | (57) | | | 2 | | | — | | | — | | | 1 | | | — | | | — | | | — | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Long-term incentive plan | 137 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Amortization of operating ROU asset | 183 | | | 1 | | | — | | | 29 | | | 28 | | | 6 | | | 8 | | | 4 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | AFUDC - Equity | (136) | | | (34) | | | (26) | | | (27) | | | (49) | | | (40) | | | (6) | | | (3) | | | | | | | | | | | | | | | | | | For the year ended December 31, 2020 | | | | | | | | | | | | | | | | Pension and non-pension postretirement benefit costs | $ | 411 | | | $ | 114 | | | $ | 5 | | | $ | 62 | | | $ | 70 | | | $ | 15 | | | $ | 7 | | | $ | 14 | | Allowance for credit losses | 150 | | | 32 | | | 42 | | | 15 | | | 43 | | | 24 | | | 16 | | | 2 | | Other decommissioning-related activity | (659) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Energy-related options | 104 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | True-up adjustments to decoupling mechanisms and formula rates(c) | (6) | | | 47 | | | (16) | | | (16) | | | (21) | | | (40) | | | 7 | | | 12 | | Severance costs | 105 | | | 1 | | | 1 | | | — | | | — | | | — | | | — | | | — | | | | | | | | | | | | | | | | | | Provision for excess and obsolete inventory | 131 | | | 2 | | | 1 | | | — | | | — | | | — | | | — | | | — | | | | | | | | | | | | | | | | | | Long-term incentive plan | 56 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Amortization of operating ROU Asset | 222 | | | 2 | | | 1 | | | 31 | | | 28 | | | 7 | | | 8 | | | 3 | | Asset impairments | — | | | 15 | | | — | | | — | | | 13 | | | — | | | 7 | | | 6 | | AFUDC - Equity | (104) | | | (29) | | | (17) | | | (22) | | | (36) | | | (28) | | | (4) | | | (4) | |
__________ | | (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)Exelon's amounts include amounts related to Generation prior to the separation. See Note 2 — Discontinued Operations for additional information. (b)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 PECO, reflects the change in regulatory assets and liabilities associated with its transmission formula rate. For BGE, Pepco, DPL, and ACE, reflects the change in regulatory assets and liabilities associated with their decoupling mechanisms and transmission formula rates. See Note 3 — Regulatory Matters for additional 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, and DPL, reflects the change in regulatory assets and liabilities associated with their decoupling mechanisms and transmission formula rates. For PECO and ACE, reflects the change in regulatory assets and liabilities associated with their transmission formula rates. 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 2322 — Supplemental Financial 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, 2022 | | | | | | | | | | | | | | | | Cash and cash equivalents | $ | 407 | | | $ | 67 | | | $ | 59 | | | $ | 43 | | | $ | 198 | | | $ | 45 | | | $ | 31 | | | $ | 72 | | Restricted cash and cash equivalents | 566 | | | 327 | | | 9 | | | 24 | | | 175 | | | 54 | | | 121 | | | — | | Restricted cash included in other long-term assets | 117 | | | 117 | | | — | | | — | | | — | | | — | | | — | | | — | | Total cash, restricted cash, and cash equivalents | $ | 1,090 | | | $ | 511 | | | $ | 68 | | | $ | 67 | | | $ | 373 | | | $ | 99 | | | $ | 152 | | | $ | 72 | | | | | | | | | | | | | | | | | | December 31, 2021 | | | | | | | | | | | | | | | | Cash and cash equivalents | $ | 672 | | | $ | 131 | | | $ | 36 | | | $ | 51 | | | $ | 136 | | | $ | 34 | | | $ | 28 | | | $ | 29 | | Restricted cash and cash equivalents | 321 | | | 210 | | | 8 | | | 4 | | | 77 | | | 34 | | | 43 | | | — | | Restricted cash included in other long-term assets | 44 | | | 43 | | | — | | | — | | | — | | | — | | | — | | | — | | | | | | | | | | | | | | | | | | Cash, restricted cash, and cash equivalents included in current assets of discontinued operations | 582 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | Total cash, restricted cash, and cash equivalents | $ | 1,619 | | | $ | 384 | | | $ | 44 | | | $ | 55 | | | $ | 213 | | | $ | 68 | | | $ | 71 | | | $ | 29 | | | | | | | | | | | | | | | | | | December 31, 2020 | | | | | | | | | | | | | | | | Cash and cash equivalents | $ | 432 | | | $ | 83 | | | $ | 19 | | | $ | 144 | | | $ | 111 | | | $ | 30 | | | $ | 15 | | | $ | 17 | | Restricted cash and cash equivalents | 349 | | | 279 | | | 7 | | | 1 | | | 39 | | | 35 | | | — | | | 3 | | Restricted cash included in other long-term assets | 53 | | | 43 | | | — | | | — | | | 10 | | | — | | | — | | | 10 | | Cash, restricted cash, and cash equivalents included in current assets of discontinued operations | 332 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | 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(a) | $ | 1,122 | | | $ | 403 | | | $ | 27 | | | $ | 25 | | | $ | 181 | | | $ | 63 | | | $ | 13 | | | $ | 28 | | __________ | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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 |
|
(a)Exelon's amounts include amounts related to Generation prior to the separation. See Note 2 — Discontinued Operations for additional information.
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 2322 — 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 | | | | | December 31, 2022 | | | | | | | | | | | | | | | | Equity method investments: | | | | | | | | | | | | | | | | Other equity method investments | $ | 16 | | | $ | 6 | | | $ | 8 | | | $ | — | | | $ | — | | | $ | — | | | | | | Other investments: | | | | | | | | | | | | | | | | Employee benefit trusts and investments(a) | 216 | | | — | | | 22 | | | 7 | | | 138 | | | 119 | | | | | | Total investments | $ | 232 | | | $ | 6 | | | $ | 30 | | | $ | 7 | | | $ | 138 | | | $ | 119 | | | | | | | | | | | | | | | | | | | | | | December 31, 2021 | | | | | | | | | | | | | | | | Equity method investments: | | | | | | | | | | | | | | | | Other equity method investments | $ | 15 | | | $ | 6 | | | $ | 7 | | | $ | — | | | $ | — | | | $ | — | | | | | | Other investments: | | | | | | | | | | | | | | | | Employee benefit trusts and investments(a) | 235 | | | — | | | 27 | | | 14 | | | 145 | | | 120 | | | | | | | | | | | | | | | | | | | | | | Total investments | $ | 250 | | | $ | 6 | | | $ | 34 | | | $ | 14 | | | $ | 145 | | | $ | 120 | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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, 2022 | | | | | | | | | | | | | | | | Compensation-related accruals(a) | $ | 613 | | | $ | 179 | | | $ | 81 | | | $ | 79 | | | $ | 104 | | | $ | 29 | | | $ | 20 | | | $ | 16 | | Taxes accrued | 211 | | | 92 | | | 10 | | | 34 | | | 70 | | | 52 | | | 8 | | | 12 | | Interest accrued | 338 | | | 124 | | | 47 | | | 42 | | | 61 | | | 32 | | | 9 | | | 14 | | | | | | | | | | | | | | | | | | December 31, 2021 | | | | | | | | | | | | | | | | Compensation-related accruals(a) | $ | 596 | | | $ | 155 | | | $ | 77 | | | $ | 78 | | | $ | 113 | | | $ | 35 | | | $ | 20 | | | $ | 17 | | Taxes accrued | 253 | | | 94 | | | 14 | | | 53 | | | 96 | | | 88 | | | 9 | | | 11 | | Interest accrued | 297 | | | 116 | | | 41 | | | 44 | | | 52 | | | 28 | | | 8 | | | 11 | |
__________ | | (a) | 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 23 — Supplemental Financial Information
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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. |
24.23. Related Party Transactions (All Registrants)
Operating revenues from affiliates
Utility Registrants' expense with Generation The followingUtility Registrants incurred expenses from transactions with the Generation affiliate as described in the footnotes to the table presents Generation’s Operating revenues from affiliates, which arebelow prior to separation on February 1, 2022. Such expenses were primarily recorded as Purchased power from affiliates and an immaterial amount recorded as Operating and maintenance expense from affiliates at the Utility Registrants: | | | | | | | | | | | | | | 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 |
|
267 __________
| | (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. |
Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)
Note 2423 — Related Party Transactions
| | (g) | Generation provides electric supply to ACE under contracts executed through ACE's competitive procurement process. |
PHI | | | | | | | | | | | | | | | | | | | For the Years Ended December 31, | | 2022 | | 2021 | | 2020 | ComEd(a) | $ | 59 | | | $ | 376 | | | $ | 330 | | PECO(b) | 33 | | | 196 | | | 190 | | BGE(c) | 18 | | | 236 | | | 315 | | PHI | 51 | | | 366 | | | 367 | | Pepco(d) | 39 | | | 270 | | | 279 | | DPL(e) | 10 | | | 79 | | | 75 | | ACE(f) | 2 | | | 17 | | | 13 | |
PHI’s Operating revenues__________
(a)ComEd had an ICC-approved RFP contract with Generation to provide a portion of ComEd’s electric supply requirements. ComEd also purchased RECs and ZECs from affiliates are primarilyGeneration. (b)PECO received electric supply from Generation under contracts executed through PECO’s competitive procurement process. In addition, PECO had a ten-year agreement with BSCGeneration to sell solar AECs. (c)BGE received a portion of its energy requirements from Generation under its MDPSC-approved market-based SOS and gas commodity programs. (d)Pepco received electric supply from Generation under contracts executed through Pepco's competitive procurement process approved by the MDPSC and DCPSC. (e)DPL received a portion of its energy requirements from Generation under its MDPSC and DEPSC approved market-based SOS commodity programs. (f)ACE received electric supply from Generation under contracts executed through ACE's competitive procurement process approved by the NJBPU. Service Company Costs for services that PHISCO provides to BSC.Corporate Support Operating and maintenance expense from affiliates
The Registrants receive a variety of corporate support services from BSC. Pepco, DPL, and ACE also receive corporate support services from PHISCO. See Note 1 -— Significant Accounting Policies for additional information regarding BSC and PHISCO. The following table presents the service company costs allocated to the Registrants:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Operating and maintenance from affiliates | | 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 |
| | — |
|
268 __________
| | (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 2423 — 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, | | | 2022 | | 2021 | | 2020 | | 2022 | | 2021 | | 2020 | Exelon | | | | | | | | | | | | | BSC | | | | | | | | $ | 707 | | | $ | 508 | | | $ | 531 | | PHISCO | | | | | | | | 80 | | | 72 | | | 61 | | ComEd | | | | | | | | | | | | | BSC | | $ | 316 | | | $ | 304 | | | $ | 283 | | | 311 | | | 207 | | | 186 | | PECO | | | | | | | | | | | | | BSC | | 197 | | | 169 | | | 150 | | | 115 | | | 81 | | | 76 | | BGE | | | | | | | | | | | | | BSC | | 204 | | | 189 | | | 170 | | | 122 | | | 92 | | | 132 | | PHI | | | | | | | | | | | | | BSC | | 188 | | | 168 | | | 152 | | | 159 | | | 128 | | | 149 | | PHISCO | | — | | | — | | | — | | | 80 | | | 72 | | | 61 | | Pepco | | | | | | | | | | | | | BSC | | 110 | | | 96 | | | 85 | | | 60 | | | 50 | | | 55 | | PHISCO | | 112 | | | 114 | | | 120 | | | 33 | | | 31 | | | 27 | | DPL | | | | | | | | | | | | | BSC | | 71 | | | 61 | | | 54 | | | 45 | | | 43 | | | 51 | | PHISCO | | 96 | | | 99 | | | 97 | | | 26 | | | 22 | | | 18 | | ACE | | | | | | | | | | | | | BSC | | 57 | | | 53 | | | 45 | | | 54 | | | 33 | | | 40 | | PHISCO | | 84 | | | 86 | | | 87 | | | 21 | | | 19 | | | 16 | |
Current Receivables from/Payables to affiliates The following tables present current receivablesReceivables from affiliates and current payablesPayables to affiliates: December 31, 20192022 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Receivables from affiliates: | | | Payables to affiliates: | | ComEd | | PECO | | BGE | | | | Pepco | | DPL | | ACE | | BSC | | PHISCO | | Other | | Total | ComEd | | | | $ | — | | | $ | — | | | | | $ | — | | | $ | — | | | $ | — | | | $ | 66 | | | $ | — | | | $ | 8 | | | $ | 74 | | PECO | | $ | — | | | | | — | | | | | — | | | — | | | — | | | 39 | | | — | | | 3 | | | 42 | | BGE | | — | | | — | | | | | | | — | | | — | | | — | | | 38 | | | — | | | 1 | | | 39 | | PHI | | — | | | — | | | — | | | | | — | | | — | | | — | | | 4 | | | — | | | 10 | | | 14 | | Pepco | | — | | | — | | | — | | | | | | | — | | | — | | | 20 | | | 13 | | | 1 | | | 34 | | DPL | | — | | | 2 | | | — | | | | | — | | | | | — | | | 12 | | | 8 | | | — | | | 22 | | ACE | | — | | | 2 | | | — | | | | | — | | | — | | | | | 14 | | | 9 | | | 1 | | | 26 | | Other | | 3 | | | — | | | — | | | | | — | | | — | | | 1 | | | — | | | — | | | | | 4 | | Total | | $ | 3 | | | $ | 4 | | | $ | — | | | | | $ | — | | | $ | — | | | $ | 1 | | | $ | 193 | | | $ | 30 | | | $ | 24 | | | $ | 255 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
269
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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 2423 — Related Party Transactions
December 31, 2021
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Receivables from affiliates: | | | Payables to affiliates: | | ComEd | | PECO | | BGE | | | | Pepco | | DPL | | ACE | | Generation | | BSC | | PHISCO | | Other | | Total | ComEd | | | | $ | — | | | $ | — | | | | | $ | — | | | $ | — | | | $ | — | | | $ | 41 | | | $ | 71 | | | $ | — | | | $ | 9 | | | $ | 121 | | PECO | | $ | — | | | | | — | | | | | — | | | — | | | — | | | 30 | | | 36 | | | — | | | 4 | | | 70 | | BGE | | — | | | — | | | | | | | — | | | — | | | — | | | 4 | | | 41 | | | — | | | 3 | | | 48 | | PHI | | — | | | 1 | | | — | | | | | — | | | — | | | 1 | | | — | | | 5 | | | — | | | 9 | | | 16 | | Pepco | | — | | | — | | | 1 | | | | | | | 1 | | | 1 | | | 20 | | | 21 | | | 12 | | | 3 | | | 59 | | DPL | | — | | | — | | | — | | | | | — | | | | | — | | | 4 | | | 17 | | | 11 | | | 1 | | | 33 | | ACE | | — | | | — | | | — | | | | | — | | | — | | | | | 7 | | | 13 | | | 9 | | | 2 | | | 31 | | Generation | | 13 | | | — | | | — | | | | | — | | | — | | | — | | | | | 102 | | | — | | | 16 | | | 131 | | Other | | 3 | | | — | | | — | | | | | — | | | — | | | — | | | 11 | | | — | | | — | | | | | 14 | | Total | | $ | 16 | | | $ | 1 | | | $ | 1 | | | | | $ | — | | | $ | 1 | | | $ | 2 | | | $ | 117 | | | $ | 306 | | | $ | 32 | | | $ | 47 | | | $ | 523 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Borrowings from Exelon/PHI intercompany money pool To provide an additional short-term borrowing option that will generally be more favorable to the borrowing participants than the cost of external financing both Exelon and PHI operate an intercompany money pool. Generation, ComEd, PECO, and PHI Corporate participate in the Exelon money pool. Pepco, DPL, and ACE participate in the PHI intercompany money pool. Noncurrent Receivables from/Payables tofrom affiliates Generation has long-term payables to ComEd and PECO as a result of the nuclear decommissioning contractual construct whereby, to the extent NDThave noncurrent receivables with Constellation for estimated excess funds are greater than the underlying ARO at the end of decommissioning the Regulatory Agreement Units, such amounts are due back to ComEd and PECO, as applicable, for payment to their respective customers. The receivables are recorded in Receivable related to Regulatory Agreement Units as of December 31, 2022 and in noncurrent Receivables from affiliates as of December 31, 2021. See Note 93 — Asset Retirement ObligationsRegulatory Matters of the Combined Notes to Consolidated Financial Statements 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, | | 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 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | As of December 31, | | 2022 | | 2021 | | Exelon | | ComEd | | PECO | | Exelon | | ComEd | | PECO | ComEd Financing III | $ | 206 | | | $ | 205 | | | $ | — | | | $ | 206 | | | $ | 205 | | | $ | — | | PECO Trust III | 81 | | | — | | | 81 | | | 81 | | | — | | | 81 | | PECO Trust IV | 103 | | | — | | | 103 | | | 103 | | | — | | | 103 | | Total | $ | 390 | | | $ | 205 | | | $ | 184 | | | $ | 390 | | | $ | 205 | | | $ | 184 | |
Long-term debt to affiliatesCharitable Contributions
In connectionDecember 2022, Exelon Corporation made an unconditional promise to give $20 million to the Exelon Foundation. The contribution was recorded in Operating and maintenance expense within the Consolidated Statements of Operations and Comprehensive Income with the debt obligations assumed by Exelon as part ofoffset in Accrued expenses and Other Deferred credits and other liabilities on 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.Sheets.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 25 — Quarterly Data
25. Quarterly Data (Unaudited) (All Registrants)
Exelon
The data shown below, which may not equal the total for the year due to the effects of rounding and dilution, includes all adjustments that Exelon considers necessary for a fair presentation of such amounts:
| | | | | | | | | | | | | | | | | | | | | | | | | | 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 |
|
270
__________
| | | | | | (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 2019,2022, 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’sRegistrant’s periodic reports that it files with the SEC. These disclosure controls and procedures have been designed by each registrantthe Registrants to ensure that (a) material 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’sRegistrant’s management, including its principal executive officer and principal financial officer, by other employees of that registrantRegistrant 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, 2019,2022, 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 theirits objectives. All Registrants—Changes in Internal Control Over Financial Reporting Each registrantRegistrant 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 20192022 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, 2019.2022. As a result of that assessment, management determined that there were no material weaknesses as of December 31, 20192022 and, therefore, concluded that each registrant’sRegistrant’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, 2020.14, 2023. 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 20202023 proxy statement (2020(2023 Exelon Proxy Statement) and the ComEd information statement (2020(2023 ComEd Information Statement) to be filed with the SEC on or before April 30, 20202023 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 20202023 Annual Meeting of Shareholders or the ComEd 20202023 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 20202023 Exelon Proxy Statement or the ComEd 20202023 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 | 3,991,435 | | | $ | — | | | 43,893,655 | |
__________ | | (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 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 2020, 2021, and 2022, 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 2,512,560 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 1,256,280. The balance also includes 471,350 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 20 — Stock-Based Compensation Plans of the Combined Notes to Consolidated Financial Statements for additional information about the material features of the plans. (2)There are no outstanding stock options. 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 12,662,529 shares remaining available for issuance from the employee stock purchase plan. 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 20202023 Annual Meeting of Shareholders or the ComEd 20202023 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 20202023 in the Exelon Proxy Statement for the 20202023 Annual Meeting of Shareholders and the ComEd 20202023 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, 202014, 2023 of PricewaterhouseCoopers LLP (PCAOB ID 238) | | | | | Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2019, 20182022, 2021, and 20172020 | | | | | | Consolidated Statements of Cash Flows for the Years Ended December 31, 2019, 20182022, 2021, and 20172020 | | | | | | Consolidated Balance Sheets at December 31, 20192022 and 20182021 | | | | | | Consolidated Statements of Changes in Equity for the Years Ended December 31, 2018, 20172022, 2021, and 20162020 | | | | | | Notes to Consolidated Financial Statements | | | | (ii) | | Financial Statement Schedules: | | | | | | Schedule I—Condensed Financial Information of Parent (Exelon Corporate) at December 31, 20192022 and 20182021 and for the Years Ended December 31, 2019, 20182022, 2021, and 20172020 | | | | | | Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2019, 20182022, 2021, and 2017
2020 | | | | | | 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) | 2022 | | 2021 | | 2020 | Operating expenses | | | | | | Operating and maintenance | $ | 25 | | | $ | (9) | | | $ | (2) | | Operating and maintenance from affiliates | 4 | | | 14 | | | 10 | | Other | 2 | | | 2 | | | 2 | | Total operating expenses | 31 | | | 7 | | | 10 | | Operating loss | (31) | | | (7) | | | (10) | | Other income and (deductions) | | | | | | Interest expense, net | (413) | | | (333) | | | (378) | | Equity in earnings of investments | 2,450 | | | 1,908 | | | 1,482 | | Interest income from affiliates, net | 5 | | | — | | | 1 | | Other, net | 22 | | | — | | | 15 | | Total other income | 2,064 | | | 1,575 | | | 1,120 | | Income from continuing operations before income taxes | 2,033 | | | 1,568 | | | 1,110 | | Income taxes | (21) | | | (48) | | | 11 | | Net income from continuing operations after income taxes | 2,054 | | | 1,616 | | | 1,099 | | Net income from discontinued operations after income taxes | 116 | | | 90 | | | 864 | | Net income | $ | 2,170 | | | $ | 1,706 | | | $ | 1,963 | | Other comprehensive income (loss), net of income taxes | | | | | | Pension and non-pension postretirement benefit plans: | | | | | | Prior service benefit reclassified to periodic costs | $ | (1) | | | $ | (4) | | | $ | (40) | | Actuarial loss reclassified to periodic cost | 42 | | | 223 | | | 190 | | Pension and non-pension postretirement benefit plan valuation adjustment | 46 | | | 431 | | | (357) | | Unrealized gain (loss) on cash flow hedges | 2 | | | — | | | (1) | | Other comprehensive income (loss) | 89 | | | 650 | | | (208) | | Comprehensive income | $ | 2,259 | | | $ | 2,356 | | | $ | 1,755 | |
| | | | | | | | | | | | | | 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
377278
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) | 2022 | | 2021 | | 2020 | Net cash flows provided by operating activities | $ | 1,690 | | | $ | 3,629 | | | $ | 3,018 | | Cash flows from investing activities | | | | | | Changes in Exelon intercompany money pool | 35 | | | 381 | | | (477) | | Notes receivable from affiliates | 274 | | | — | | | 550 | | | | | | | | Investment in affiliates | (4,011) | | | (2,231) | | | (1,969) | | | | | | | | Other investing activities | — | | | 1 | | | — | | Net cash flows used in investing activities | (3,702) | | | (1,849) | | | (1,896) | | Cash flows from financing activities | | | | | | Changes in short-term borrowings | 448 | | | — | | | (136) | | Proceeds from short-term borrowings with maturities greater than 90 days | 1,150 | | | 500 | | | — | | Repayments on short-term borrowings with maturities greater than 90 days | (1,300) | | | (350) | | | — | | Issuance of long-term debt | 3,350 | | | — | | | 2,000 | | Retirement of long-term debt | (1,150) | | | (300) | | | (1,450) | | Issuance of common stock | 563 | | | — | | | — | | | | | | | | Dividends paid on common stock | (1,334) | | | (1,497) | | | (1,492) | | Proceeds from employee stock plans | 36 | | | 80 | | | 45 | | Other financing activities | (35) | | | 19 | | | (27) | | Net cash flows provided by (used in) financing activities | 1,728 | | | (1,548) | | | (1,060) | | (Decrease) increase in cash, restricted cash, and cash equivalents | (284) | | | 232 | | | 62 | | Cash, restricted cash, and cash equivalents at beginning of period | 295 | | | 63 | | | 1 | | Cash, restricted cash, and cash equivalents at end of period | $ | 11 | | | $ | 295 | | | $ | 63 | |
See the Notes to Financial Statements
378279
Exelon Corporation and Subsidiary Companies Schedule I – Condensed Financial Information of Parent (Exelon Corporate) Condensed Balance Sheets | | | | | | | | | | | | | December 31, | (In millions) | 2022 | | 2021 | ASSETS | | | | Current assets | | | | Cash and cash equivalents | $ | 11 | | | $ | 295 | | | | | | | | | | Accounts receivable, net | | | | Other accounts receivable | 358 | | | 318 | | Accounts receivable from affiliates | 17 | | | 35 | | Notes receivable from affiliates | 182 | | | 217 | | Regulatory assets | 154 | | | 266 | | Other | 6 | | | 41 | | Total current assets | 728 | | | 1,172 | | Property, plant, and equipment, net | 44 | | | 45 | | Deferred debits and other assets | | | | Regulatory assets | 2,650 | | | 3,164 | | Investments in affiliates from continuing operations | 35,925 | | | 29,563 | | Investments in affiliates from discontinued operations | — | | | 12,333 | | Deferred income taxes | 929 | | | 1,351 | | Non-pension postretirement benefit asset | 187 | | | — | | Notes receivable from affiliates | — | | | 319 | | Other | 115 | | | 42 | | Total deferred debits and other assets | 39,806 | | | 46,772 | | Total assets | $ | 40,578 | | | $ | 47,989 | |
| | | | | | | | | | 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
379280
Exelon Corporation and Subsidiary Companies Schedule I – Condensed Financial Information of Parent (Exelon Corporate) Condensed Balance Sheets | | | | | | | | | | | | | December 31, | (In millions) | 2022 | | 2021 | LIABILITIES AND SHAREHOLDERS’ EQUITY | | | | Current liabilities | | | | Short-term borrowings | $ | 948 | | | $ | 650 | | Long-term debt due within one year | 850 | | | 1,150 | | Accounts payable | 188 | | | — | | | | | | Accrued expenses | 101 | | | 47 | | | | | | Payables to affiliates | 360 | | | 360 | | Regulatory liabilities | 12 | | | 3 | | Pension obligations | 77 | | | 49 | | Other | 7 | | | 40 | | Total current liabilities | 2,543 | | | 2,299 | | Long-term debt | 8,742 | | | 6,265 | | | | | | Deferred credits and other liabilities | | | | Regulatory liabilities | 103 | | | 63 | | Pension obligations | 3,896 | | | 4,416 | | Non-pension postretirement benefit obligations | — | | | 87 | | | | | | Deferred income taxes | 53 | | | 362 | | Other | 497 | | | 104 | | Total deferred credits and other liabilities | 4,549 | | | 5,032 | | Total liabilities | 15,834 | | | 13,596 | | Commitments and contingencies | | | | Shareholders’ equity | | | | Common stock (No par value, 2,000 shares authorized, 994 shares and 979 shares outstanding as of December 31, 2022 and 2021, respectively) | 20,908 | | | 20,324 | | Treasury stock, at cost (2 shares as of December 31, 2022 and 2021) | (123) | | | (123) | | Retained earnings | 4,597 | | | 16,942 | | Accumulated other comprehensive loss, net | (638) | | | (2,750) | | Total shareholders’ equity | 24,744 | | | 34,393 | | | | | | Total liabilities and shareholders’ equity | $ | 40,578 | | | $ | 47,989 | |
| | | | | | | | | | 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
380281
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, 2022 and 2021, 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),. As of which Exelon owns 100%February 1, 2022, as a result of the common stock but nonecompletion of BGE’s preferred stock.the separation, Exelon Corporate no longer retains any equity ownership interest in Generation or Constellation. The separation of Constellation, including Generation and its subsidiaries, meets the criteria for discontinued operations and as such, results of operations are presented as discontinued operations and have been excluded from continuing operations for all periods presented. Accounting rules require that certain BSC costs previously allocated to Generation be presented as part of Exelon’s continuing operations as these costs do not qualify as expenses of the discontinued operations. Comprehensive income and cash flows related to Generation have not been segregated and are included in the Condensed Statements of Operations and Comprehensive Income and Condensed Statements of Cash Flows, respectively, for all periods presented. See Note 2 — Discontinued Operations of the Combined Notes to Consolidated Financial Statements for additional information. 2. Derivative Financial Instruments See Note 15—Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for Exelon Corporate’s derivatives. 3. 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$449 million of in outstanding commercial paper borrowings atas of December 31, 20192022 and no outstanding commercial paper borrowings atas of December 31, 2018.2021. 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, 201914, 2022 and will expire on March 19, 2020.16, 2023. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBORSOFR plus 0.95%0.65% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Exelon’s ConsolidatedExelon Corporation's Balance SheetSheets within Short-TermShort-term borrowings. Revolving Credit Agreements
On May 26, 2016,March 31, 2021, Exelon Corporate amended its syndicated revolving credit facilityentered into a 364-day term loan agreement for $150 million with aggregate bank commitmentsa variable interest rate of $600 million through May 26, 2021. On May 26, 2018,LIBOR plus 0.65% and an expiration date of March 30, 2022. Exelon Corporate had its maturity date extended to May 26, 2023. As of December 31, 2019, Exelon Corporation had available capacity under those commitments of $458 million. See Note 16—Debt and Credit Agreements ofrepaid the Combined Notes to Consolidated Financial Statements for additional information regarding Exelon Corporation’s credit agreement.term loan on March 30, 2022. Long-Term Debt
The following tables presentIn connection with the outstanding long-term debt forseparation, on January 24, 2022, Exelon Corporate asentered into a 364-day term loan agreement for $1.15 billion. The loan agreement was set to expire on January 23, 2023. Pursuant to the loan agreement, loans made thereunder bore interest at a variable rate equal to SOFR plus 0.75% until July 23, 2022 and a rate of December 31, 2019 and December 31, 2018:
| | | | | | | | | | | | | | | | | | | | | | Maturity Date | | December 31, | | Rates | | 2019 | | 2018 | Long-term debt | | | | | | | | | | Junior subordinated notes | | | 3.50 | % | | 2022 | | $ | 1,150 |
| | $ | 1,150 |
| Senior unsecured notes(a) | 2.45 | % | - | 7.60 | % | | 2020 - 2046 | | 5,889 |
| | 5,889 |
| Total long-term debt | | | | | | | 7,039 |
| | 7,039 |
| Unamortized debt discount and premium, net | | | | | | | (7 | ) | | (7 | ) | Unamortized debt issuance costs | | | | | | | (39 | ) | | (47 | ) | Fair value adjustment | | | | | | | 182 |
| | 162 |
| Long-term debt due within one year | | | | | | | (1,458 | ) | | — |
| Long-term debt | | | | | | | $ | 5,717 |
|
| $ | 7,147 |
|
__________
| | (a) | Senior unsecured notes include mirror debt that is held on both Generation and Exelon Corporation's balance sheets. |
The debt maturities forSOFR plus 0.975% thereafter. All indebtedness pursuant to the loan agreement was unsecured. On August 11, 2022, Exelon Corporate formade a partial repayment of $575 million on the periods 2020, 2021,term loan. The remaining $575 million outstanding balance was repaid on October 11, 2022 2023, 2024 and thereafter are as follows:in conjunction with the $500 million 18-month term loan that was entered into on October 7, 2022.
Exelon Corporation and Subsidiary Companies Schedule I – Condensed Financial Information of Parent (Exelon Corporate) Notes to Financial Statements
Revolving Credit Agreements
As of December 31, 2022, Exelon Corporation had a $900 million aggregate bank commitment under its existing syndicated revolving facility in which $448 million was available to support additional commercial paper as of December 31, 2022. See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information regarding Exelon Corporate’s credit agreement. | | | | | 2020 | $ | 1,458 |
| 2021 | 300 |
| 2022 | 1,150 |
| 2023 | — |
| 2024 | — |
| Remaining years | 4,131 |
| Total long-term debt | $ | 7,039 |
|
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.Long-Term Debt The following tables present the outstanding long-term debt for Exelon Corporate as of December 31, 2022 and December 31, 2021: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Maturity Date | | December 31, | | Rates | | 2022 | | 2021 | Long-term debt | | | | | | | | | | Junior subordinated notes | | | 3.50 | % | | 2022 | | $ | — | | | $ | 1,150 | | | | | | | | | | | | Senior unsecured notes(a) | 2.75 | % | - | 7.60 | % | | 2025 - 2052 | | 8,139 | | | 6,139 | | Loan agreement | 4.95 | % | - | 5.15 | % | | 2023 - 2024 | | 1,350 | | | — | | Total long-term debt | | | | | | | 9,489 | | | 7,289 | | Unamortized debt discount and premium, net | | | | | | | (10) | | | (10) | | Unamortized debt issuance costs | | | | | | | (51) | | | (39) | | Fair value adjustment | | | | | | | 164 | | | 175 | | Long-term debt due within one year(b) | | | | | | | (850) | | | (1,150) | | Long-term debt | | | | | | | $ | 8,742 | | | $ | 6,265 | |
__________
(a)Senior unsecured notes included mirror debt that was held on Exelon Corporation's Balance Sheet in 2021. 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 16 — Debt and Credit Agreements for additional information on the merger debt.
(b)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%. 3.The long-term debt maturities for Exelon Corporate for the periods 2023 through 2027 and thereafter are as follows:
| | | | | | 2023 | $ | 850 | | 2024 | 500 | | 2025 | 807 | | 2026 | 750 | | 2027 | 650 | | Thereafter | 5,932 | | Total long-term debt | $ | 9,489 | |
4. 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.contingencies. 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) | 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
5. 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) | 2022 | | 2021 | | 2020 | Operating and maintenance from affiliates: | | | | | | BSC(a) | $ | 4 | | | $ | 14 | | | $ | 10 | | | | | | | | Total operating and maintenance from affiliates: | $ | 4 | | | $ | 14 | | | $ | 10 | | Interest income (expense) from affiliates, net: | | | | | | | | | | | | BSC | $ | 4 | | | $ | — | | | $ | 1 | | EEDC(b) | 1 | | | — | | | — | | Total interest income from affiliates, net: | $ | 5 | | | $ | — | | | $ | 1 | | Equity in earnings (losses) of investments: | | | | | | BSC | $ | (18) | | | $ | (301) | | | $ | (273) | | EEDC(b) | 2,482 | | | 2,215 | | | 1,729 | | | | | | | | PCI | (9) | | | (1) | | | — | | | | | | | | | | | | | | Exelon InQB8R | (4) | | | (7) | | | (1) | | | | | | | | | | | | | | Other | (1) | | | 2 | | | 27 | | Total equity in earnings of investments: | $ | 2,450 | | | $ | 1,908 | | | $ | 1,482 | | | | | | | | Cash contributions received from affiliates | $ | 2,027 | | | $ | 1,842 | | | $ | 1,638 | |
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) | 2022 | | 2021 | Accounts receivable from affiliates (current): | | | | Accounts receivable from affiliates (current): | | | | BSC(a) | $ | 11 |
| | $ | 13 |
| BSC(a) | $ | 3 | | | $ | 4 | | Generation | 13 |
| | 17 |
| Generation | — | | | 13 | | ComEd | 2 |
| | 4 |
| ComEd | 4 | | | 5 | | PECO | 2 |
| | 2 |
| PECO | 2 | | | 4 | | BGE | 1 |
| | 2 |
| BGE | 1 | | | 2 | | PHISCO | 7 |
| | 6 |
| PHISCO | 7 | | | 6 | | Exelon VTI, LLC | 5 |
| | — |
| | Exelon Enterprises | | Exelon Enterprises | — | | | 1 | | | Total accounts receivable from affiliates (current): | $ | 41 |
| | $ | 44 |
| Total accounts receivable from affiliates (current): | $ | 17 | | | $ | 35 | | Notes receivable from affiliates (current): | | | | Notes receivable from affiliates (current): | | | | BSC(a) | $ | 109 |
| | $ | 116 |
| BSC(a) | $ | 138 | | | $ | 210 | | Generation(c) | 558 |
| | 100 |
| | | PHI | 12 |
| | — |
| PHI | 44 | | | 7 | | Total notes receivable from affiliates (current): | $ | 679 |
| | $ | 216 |
| Total notes receivable from affiliates (current): | $ | 182 | | | $ | 217 | | Investments in affiliates: | | | | | Investments in affiliates from continuing operations: | | Investments in affiliates from continuing operations: | | | | BSC(a) | $ | 197 |
| | $ | 197 |
| BSC(a) | $ | 384 | | | $ | 146 | | Exelon Energy Delivery Company, LLC(b) | 28,147 |
| | 26,679 |
| | Generation | 13,484 |
| | 13,204 |
| | EEDC(b) | | EEDC(b) | 35,092 | | | 32,621 | | PCI | 62 |
| | 61 |
| PCI | 52 | | | 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 | 4 | | | 3 | | Exelon Enterprises | 6 |
| | 22 |
| Exelon Enterprises | 3 | | | 3 | | Exelon INQB8R, LLC | (8 | ) | | — |
| | Conectiv | | Conectiv | 12 | | | — | | Exelon InQB8R | | Exelon InQB8R | 15 | | | 26 | | Other(d) | (4 | ) | | (6 | ) | (2) | | | (3,663) | | Total investments in affiliates: | $ | 42,245 |
| | $ | 40,425 |
| | Notes receivable from affiliates (non-current): | | | | | Total investments in affiliates from continuing operations: | | Total investments in affiliates from continuing operations: | $ | 35,925 | | | $ | 29,563 | | Notes receivable from affiliates (noncurrent): | | Notes receivable from affiliates (noncurrent): | | | | Generation(c) | $ | 329 |
| | $ | 898 |
| Generation(c) | $ | — | | | $ | 319 | | | Accounts payable to affiliates (current): | | | | Accounts payable to affiliates (current): | | UII, LLC | $ | 360 |
| | $ | 360 |
| | Exelon Enterprises | 3 |
| | — |
| | | UII | | UII | $ | 360 | | | $ | 360 | | | Total accounts payable to affiliates (current): | $ | 363 |
| | $ | 360 |
| Total accounts payable to affiliates (current): | $ | 360 | | | $ | 360 | |
__________ | | (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. (d)Primarily relates to elimination of affiliate transactions with Generation, primarily related to the Regulatory Agreement Units. See Note 3 — Regulatory Matters and Note 23 — Related Party Transactions of the Combined Notes to Consolidated Financial Statements for additional information. Charitable Contributions In December 2022, Exelon Corporation made an unconditional promise to give $20 million to the Exelon Foundation. The contribution was recorded in Operating and maintenance expense within the Condensed Statements of Operations and Comprehensive Income with the offset in Accrued expenses and Other Deferred credits and other liabilities on the Condensed Balance Sheets.
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, 2022 | | For the year ended December 31, 2022 | | Allowance for credit losses(a) | | Allowance for credit losses(a) | | $ | 392 | |
| $ | 174 | | (b) | $ | 28 | | | $ | 185 | | (c) | $ | 409 | | Deferred tax valuation allowance | | 35 |
|
| — |
|
| (9 | ) |
| — |
| | 26 |
| Deferred tax valuation allowance | | 37 | |
| — | |
| 57 | | | — | | | 94 | | Reserve for obsolete materials | | 156 |
|
| 6 |
|
| — |
| (d) | 7 |
| | 155 |
| Reserve for obsolete materials | | 13 | |
| 8 | | | — | | | 6 | | | 15 | | 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, 2021 | | For the year ended December 31, 2021 | |
| |
| |
| | Allowance for credit losses(a) | | Allowance for credit losses(a) | | $ | 405 | |
| $ | 107 | | (b) | $ | — | |
| $ | 120 | | (c) | $ | 392 | | Deferred tax valuation allowance | | 37 |
|
| — |
|
| 5 |
|
| 7 |
| | 35 |
| Deferred tax valuation allowance | | 4 | |
| — | |
| 33 | | (d) | — | | | 37 | | Reserve for obsolete materials | | 174 |
|
| 25 |
|
| (31 | ) |
| 12 |
| | 156 |
| Reserve for obsolete materials | | 11 | |
| 5 | |
| — | | | 3 | | | 13 | | 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, 2020 | | For the year ended December 31, 2020 | |
| |
| |
| | Allowance for credit losses(a) | | Allowance for credit losses(a) | | $ | 213 | |
| $ | 228 | | (b) | $ | 38 | | | $ | 74 | | (c) | $ | 405 | | Deferred tax valuation allowance | | 20 |
|
| — |
|
| 17 |
| (b) | — |
| | 37 |
| Deferred tax valuation allowance | | 2 | |
| — | |
| 2 | | | — | | | 4 | | Reserve for obsolete materials | | 113 |
|
| 56 |
|
| 10 |
| (b) | 5 |
| | 174 |
| Reserve for obsolete materials | | 12 | |
| 5 | |
| — | | | 6 | | | 11 | |
__________ | | (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 noncurrent allowance for credit losses related to PECO’s installment plan receivables of $7 million, $14 million, and $5 million for the years ended December 31, 2022, 2021, and 2020, 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 13 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information on the valuation allowance.
Commonwealth Edison Company LLC and Subsidiary Companies (2) Generation | | | | | | | | | (i) | | Financial Statements (Item 8): | | | | | Report of Independent Registered Public Accounting Firm dated February 11, 202014, 2023 of PricewaterhouseCoopers LLP (PCAOB ID 238) | | | | | Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2019, 20182022, 2021, and 20172020 | | | | | Consolidated Statements of Cash Flows for the Years Ended December 31, 2019, 20182022, 2021, and 20172020 | | | | | Consolidated Balance Sheets at December 31, 20192022 and 20182021 | | | | | Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2019, 20182022, 2021, and 20172020 | | | | | Notes to Consolidated Financial Statements | | | (ii) | | Financial Statement Schedule: | | | | | Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2019, 20182022, 2021, and 2017
2020 | | | | | 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, 2022 | | | | | | | | | | | Allowance for credit losses | | $ | 90 | | | $ | 24 | | (a) | $ | 8 | | | $ | 46 | | (b) | $ | 76 | | Reserve for obsolete materials | | 7 | | | 5 | | | — | |
| 4 | | | 8 | | 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 | |
__________ | | (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): | | | | | Report of Independent Registered Public Accounting Firm dated February 11, 202014, 2023 of PricewaterhouseCoopers LLP (PCAOB ID 238) | | | | | Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2019, 20182022, 2021, and 20172020 | | | | | Consolidated Statements of Cash Flows for the Years Ended December 31, 2019, 20182022, 2021, and 20172020 | | | | | Consolidated Balance Sheets at December 31, 20192022 and 20182021 | | | | | Consolidated Statements of Changes in Shareholders’Shareholder's Equity for the Years Ended December 31, 2019, 20182022, 2021, and 20172020 | | | | | Notes to Consolidated Financial Statements | | | (ii) | | Financial Statement Schedule: | | | | | Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2019, 20182022, 2021, and 2017
2020 | | | | | 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 | | | | | 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 | | $ | 81 |
|
| $ | 35 |
|
| $ | 20 |
| (a) | $ | 57 |
| (b) | $ | 79 |
| Reserve for obsolete materials | | 6 |
|
| 6 |
|
| — |
|
| 5 |
| | 7 |
| 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 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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, 2022 | | | | | | | | | | | Allowance for credit losses(a) | | $ | 112 | |
| $ | 44 | | (b) | $ | 14 | | | $ | 56 | | (c) | $ | 114 | | Deferred tax valuation allowance | | 3 | | | — | | | 4 | | | — | | | 7 | | Reserve for obsolete materials | | 2 | |
| 2 | | | — | | | 1 | | | 3 | | For the year ended December 31, 2021 | | |
| | | | | | | | Allowance for credit losses(a) | | $ | 124 | |
| $ | 32 | | (b) | $ | (6) | | | $ | 38 | | (c) | $ | 112 | | Deferred tax valuation allowance | | 1 | | | — | | | 2 | | | — | | | 3 | | Reserve for obsolete materials | | 2 | |
| 1 | | | — | | | 1 | | | 2 | | For the year ended December 31, 2020 | | |
| | | | | | | | Allowance for credit losses(a) | | $ | 62 | |
| $ | 76 | | (b) | $ | 6 | | | $ | 20 | | (c) | $ | 124 | | Deferred tax valuation allowance | | — | | | — | | | 1 | | | — | | | 1 | | Reserve for obsolete materials | | 2 | |
| 1 | |
| — | |
| 1 | | | 2 | |
__________ (a)Excludes the noncurrent allowance for credit losses related to PECO’s installment plan receivables of $7 million, $14 million, and $5 million for the years ended December 31, 2022, 2021, and 2020, 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) | Primarily charges for late payments and non-service receivables. |
| | (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, 202014, 2023 of PricewaterhouseCoopers LLP (PCAOB ID 238) | | | | | Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2019, 20182022, 2021 and 20172020 | | | | | Consolidated Statements of Cash Flows for the Years Ended December 31, 2019, 20182022, 2021 and 20172020 | | | | | Consolidated Balance Sheets at December 31, 20192022 and 20182021 | | | | | Consolidated Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2019, 20182022, 2021 and 20172020 | | | | | Notes to Consolidated Financial Statements | | | (ii) | | Financial Statement Schedule: | | | | | Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2019, 20182022, 2021, and 2017
2020 | | | | | 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 | | | | | 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(a) | | $ | 61 |
|
| $ | 31 |
|
| $ | 3 |
| (b) | $ | 33 |
| (c) | $ | 62 |
| Reserve for obsolete materials | | 2 |
|
| — |
|
| — |
|
| — |
| | 2 |
| 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 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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, 2022 | | | | | | | | | | | Allowance for credit losses | | $ | 47 | |
| $ | 37 | | (a) | $ | 6 | |
| $ | 26 | | (b) | $ | 64 | | Deferred tax valuation allowance | | — | |
| — | | | 3 | |
| — | | | 3 | | Reserve for obsolete materials | | 1 | |
| 1 | | | — | |
| — | | | 2 | | For the year ended December 31, 2021 | | |
| | | |
| | | | Allowance for credit losses | | $ | 44 | |
| $ | 16 | | (a) | $ | 3 | |
| $ | 16 | | (b) | $ | 47 | | | | | | | | | | | | | Reserve for obsolete materials | | 1 | |
| — | | | — | |
| — | | | 1 | | For the year ended December 31, 2020 | | |
| | | |
| | | | Allowance for credit losses | | $ | 17 | |
| $ | 31 | | (a) | $ | 6 | |
| $ | 10 | | (b) | $ | 44 | | Deferred tax valuation allowance | | 1 | | | — | | | (1) | | | — | | | — | | Reserve for obsolete materials | | 1 | | | — | | | — | | | — | | | 1 | |
__________ | | (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): | | | | | Report of Independent Registered Public Accounting Firm dated February 11, 202014, 2023 of PricewaterhouseCoopers LLP (PCAOB ID 238) | | | | | Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2019, 20182022, 2021, and 20172020 | | | | | Consolidated Statements of Cash Flows for the Years Ended December 31, 2019, 20182022, 2021, and 20172020 | | | | | Consolidated Balance Sheets at December 31, 20192022 and 20182021 | | | | | Consolidated Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2019, 20182022, 2021, and 20172020 | | | | | Notes to Consolidated Financial Statements | | | | (ii) | | Financial Statement Schedule: | | | | | Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2019, 20182022, 2021, and 2017
2020 | | | | | | 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, 2022 | | For the year ended December 31, 2022 | | Allowance for credit losses | | Allowance for credit losses | | $ | 143 | | | $ | 69 | | (a) | $ | — | | | $ | 57 | | (b) | $ | 155 | | Deferred tax valuation allowance | | 1 |
|
| — |
|
| — |
|
| — |
| | 1 |
| Deferred tax valuation allowance | | 31 | | | — | | | 4 | | | — | | | 35 | | Reserve for obsolete materials | | 1 |
|
| — |
|
| — |
|
| — |
| | 1 |
| Reserve for obsolete materials | | 3 | | | — | | | — | | | 1 | | | 2 | | For the year ended December 31, 2018 | |
|
|
|
|
|
|
| |
|
| | Allowance for uncollectible accounts | | $ | 24 |
|
| $ | 10 |
|
| $ | (2 | ) |
| $ | 12 |
| (a) | $ | 20 |
| | 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, 2017 | |
|
|
|
|
|
|
| |
|
| | Allowance for uncollectible accounts | | $ | 32 |
|
| $ | 8 |
|
| $ | (3 | ) |
| $ | 13 |
| (a) | $ | 24 |
| | Deferred tax valuation allowance | | 1 |
| | — |
| | — |
| | — |
| | 1 |
| | 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 | |
__________ (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 13 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information on the valuation allowance.
Potomac Electric Power Company (6) Pepco | | (a) | Write-off of individual accounts receivable. |
Pepco Holdings LLC and Subsidiary Companies
(6) PHI
| | | | | (i) | | Financial Statements (Item 8): | | | | | Report of Independent Registered Public Accounting Firm dated February 11, 202014, 2023 of PricewaterhouseCoopers LLP (PCAOB ID 238) | | | | | Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2019, 20182022, 2021 and 20172020 | | | | | Consolidated Statements of Cash Flows for the Years Ended December 31, 2019, 20182022, 2021 and 20172020 | | | | | Consolidated Balance Sheets at December 31, 20192022 and 20182021 | | | | | Consolidated Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2019, 20182022, 2021 and 20172020 | | | | | Notes to Consolidated Financial Statements | | | | (ii) | | Financial Statement Schedule: | | | | | Schedule II – II—Valuation and Qualifying Accounts for the Years Ended December 31, 2019, 20182022, 2021, and 20172020 | | | | | | 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, 2022 | | | | | | | | | | | Allowance for credit losses | | $ | 53 | | | $ | 36 | | (a) | $ | 4 | | | $ | 21 | | (b) | $ | 72 | | | | | | | | | | | | | Reserve for obsolete materials | | 1 | | | — | | | — | | | — | | | 1 | | 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 | |
__________ (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.
Delmarva Power & Light Company (7) DPL | | (a) | Primarily charges for late payments. |
| | (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, 202014, 2023 of PricewaterhouseCoopers LLP (PCAOB ID 238) | | | | | Statements of Operations and Comprehensive Income for the Years Ended December 31, 2019, 20182022, 2021 and 20172020 | | | | | Statements of Cash Flows for the Years Ended December 31, 2019, 20182022, 2021 and 20172020 | | | | | Balance Sheets at December 31, 20192022 and 20182021 | | | | | Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2019, 20182022, 2021 and 20172020 | | | | | Notes to Financial Statements | | | (ii) | | Financial Statement Schedule: | | | | | Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2019, 20182022, 2021, and 2017
2020 | | | | | 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, 2022 | | | | | | | | | | | Allowance for credit losses | | $ | 26 | | | $ | 13 | | (a) | $ | (2) | | | $ | 9 | | (b) | $ | 28 | | Deferred tax valuation allowance | | 31 | | | — | | | 1 | |
| — | | | 32 | | | | | | | | | | | | | 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 | | | | | | | | | | | | | | | | | | | | | | | |
__________ (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 13 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information on the valuation allowance.
Atlantic City Electric Company and Subsidiary Company (8) ACE | | (a) | Primarily charges for late payments. |
| | (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, 202014, 2023 of PricewaterhouseCoopers LLP (PCAOB ID 238) | | | | | Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2019, 20182022, 2021, and 20172020 | | | | | Consolidated Statements of Cash Flows for the Years Ended December 31, 2019, 20182022, 2021, and 20172020 | | | | | Consolidated Balance Sheets at December 31, 20192022 and 20182021 | | | | | Consolidated Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2019, 20182022, 2021, and 20172020 | | | | | Notes to Consolidated Financial Statements | | | (ii) | | Financial Statement Schedule: | | | | | Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2019, 20182022, 2021, and 2017
2020 | | | | | 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 | | | | | 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 | | $ | 19 |
| | $ | 5 |
| | $ | 2 |
| (a) | $ | 8 |
| (b) | $ | 18 |
| 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 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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, 2022 | | | | | | | | | | | Allowance for credit losses | | $ | 64 | | | $ | 20 | | (a) | $ | (2) | | | $ | 27 | | (b) | $ | 55 | | | | | | | | | | | | | Reserve for obsolete materials | | 1 | | | — | | | — | | | — | | | 1 | | For the year ended December 31, 2021 | | | | | | | | | | | Allowance for credit losses | | $ | 43 | | | $ | 21 | | (a) | $ | 1 | | | $ | 1 | | (b) | $ | 64 | | | | | | | | | | | | | Reserve for obsolete materials | | — | | | 1 | | | — | | | — | | | 1 | | For the year ended December 31, 2020 | | | | | | | | | | | Allowance for credit losses | | $ | 18 | | | $ | 28 | | (a) | $ | 4 | | | $ | 7 | | (b) | $ | 43 | | | | | | | | | | | | | 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.
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. (2) Plans of acquisition, reorganization, arrangement, liquidation, or succession | | | | | | | | | | | | | | | | | | Exhibit No. | Description | | | | | | | | | | Location | | | | |
(3) Articles of Incorporation and Bylaws Exelon Corporation | | | | | | | | | | | | | | | | | | Exhibit No. | Description | | | | Location | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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). | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
|
Baltimore Gas and Electric Company | | | | | | | | | | | | | | | | | | Exhibit No. | Description | | Location | | Articles of Restatement to the Charter of Baltimore Gas and Electric Company, restated as of August 16, 1996 | | | | | | | | | | Articles of Amendment to the Charter of Baltimore Gas and Electric Company as of February 2, 2010 | | | | | | | | | | Amended and Restated Bylaws of Baltimore Gas and Electric Company dated August 3, 2020 | | |
Commonwealth Edison Company | | | | | | | | | | | | | | | | | | Exhibit No. | Description | | Location | | Restated Articles of Incorporation of Commonwealth Edison Company Effective February 20, 1985, including Statements of Resolution Establishing Series, relating to the establishment of three new series of Commonwealth Edison Company preference stock known as the “$9.00 Cumulative Preference Stock,” the “$6.875 Cumulative Preference Stock” and the “$2.425 Cumulative Preference Stock” (File | | | | | | | | | | | | |
PECO Energy Company | | | | | | | | | | | | | | | | | | Exhibit No. | Description | | Location | | | | | | | | | | | | | | | | | | | | | | | | | | |
Pepco Holdings LLC | | | | | | | | | | | | | | | | | | Exhibit No. | Description | | Location | | | | | | | | | | | | | | |
Atlantic City Electric Company | | | | | | | | | | | | | | | | | | Exhibit No. | Description | | Location | | | | | | | | | | | | | | | | | | | | | | | | Bylaws of Atlantic City Electric Company | | |
Delmarva Power & Light Company | | | | | | | | | | | | | | | | | | Exhibit No. | Description | | Location | | Restated Certificate and Articles of Incorporation of Delmarva Power & Light Company (as filed in Delaware and Virginia) | | | | | | | | | | Bylaws of Delmarva Power & Light Company | | |
Potomac Electric Power Company | | | | | | | | | | | | | | | | | | Exhibit No. | Description | | Location | | Restated Articles of Incorporation of Potomac Electric Power Company (as filed in the District of Columbia) | | | | | | | | | | Restated Articles of Incorporation and Articles of Restatement of Potomac Electric Power Company (as filed in Virginia) | | | | | | | | | | Bylaws of Potomac Electric Power Company (File | | | | | | | | | | |
(4) Instruments Defining the Rights of Securities Holders, Including Indentures
| | | | | | | | | | | | | | | | | | Exhibit No. | Description | | Location | | Exelon Corporation Direct Stock Purchase Plan | | | | | | | | | Exhibit No. | Description | | | | | 4-1 | First and Refunding MortgageIndenture dated May 1, 19232001 between Exelon Corporation and The Counties Gas and Electric Company (predecessor to PECO Energy Company) and FidelityBank of New York Mellon Trust Company, Trustee (U.S. Bank National Association, as current successor trustee), (Registrationtrustee
| | | | | | | | | 4-1-1 | Supplemental Indentures to PECO Energy Company’s First and Refunding Mortgage: |
| | | | | | | | Dated asForm of $500,000,000 5.625% senior notes due 2035 dated June 9, 2005 issued by Exelon Corporation | | File Reference | | Exhibit No. | | December 1, 1941 | | 2-4863(a)
| | B-1(h) | | | | | | April 15, 2004 | | 0-6844, September 30, 2004 Form 10-Q(a)
| | 4-1-1 | | | | | | 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 | | | | |
| | | | | | | | Indenture, dated as of June 17, 2014, between Exelon Corporation and The Bank of New York Mellon Trust Company, N.A., as Trustee | | | Description4.1 | | | | | | | | | | | | | | | | | 4-3 | 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 | | | | | | | | | | Indenture, dated as of June 11, 2015, among Exelon Corporation and The Bank of New York Mellon Trust Company, National Association, as trustee | | | | | | | | | | First Supplemental Indenture, dated as of June 11, 2015, among Exelon Corporation and The Bank of New York Mellon Trust Company, National Association, as trustee | | | | | | | | |
| | | | | | | | | | | | | | | | | | Exhibit No. | Description | | Location | | Second Supplemental Indenture, dated as of December 2, 2015, among Exelon Corporation and The Bank of New York Mellon Trust Company, National Association, as trustee | | | | | | | | | | Third Supplemental Indenture, dated as of April 7, 2016, among Exelon Corporation and The Bank of New York Mellon Trust Company, N.A., as trustee | | | | | | | | | | Fourth Supplemental Indenture, dated as of April 1, 2020, among Exelon Corporation and The Bank of New York Mellon Trust Company, N.A., as trustee | | | | | | | | | | Fifth Supplemental Indenture, dated as of March 7, 2022, among Exelon Corporation and The Bank of New York Mellon Trust Company, N.A., as trustee | | | | | | | | | | Description of Exelon Securities | | |
Baltimore Gas and Electric Company | | | | | | | | | | | | | | | | | | Exhibit No. | Description | | Location | | Form of 3.350% Note due 2023 issued June 17, 2013 by Baltimore Gas and Electric Company | | | | | | | | | | Indenture dated as of July 24, 2006 between Baltimore Gas and Electric Company and Deutsche Bank Trust Company Americas, as trustee | | | | | | | | | | Form of 2.400% notes due 2026 issued August 18, 2016 by Baltimore Gas and Electric Company | | | | | | | | | | Form of 3.500% Note due 2046 issued August 18, 2016 by Baltimore Gas and Electric Company | | | | | | | | | | Form of 3.750% Note due 2047 issued August 24, 2017 by Baltimore Gas and Electric Company | | | | | | | | | | Form of 4.550% Note due 2052 issued June 6, 2022 by Baltimore Gas and Electric Company | | | | | | | | | | Indenture, dated as of September 1, 2019, between Baltimore Gas and Electric Company and U.S. Bank National Association, as trustee | | |
Commonwealth Edison Company | | | | | | | | | | | | | | | | | | Exhibit No. | Description | | Location | 4-14 | 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. (Registration1944 | | Registration No. 2-60201, Form S-7, Exhibit 2-1).2-1(a) |
| | | | | | | Exhibit No. | Description | 4-3-1 | Supplemental IndenturesIndenture to Commonwealth Edison Company Mortgage. | | | | | | | | DatedMortgage dated as of | | File Reference | | | | January 13, 2003 | | | | | | | | | | Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of February 22, 2006 | | | | | | | | | | August 1, 2006 | | | | | | | | | | September 15, 2006 | | | | | | | | | | as of March 1, 2007 | | | | | | | | | | August 30, 2007 | | | | | | | | | | Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of December 20, 2007 | | | | | | | | | | March 10, 2008 | | | | | | | | | | | | July 12, 2010 | | | | | | | | | | August 22, 2011 | | | | | | | | | | as of September 17, 2012 | | | | | | | | | | Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of August 1, 2013 | | | | | | | | | | Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of January 2, 2014 | | | | | | | | | | | | October 28, 2014 | | | | | | | | | | | | February 18, 2015 | | | | | | | | | | | | November 4, 2015 | | | | | | | | | | | | June 15, 2016 | | | | | | | | | | | | August 9, 2017 | | | | |
| | | | | | | | DatedSupplemental Indenture to Commonwealth Edison Company Mortgage dated as of October 28, 2014 | | | | No. 001-01839, Form 8-K dated November 10, 2014, Exhibit 4.1 | | | | | | | | Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of February 18, 2015 | | | | | | | | | | Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of November 4, 2015 | | | | | | | | | | Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of June 15, 2016 | | | | | | | | | | Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of August 9, 2017 | | | | | | | | |
| | | | | | | | | | | | | | | | | | Exhibit No. | Description | | Location | | Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of February 6, 2018 | | | | | | | | | | | | Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of July 26, 2018 | | | | | | | | | | | | Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of February 7, 2019 | | | | | | | | | | | | Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of October 29, 2019 | | | | |
| | | Exhibit No. | Description | | | | Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of February 10, 2020 | | | | | | | | | | Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of February 16, 2021 | | | | | | | | | | Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of August 2, 2021 | | | | | | | | | | Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of February 23, 2022 | | | | | | | | | | Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of December 21, 2022 | | | | | | | | | | 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 | | | | | | | | | | | | | | | | | | | | Description of ComEd Securities | | |
PECO Energy Company | | | | | | | | | | | | | | | | | | Exhibit No. | Description | | Location | 4-18 | 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) | | | | | | | 4-18-1 | Supplemental Indenture to PECO Energy Company’s First and Refunding Mortgage dated as of December 1, 1941 | | Registration No. 2-4863, Exhibit B-1(h)(a) | | | | | | | Supplemental Indenture to PECO Energy Company’s First and Refunding Mortgage dated as of April 15, 2004 | | | | | | | | | Supplemental Indenture to PECO Energy Company’s First and Refunding Mortgage dated as of September 15, 2006 | | | | | | | | | | Supplemental Indenture to PECO Energy Company’s First and Refunding Mortgage dated as of March 1, 2007 | | | | | | | | | | Supplemental Indenture to PECO Energy Company’s First and Refunding Mortgage dated as of September 1, 2012 | | | | | | | | | | Supplemental Indenture to PECO Energy Company’s First and Refunding Mortgage dated as of September 1, 2014 | | | | | | | | | | Supplemental Indenture to PECO Energy Company’s First and Refunding Mortgage dated as of September 15, 2015 | | | | | | | | | | Supplemental Indenture to PECO Energy Company’s First and Refunding Mortgage dated as of September 1, 2017 | | | | | | | | | | Supplemental Indenture to PECO Energy Company’s First and Refunding Mortgage dated as of February 1, 2018 | | | | | | | | | | Supplemental Indenture to PECO Energy Company’s First and Refunding Mortgage dated as of September 1, 2018 | | | | | | | | | | Supplemental Indenture to PECO Energy Company’s First and Refunding Mortgage dated as of August 15, 2019 | | | | | | | | | | Supplemental Indenture to PECO Energy Company’s First and Refunding Mortgage dated as of June 1, 2020 | | | | | | | | | | Supplemental Indenture to PECO Energy Company’s First and Refunding Mortgage dated as of February 15, 2021 | | | | | | | | |
| | | | | | | | | | | | | | | | | | Exhibit No. | Description | | Location | | Supplemental Indenture to PECO Energy Company’s First and Refunding Mortgage dated as of September 1, 2021 | | | | | | | | | | Supplemental Indenture to PECO Energy Company’s First and Refunding Mortgage dated as of May 1, 2022 | | | | | | | | | | Supplemental Indenture to PECO Energy Company’s First and Refunding Mortgage dated as of August 1, 2022 | | | | | | | | | | Indenture to Subordinated Debt Securities dated as of June 24, 2003 between PECO Energy Company, as Issuer, and U.S. Bank National Association, as Trustee (File | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 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). | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Exhibit No. | Description | | | | | | | | | | | 4-39 | 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)
| | | 4-39-1 | Supplemental Indentures to Potomac Electric Power Company Mortgage. |
| | | | | | | | Dated asDescription of PECO Securities | | File Reference | | Exhibit No. | | | | | | | | December 10, 1939 | | | | B | | | | | | | | March 16, 2004 | | | | | | | | | | | | May 24, 2005 | | | | | | | | | | | | November 13, 2007 | | | | | | | | | | | | March 24, 2008 | | | | | | | | | | | | December 3, 2008 | | | | | | | | | | | | March 28, 2012 | | | | | | | | | | | | March10-K dated February 11, 2013 | | | | | | | | | | | | November 14, 2013 | | | | | | | | | | | | March 11, 2014 | | | | | | | | | | | | March 9, 2015 | | | | | | | | | | | | May 15, 2017 | | | | | | | | | | | | June 1, 2018 | | | |
| | | | | | | | May 2, 2019 | | | |
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Atlantic City Electric Company | | | | | | | | | | | | | | | | | | Exhibit No. | Description | | Location | 4-23 | 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 | | 2-66280, Registration Statement dated December 21, 1979, Exhibit 2(a)(a) | | | | | | | Exhibit No.4-23-1 | Description | 4-40 | Supplemental Indenture to Atlantic City Electric Company Mortgage dated as of JulyJune 1, 1949 | | 2-66280, Registration Statement dated December 21, 1979, Exhibit 2(b)(a) | | | | | | | 4-23-2 | Supplemental Indenture to Atlantic City Electric Company Mortgage dated as of March 1, 1991 | | Form 10-K dated March 28, 1989, between Potomac1991, Exhibit 4(d)(1)(a) | | | | | | | | Supplemental Indenture to Atlantic City Electric Power Company and The BankMortgage dated as of New York Mellon, Trustee, with respectApril 1, 2004 | | | | | | | | | | Supplemental Indenture to Medium-Term Note Program (FileAtlantic City Electric Company Mortgage dated as of March 8, 2006 | | | | | | | | | | Supplemental Indenture to Atlantic City Electric Company Mortgage dated as of March 29, 2011 | | | | | | | | | | Supplemental Indenture to Atlantic City Electric Company Mortgage dated as of August 18, 2014 | | | | | | | | | | Supplemental Indenture to Atlantic City Electric Company Mortgage dated as of December 1, 2015 | | | | | | | | | | Supplemental Indenture to Atlantic City Electric Company Mortgage dated as of October 9, 2018 | | | | | | | | | | Supplemental Indenture to Atlantic City Electric Company Mortgage dated as of May 2, 2019 | | | | | | | | | | Supplemental Indenture to Atlantic City Electric Company Mortgage dated as of June 1, 2020 | | | | | | | | | | | | | | | | | | | | Supplemental Indenture to Atlantic City Electric Company Mortgage dated as of November 17, 2003 between Potomac Electric Power Company and The Bank of New York Mellon (File1, 2021 | | | | | | | | | | | | | | | | | | | 4-42 | Pollution Control Facilities Loan Agreement, dated as of June 1, 2020, between The Pollution Control Financing Authority of Salem County and Atlantic City Electric | | |
Delmarva Power & Light Company | | | | | | | | | | | | | | | | | | Exhibit No. | Description | | Location | 4-25 | 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)4-(A)(a) | | | | | | | 4-42-14-25-1 | Supplemental IndenturesIndenture to Delmarva Power & Light Company Mortgage. | | | | | | | | DatedMortgage dated as of | | File Reference | | Exhibit No. | | | | | | | | October 1, 1993 | | 33-53855, Registration Statement 1/30/95dated January 30, 1995, Exhibit 4-L(a) | | 4-L | | | | | | | 4-25-2 | Supplemental Indenture to Delmarva Power & Light Company Mortgage dated as of October 1, 1994 | | 33-53855, Registration Statement 1/30/95dated January 30, 1995, Exhibit 4-N(a) | | 4-N | | | | | | | | January 1, 1997 | | | | | | | | | | | | Supplemental Indenture to Delmarva Power & Light Company Mortgage dated as of November 7, 2013 | | | | | | | | | | | | Supplemental Indenture to Delmarva Power & Light Company Mortgage dated as of June 2, 2014 | | | | | | | | | | | | Supplemental Indenture to Delmarva Power & Light Company Mortgage dated as of May 4, 2015 | | | | | | | | | | | | Supplemental Indenture to Delmarva Power & Light Company Mortgage dated as of December 5, 2016 | | | | | | | | | | | | April 5, 2017Supplemental Indenture to Delmarva Power & Light Company Mortgage dated as of June 1, 2018 | | | | | | | | | | Supplemental Indenture to Delmarva Power & Light Company Mortgage dated as of May 2, 2019 | | | | | | | | | | Supplemental Indenture to Delmarva Power & Light Company Mortgage dated as of January 1, 2020 | | | | | | April 3, 2018 | | | | | | | | | | | | Supplemental Indenture to Delmarva Power & Light Company Mortgage dated as of June 1, 20182020 | | | | | | | | | | | | April 3, 2019 | | | | | | | | | | | | May 2, 2019 | | | | | | | | | | Supplemental Indenture to Delmarva Power & Light Company Mortgage dated as of February 15, 2021 | | | | | | | | | | Supplemental Indenture to Delmarva Power & Light Company Mortgage dated as of February 1, 2022 | | | | | | | | |
| | | | | | | | | | | | | | | | | | Exhibit No. | Description | | Location | 4-43 | Supplemental Indenture betweento Delmarva Power & Light Company and The Bank of New York Mellon Trust Company, N.A. (ultimate successor to Manufacturers Hanover Trust Company), as trustee,Mortgage dated as of NovemberJanuary 1, 1988 (File2022 | | | | | | | | | | 4-44 | Gas Facilities Loan Agreement, dated as of July 1, 2020, between The Delaware Economic Development Authority and Delmarva Power & Light Company | | |
Potomac Electric Power Company | | | | | | | | | | | | | | | | | | Exhibit No. | Description | | Location | 4-27 | Mortgage and Deed of Trust, dated January 15, 1937, between Atlantic CityJuly 1, 1936, of Potomac Electric Power 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) | | | | | | | | 4-44-1 | Supplemental Indentures to Atlantic City Electric Company Mortgage. | | | | | | | | | Dated as of | | File Reference | | Exhibit No. | | | | | | | | | | June 1, 1949 | | 2-66280, Registration Statement, 12/21/79(a)
| | 2(b) | | | | | | | | | | March 1, 1991 | | Form 10-K, 3/28/91(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 | | | | File No. 001-03559,2-2232, Registration Statement dated June 19, 1936, Exhibit B-4(a) | | | | | | | 4-27-1 | Supplemental Indenture to Potomac Electric Power Company Mortgage dated as of December 10, 1939 | | 8-K dated January 3, 1940, Exhibit B(a) | | | | | | | | Supplemental Indenture to Potomac Electric Power Company Mortgage dated as of March 16, 2004 | | | | | | | | | | | | | | | | | | | | Supplemental Indenture to Potomac Electric Power Company Mortgage dated as of November 13, 2007 | | | | | | | | | | Supplemental Indenture to Potomac Electric Power Company Mortgage dated as of March 24, 2008 | | | | | | | | | | Supplemental Indenture to Potomac Electric Power Company Mortgage dated as of December 19, 2002 between Atlantic City Electric Transition Funding LLC and The Bank of New York Mellon, as trustee (File3, 2008 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Supplemental Indenture to Potomac Electric Power Company Mortgage dated as of March 11, 2014 | | | | | | | | |
| | | | | | | | | | | | | | | | | | Exhibit No. | Description | | Location | | Supplemental Indenture to Potomac Electric Power Company Mortgage dated as of March 9, 2015 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Second Supplemental Indenture to Potomac Electric Power Company Mortgage dated April 3,as of May 15, 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) | | | | | | | | | | | | | | | | | | | | | | | | | | Supplemental Indenture to Potomac Electric Power Company Mortgage dated as of May 2, 2019 | | | | | | | | | | Supplemental Indenture to Potomac Electric Power Company Mortgage dated as of February 12, 2020 | | | | | | | | | | Supplemental Indenture to Potomac Electric Power Company Mortgage dated as of February 15, 2021 | | | | | | | | | | Supplemental Indenture to Potomac Electric Power Company Mortgage dated as of March 1, 2022 | | | | | | | | | | Exempt Facilities Loan Agreement dated as of June 1, 2019 between the Maryland Economic Development Corporation and Potomac Electric Power Company (File | | |
(10) Material Contracts Exelon Corporation | | | | | | | | | | | | | | | | | | Exhibit No. | Description | | Location | | Transition Services Agreement, dated January 31, 2022, between Exelon Corporation and Constellation Energy Corporation | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Credit Agreement for $900,000,000 dated February 1, 2022, between Exelon Corporation and various financial institutions | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | Exhibit No. | Description | | Location | | | | | | | | |
| | | Exhibit No. | Description | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | |
| | | | | | | | Exelon Corporation 2020 Long-Term Incentive Plan (Effective April 28, 2020) | | | | | | | | | | Exelon Corporation 2020 Long-Term Incentive Plan Prospectus, dated May 27, 2020 | | | | | | | | | | Form of Restricted Stock Unit Award Notice and Agreement under the Exelon Corporation 2020 Long-Term Incentive Plan | | | | | | | | | | Form of Performance Share Award Notice and Agreement under the Exelon Corporation 2020 Long-Term Incentive Plan | | | | | | | | | | Exelon Corporation Senior Management Severance Plan (As Amended and Restated Effective January 1, 2020) * | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | |
| | | Exhibit No. | Description | | | | | | | | | | | | | | | | | | | | | | | | First Amendment to Exelon Corporation Executive Death Benefits Plan, Effective January 1, 2006 * | | | | | | | | |
| | | | | | | | | | | | | | | | | | Exhibit No. | Description | | Location | | Exelon Corporation Deferred Compensation Plan (As Amended and Restated Effective January 1, 2005) | | | | | | | | | | Exelon Corporation Stock Deferral Plan (As Amended and Restated Effective September 25, 2019) | | | | | | | | | | Form of Exelon Corporation Change in Control Agreement | | | | | | | | | | Letter Agreement, dated June 4, 2020, between Exelon Corporation and Various Financial Institutions (File William A. Von Hoene, Jr. | | |
Commonwealth Edison Company | | | | | | | | | | | | | | | | | | Exhibit No. | Description | | Location | | Deferred Prosecution Agreement, dated July 17, 2020, between Commonwealth Edison Company and the U.S. Department of Justice and the U.S. Attorney for the Northern District of Illinois | | | | | | | | | | | | |
Baltimore Gas and Electric Company | | | | | | | | | | | | | | | | | | Exhibit No. 99.2). | Description | | Location | | | | |
PECO Energy Company | | | | | | | | | | | | | | | | | | Exhibit No. | Description | | Location | | PECO Energy Company Supplemental Pension Benefit Plan (As Amended and Restated Effective January 1, 2009) | | | | | | | | | | Credit Agreement for $600,000,000 dated February 1, 2022, between PECO Energy Company and Various Financial Institutions (File No. 000-16844, Form 8-K dated March 23, 2011, Exhibit No. 99.3). | | | | | | | | | | | | | | | | | | 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). | | | | | | | | | | | | | | | | | | | | |
Atlantic City Electric Company, Potomac Electric Power Company, Delmarva Power & Light Company | | | | | | | | | | | | | | | | | | Exhibit No. | Description | | Location | | | | | | | | | | 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 for $900,000,000 dated as of AugustFebruary 1, 2011, by and among Pepco Holdings, Inc.,2022, between 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, | | | | | | 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) |
(14) Code of Ethics
| | | | | | | | | | | | | | | | | | 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 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Subsidiaries | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Consent of Independent Registered Public Accountants | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Power of Attorney (Exelon Corporation) | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | Exhibit No. | Description | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 24-11 | Reserved. | | | | | | | | | | | | | | | | | | | | Power of Attorney (Commonwealth Edison Company) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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) | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | Exhibit No. | Description | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Power of Attorney (Potomac Electric Power Company) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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, 20182022 filed by the following officers for the following registrants: |
| | | | | | 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, 20182022 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. (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 11th14th day of February, 2020.2023.
| | | | | | | | | | | | EXELON CORPORATION | | | | | By: | | /s/ CHRISTOPHER M. CRANECALVIN G. BUTLER, JR. | | Name: | | Christopher M. CraneCalvin G. Butler, Jr. | | 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 11th14th day of February, 2020.2023. | | | | | | | | | Signature | | Title | | | /s/ CHRISTOPHER M. CRANECALVIN G. BUTLER, JR. | | President, Chief Executive Officer (Principal Executive Officer) and Director | Christopher M. CraneCalvin G. Butler, Jr. | | | | /s/ JOSEPH NIGROJEANNE M. JONES | | Senior Executive Vice President and Chief Financial Officer (Principal Financial Officer) | Joseph NigroJeanne M. Jones | | | | /s/ FABIAN E. SOUZAJOSEPH R. TRPIK | | Senior Vice President and Corporate Controller (Principal Accounting Officer) | Fabian E. SouzaJoseph R. Trpik | |
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'NeillJohn F. Young | Marjorie Rodgers Cheshire | | Carlos Gutierrez | | | |
| | | | | | | | | | | | | | | By: | | /s/ GAYLE E. LITTLETON | | February 14, 2023 | 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 11th14th day of February, 2020.2023. | | | | | | | | | | | | 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 11th14th day of February, 2020.2023. | | | | 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
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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. JONESELISABETH J. GRAHAM | | Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer) | Jeanne M. JonesElisabeth J. Graham | | | | /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
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| | | | | | By:Calvin G. Butler, Jr. | | /s/ JOSEPH DOMINGUEZ | | February 11, 2020Zaldwaynaka Scott | Name:Ricardo Estrada | Smita Shah | | Joseph Dominguez | | | |
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, 202014, 2023 | 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 11th14th day of February, 2020.2023. | | | | | | | | | | | | 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 11th14th day of February, 2020.2023. | | | | | | | | | 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. VAHOSMARISSA HUMPHREY | | Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer) | David M. VahosMarissa Humphrey | | | | /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:Nicholas Bertram | | /s/ CARIM V. KHOUZAMI | | February 11, 2020Charisse R. Lillie | Name:Calvin G. Butler, Jr. | Sharmaine Matlock-Turner | Nelson A. Diaz | Carim V. KhouzamiMichael Nutter | John S. Grady | | | |
| | | | | | | | | | | | | | | By: | | /s/ MICHAEL A. INNOCENZO | | February 14, 2023 | 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 11th14th day of February, 2020.2023. | | | | | | | | | | | | 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 11th14th day of February, 2020.2023. | | | | | | | | | 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:Calvin G. Butler, Jr. | | /s/ DAVID M. VELAZQUEZ | | February 11, 2020Byron Marchant | Name:James R. Curtiss | Tim Regan | Keith Lee | David M. VelazquezAmy Seto | Rachel Garbow Monroe | Maria Harris Tildon | | |
| | | | | | | | | | | | | | | By: | | /s/ CARIM V. KHOUZAMI | | February 14, 2023 | 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 11th14th day of February, 2020.2023. | | | | | | | | | | | | 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 11th14th day of February, 2020.2023. | | | | | | | | | 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, 2020Benjamin Wu | Name:Charlene Dukes | Linda W. Cropp | Calvin G. Butler, Jr. | David M. Velazquez | Debra P. DiLorenzo | | |
| | | | | | | | | | | | | | | By: | | /s/ J. TYLER ANTHONY | | February 14, 2023 | 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 11th14th day of February, 2020.2023. | | | | | | | | | | | | 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 11th14th day of February, 2020.2023. | | | | | | | | | 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)
and Director | 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:Calvin G. Butler, Jr. | | /s/ DAVID M. VELAZQUEZ | | February 11, 2020Tamla Olivier | Name:Rodney Oddoye | Anne Bancroft | Elizabeth O'Donnell | David M. Velazquez | | | |
| | | | | | | | | | | | | | | By: | | /s/ J. TYLER ANTHONY | | February 14, 2023 | 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 11th14th day of February, 2020.2023. | | | | | | | | | | | | 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 11th14th day of February, 2020.2023. | | | | | | | | | 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 14, 2023 | 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 14th day of February, 2023. | | | | | | | | | | | | 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 14th day of February, 2023. | | | | | | | | | 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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