EDGAR 10-K Filing

Company CIK: 27879
Filing Year: 2023
Filename: 27879_10-K_2023_0001109357-23-000018.json

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ITEM 1. BUSINESS
ITEM 1.
General
Corporate Structure and Business and Other Information
Exelon is a utility services holding company engaged in 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 Business Service Territories
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
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, 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.
Utility Registrants
Utility Operations
Service Territories and Franchise Agreements
The following table presents the size of service territories, populations of each service territory, and the number of customers within each service territory for the Utility Registrants as of December 31, 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 square mile that includes both electric and natural gas services, and thus does not represent the combined total square mileage of electric and natural gas service territories.
(b)The total service territory population counts once only an individual who lives in a region that includes both electric and natural gas services, and thus does not represent the combined total population of electric and natural gas service territories.
(c)The number of total customers counts once only a customer who is both an electric and a natural gas customer, and thus does not represent the combined total of electric customers and natural gas customers.
The Utility Registrants have the necessary authorizations to perform their current business of providing regulated electric and natural gas distribution services in the various municipalities and territories in which they now supply such services. These authorizations include charters, franchises, permits, and certificates of public convenience issued by local and state governments and state utility commissions. ComEd's, BGE's (gas), Pepco DC's, and ACE's rights are generally non-exclusive while PECO's, BGE's (electric), Pepco MD's, and DPL's rights are generally exclusive. Certain authorizations are perpetual while others have varying expiration dates. The Utility Registrants anticipate working with the appropriate governmental bodies to extend or replace the authorizations prior to their expirations.
Utility Regulations
State utility commissions regulate the Utility Registrants' electric and gas distribution rates and service, issuances of certain securities, and certain other aspects of the business. The following table outlines the state commissions responsible for utility oversight:
Registrant Commission
ComEd ICC
PECO PAPUC
BGE MDPSC
Pepco DCPSC/MDPSC
DPL DEPSC/MDPSC
ACE NJBPU
The Utility Registrants are public utilities under the Federal Power Act subject to regulation by FERC related to transmission rates and certain other aspects of the utilities' business. The U.S. Department of Transportation also regulates pipeline safety and other areas of gas operations for PECO, BGE, and DPL. The U.S. Department of Homeland Security (Transportation Security Administration) provided new security directives in 2021 that regulate cyber risks for certain gas distribution operators. Additionally, the Utility Registrants are subject to NERC mandatory reliability standards, which protect the nation's bulk power system against potential disruptions from cyber and physical security breaches.
Seasonality Impacts on Delivery Volumes
The Utility Registrants' electric distribution volumes are generally higher during the summer and winter months when temperature extremes create demand for 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 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 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. The EPA’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

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ITEM 1A. RISK FACTORS
ITEM 1A. RISK FACTORS
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 primarily include:
•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.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
ITEM 1B. UNRESOLVED STAFF COMMENTS
All Registrants
None.

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ITEM 2. PROPERTIES
ITEM 2. PROPERTIES
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.

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ITEM 3. LEGAL PROCEEDINGS
ITEM 3. LEGAL PROCEEDINGS
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.

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ITEM 4. MINE SAFETY DISCLOSURE
ITEM 4. MINE SAFETY DISCLOSURES
Not Applicable
PART II
(Dollars in millions, except per share data, unless otherwise noted)

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
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.

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ITEM 6. SELECTED FINANCIAL DATA
ITEM 6. [RESERVED]

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
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 operations increased 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.
ComEd
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
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.
ComEd
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.
ComEd
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
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)
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, 2022 and 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.
PECO
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:
PECO
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.
PECO
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)
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.
PECO
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.
BGE
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
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 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.
BGE
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
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.
PHI
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.
Pepco
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)
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
Pepco
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.
Pepco
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)
Regulatory required programs 6
Total increase $ 36
The changes in Depreciation and amortization expense 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.
DPL
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.
DPL
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 %
DPL
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.
DPL
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% and 24.7% for the years ended December 31, 2022 and 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 rates.
ACE
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)
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.
ACE
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
ACE
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
Regulatory required programs(a)
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:
2022 vs. 2021
Increase
Depreciation and amortization(a)
$ 18
Regulatory asset amortization 2
Regulatory required programs(b)
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 in intercompany 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 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 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
REC commitments Note 3 - Regulatory Matters
ZEC commitments Note 3 - Regulatory Matters
DC PLUG obligation Note 3 - Regulatory Matters
Pension contributions Note 14 - Retirement Benefits
Credit Facilities
Exelon Corporate, ComEd, and BGE meet their short-term liquidity requirements primarily through the issuance of commercial paper. PECO meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the Exelon intercompany money pool. Pepco, DPL, and ACE meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the PHI intercompany money pool. PHI Corporate meets its short-term liquidity requirements primarily through the issuance of short-term notes and the Exelon intercompany money pool. The Registrants may use their respective credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit.
See Note 16 - Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ credit facilities and short term borrowing activity.
Capital Structure
As of December 31, 2022, 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 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. 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.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Registrants hold commodity and financial instruments that are exposed to the following market risks:
•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 rate risk associated with Exelon’s pension and OPEB plan trusts. See Note 14 - Retirement Benefits of the 2021 Recast Form 10-K for additional information.
•Interest rate risk associated with changes in interest rates for the Registrants’ outstanding long-term debt. This risk is significantly reduced as substantially all of the Registrants’ outstanding debt has fixed interest rates. There is inherent interest rate risk related to refinancing maturing debt by issuing new long-term debt. The Registrants use a combination of fixed-rate and variable-rate debt to manage interest rate exposure. See Note 16 - Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. In addition, 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, or to lock in rate levels on borrowings, which are typically designated as economic hedges. See Note 15 - Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
•Electric operating revenues risk associated with ComEd'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 manage risk to Exelon, which are typically accounted for as economic hedges. See Note 15 - Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
The Registrants operate primarily under cost-based rate regulation limiting exposure to the effects of market risk. Hedging programs are utilized to reduce exposure to energy and natural gas price volatility and have no direct earnings impacts as the costs are fully recovered through regulatory-approved recovery mechanisms.
Exelon manages these risks through risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of risk exposures. 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.
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 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 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 the floating-to-fixed energy swap contracts with unaffiliated suppliers.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
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, 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, 2022, Exelon’s internal control over financial reporting was effective.
The effectiveness of Exelon’s internal control over financial reporting as of December 31, 2022, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.
February 14, 2023
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, 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, 2022, ComEd’s internal control over financial reporting was effective.
February 14, 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, 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, 2022, PECO’s internal control over financial reporting was effective.
February 14, 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, 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, 2022, BGE’s internal control over financial reporting was effective.
February 14, 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, 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, 2022, PHI’s internal control over financial reporting was effective.
February 14, 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, 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, 2022, Pepco’s internal control over financial reporting was effective.
February 14, 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, 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, 2022, DPL’s internal control over financial reporting was effective.
February 14, 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, 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, 2022, ACE’s internal control over financial reporting was effective.
February 14, 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), (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 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, 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. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.
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 consolidated financial 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 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 $9.7 billion of regulatory assets and $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 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, Illinois
February 14, 2023
We have served as the Company’s auditor since 2000.
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders of Commonwealth Edison Company
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) (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 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 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 these consolidated 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 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 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. 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
Chicago, Illinois
February 14, 2023
We have served as the Company's auditor since 2000.
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders of PECO 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) (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 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 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 these consolidated 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 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 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. 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
Philadelphia, Pennsylvania
February 14, 2023
We have served as the Company's auditor since 1932.
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholder of Baltimore Gas and Electric Company
Opinion on the Financial Statements
We have audited the 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 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 $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 the Board 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 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 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 these consolidated 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 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 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. 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 14, 2023
We have served as the Company's auditor since 2001.
Report of Independent Registered Public Accounting Firm
To the 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, of Potomac Electric Power Company (the “Company”) 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) (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
To the 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 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 $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
To the 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 subsidiary (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 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 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 these consolidated 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 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 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. 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
Philadelphia, Pennsylvania
February 14, 2023
We have served as the Company's auditor since 1998.
Exelon Corporation and Subsidiary Companies
Consolidated Statements of Operations and Comprehensive Income
For the Years Ended December 31,
(In millions, except per share data) 2022 2021 2020
Operating revenues
Electric operating revenues $ 16,899 $ 16,245 $ 15,236
Natural gas operating revenues 2,018 1,522 1,421
Revenues from alternative revenue programs 161 171 6
Total operating revenues 19,078 17,938 16,663
Operating expenses
Purchased power 5,380 4,703 4,086
Purchased fuel 834 504 426
Purchased power and fuel from affiliates 159 1,178 1,209
Operating and maintenance 4,673 4,547 4,641
Depreciation and amortization 3,325 3,033 2,891
Taxes other than income taxes 1,390 1,291 1,232
Total operating expenses 15,761 15,256 14,485
(Loss) Gain on sales of assets and businesses (2) - 13
Operating income 3,315 2,682 2,191
Other income and (deductions)
Interest expense, net (1,422) (1,264) (1,282)
Interest expense to affiliates (25) (25) (25)
Other, net 535 261 208
Total other income and (deductions) (912) (1,028) (1,099)
Income from continuing operations before income taxes 2,403 1,654 1,092
Income taxes 349 38 (7)
Net income from continuing operations after income taxes 2,054 1,616 1,099
Net income from discontinued operations after income taxes (Note 2) 117 213 855
Net Income 2,171 1,829 1,954
Net income (loss) attributable to noncontrolling interests 1 123 (9)
Net income attributable to common shareholders $ 2,170 $ 1,706 $ 1,963
Amounts attributable to common shareholders:
Net income from continuing operations 2,054 1,616 1,099
Net income from discontinued operations 116 90 864
Net income attributable to common shareholders $ 2,170 $ 1,706 $ 1,963
Comprehensive income, net of income taxes
Net income $ 2,171 $ 1,829 $ 1,954
Other comprehensive income (loss), net of income taxes
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost (1) (4) (40)
Actuarial loss reclassified to periodic benefit cost 42 223 190
Pension and non-pension postretirement benefit plan valuation adjustment 46 432 (357)
Unrealized gain (loss) on cash flow hedges 2 (1) (3)
Unrealized gain on foreign currency translation - - 4
Other comprehensive income (loss) 89 650 (206)
Comprehensive income 2,260 2,479 1,748
Comprehensive income (loss) attributable to noncontrolling interests 1 123 (9)
Comprehensive income attributable to common shareholders $ 2,259 $ 2,356 $ 1,757
Average shares of common stock outstanding:
Basic 986 979 976
Assumed exercise and/or distributions of stock-based awards 1 1 1
Diluted(a)
987 980 977
Earnings per average common share from continuing operations
Basic $ 2.08 $ 1.65 $ 1.13
Diluted $ 2.08 $ 1.65 $ 1.13
Earnings per average common share from discontinued operations
Basic $ 0.12 $ 0.09 $ 0.88
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 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
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
See the Combined Notes to Consolidated Financial Statements
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
See the Combined Notes to Consolidated Financial Statements
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
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, 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
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
See the Combined Notes to Consolidated Financial Statements
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
See the Combined Notes to Consolidated Financial Statements
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
See the Combined Notes to Consolidated Financial Statements
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
See the Combined Notes to Consolidated Financial Statements
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
See the Combined Notes to Consolidated Financial Statements
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
See the Combined Notes to Consolidated Financial Statements
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
See the Combined Notes to Consolidated Financial Statements
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
See the Combined Notes to Consolidated Financial Statements
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
See the Combined Notes to Consolidated Financial Statements
PECO Energy 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 $ 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
Baltimore Gas and Electric Company
Statements of Operations and Comprehensive Income
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
Baltimore Gas and Electric Company
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
See the Combined Notes to Consolidated Financial Statements
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
See the Combined Notes to Consolidated Financial Statements
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
_____________
(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.
See the Combined Notes to Consolidated Financial Statements
Baltimore Gas and Electric Company
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
See the Combined Notes to Consolidated Financial Statements
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
See the Combined Notes to Consolidated Financial Statements
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
See the Combined Notes to Consolidated Financial Statements
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
See the Combined Notes to Consolidated Financial Statements
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
See the Combined Notes to Consolidated Financial Statements
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
See the Combined Notes to Consolidated Financial Statements
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
See the Combined Notes to Consolidated Financial Statements
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
See the Combined Notes to Consolidated Financial Statements
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
See the Combined Notes to Consolidated Financial Statements
Potomac Electric Power Company
Balance Sheets
December 31,
(In millions) 2022 2021
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings $ 299 $ 175
Long-term debt due within one year 4 313
Accounts payable 382 272
Accrued expenses 125 160
Payables to affiliates 34 59
Customer deposits 39 35
Regulatory liabilities 6 14
Merger related obligation 26 27
Other 93 55
Total current liabilities 1,008 1,110
Long-term debt 3,747 3,132
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits 1,382 1,275
Regulatory liabilities 455 549
Asset retirement obligations 39 45
Non-pension postretirement benefit obligations - 3
Other 244 314
Total deferred credits and other liabilities 2,120 2,186
Total liabilities 6,875 6,428
Commitments and contingencies
Shareholder's equity
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 1,015 1,173
Total shareholder's equity 3,782 3,475
Total liabilities and shareholder's equity $ 10,657 $ 9,903
_____________
(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
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
See the Combined Notes to Consolidated Financial Statements
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
See the Combined Notes to Consolidated Financial Statements
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
See the Combined Notes to Consolidated Financial Statements
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
See the Combined Notes to Consolidated Financial Statements
Delmarva Power & Light Company
Balance Sheets
December 31,
(In millions) 2022 2021
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings $ 115 $ 149
Long-term debt due within one year 584 83
Accounts payable 172 131
Accrued expenses 41 40
Payables to affiliates 22 33
Customer deposits 29 28
Regulatory liabilities 44 25
Other 136 59
Total current liabilities 1,143 548
Long-term debt 1,354 1,727
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits 869 803
Regulatory liabilities 380 441
Asset retirement obligations 13 16
Non-pension postretirement benefit obligations 9 11
Other 84 89
Total deferred credits and other liabilities 1,355 1,360
Total liabilities 3,852 3,635
Commitments and contingencies
Shareholder's equity
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 594 568
Total shareholder's equity 1,950 1,777
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 as of December 31, 2022 and 2021.
See the Combined Notes to Consolidated Financial Statements
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
See the Combined Notes to Consolidated Financial Statements
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
See the Combined Notes to Consolidated Financial Statements
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
See the Combined Notes to Consolidated Financial Statements
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
See the Combined Notes to Consolidated Financial Statements
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
See the Combined Notes to Consolidated Financial Statements
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
See the Combined Notes to Consolidated Financial Statements
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 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
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 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, 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, 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
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 be presented as part of Exelon’s continuing operations as these costs do not qualify as expenses of the discontinued operations. Comprehensive income, shareholders' equity, and cash flows related to Generation have not been segregated and are included in the Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Changes in Shareholders’ Equity, and Consolidated Statements of Cash Flows, respectively, for all periods presented. See Note 2 - Discontinued Operations for additional 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 pension and OPEB, unbilled energy revenues, allowance for credit losses, inventory reserves, goodwill and long-lived asset impairment assessments, derivative instruments, unamortized energy contracts, fixed asset depreciation, environmental costs and other loss contingencies, AROs, and taxes. Actual results could differ from those estimates.
Prior Period Adjustments and Reclassifications (Exelon, PHI, ACE)
In the first quarter of 2022, management identified an error related to an overstatement of the regulatory liability associated with ACE’s mechanism to recover the cost of Transition Bonds issued in 2002 and 2003 by ACE Funding. Management has concluded that the error was not material to previously issued financial statements for Exelon, PHI or ACE.
The error was corrected through a revision to ACE’s financial statements contained herein. The impact of the error correction was an $8 million increase to ACE’s opening Retained earnings as of January 1, 2021 with a corresponding reduction to Regulatory liabilities of $11 million and an increase to Deferred income taxes and unamortized investment tax credits of $3 million. The impact of the error to ACE’s Total operating revenues and Net income was less than $1 million for the year ended December 31, 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 year ended December 31, 2021.
The error was corrected in the Exelon and PHI financial statements for the year ended December 31, 2022 as it was not material, resulting in an increase to Net income of $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 (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) there is a reasonable expectation that rates designed to recover costs can be charged to and collected from customers. The 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, DEPSC, 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. The 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, the Registrants classify regulatory assets and liabilities with a recovery or settlement period greater than one year as both current and noncurrent in their Consolidated Balance Sheets, with the current portion representing the amount expected to be recovered from or refunded 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 noncurrent in the Registrants’ Consolidated Balance Sheets to align with the classification of the related deferred income tax balances.
The 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 power and natural gas and utility revenues from 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. The 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 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. 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.
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 state or local governments on the sale or distribution of electricity and 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 22 - Supplemental Financial Information for 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. Operating lease ROU assets are included in Other deferred debits and other assets and operating lease liabilities 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. Operating lease expense, finance lease expense, and variable lease payments are primarily recorded to Operating and maintenance expense 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 income is recognized in the period in which the related obligation is performed. Operating lease income and variable lease income are recorded to Operating revenues on the Registrants’ Statements of Operations and Comprehensive Income.
The Registrants’ operating and finance leases consist primarily of real estate including office buildings and vehicles and equipment. 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 federal 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 benefits in Interest expense, net or Other, net (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, 2022 and 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 the Utility Registrants.
ComEd Collateral held from suppliers associated with energy and REC procurement contracts, any over-recovered RPS costs and alternative compliance payments received from RES pursuant to FEJA, and costs for the remediation of an MGP site.
PECO Proceeds from the sales of assets that were subject to PECO’s mortgage indenture.
BGE Proceeds from the loan program for the completion of certain energy efficiency measures and collateral held from energy suppliers.
PHI(a)
Payment of merger commitments, collateral held from its energy suppliers associated with procurement contracts, and repayment of 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
__________
(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, 2022 and 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.
See Note 16 - Debt and Credit Agreements and Note 22 - Supplemental Financial Information for additional information.
Allowance for Credit Losses on Accounts Receivables (All Registrants)
The allowance for credit losses reflects the Registrants’ best estimates of losses on the customers' accounts receivable balances based on historical experience, current information, and reasonable and supportable forecasts.
The allowance for credit losses is developed by applying loss rates for each Utility 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 credit losses on customer accounts receivable.
The Registrants have certain non-customer receivables in Other deferred debits and other assets which primarily are with governmental agencies and other high-quality counterparties with no history of default. As such, the allowance for credit losses related to these receivables is not material. The Registrants monitor these balances and will record an allowance if there are indicators of a decline in credit quality. See Note 6 - Accounts 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 are generally included in inventory when purchased. Fossil fuel is expensed to Purchased power and fuel expense when used or sold. Materials and supplies generally includes transmission and distribution materials and are expensed to Operating and maintenance or capitalized to Property, plant, and equipment, as appropriate, when installed or used.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 1 - 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 and indirect construction costs including labor and related costs of departments associated with supporting construction activities. When appropriate, original cost also includes AFUDC for regulated property at the Utility Registrants. The cost of repairs and maintenance 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.
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 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.
AFUDC. 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 22 - Supplemental Financial Information for additional information.
Depreciation and Amortization (All Registrants)
Depreciation is generally recorded over the estimated service lives of property, plant, and equipment 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 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. 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. 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 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
Depreciation and amortization in the Registrants’ Consolidated Statements of Operations and Comprehensive Income when the recovery period is more than one year.
See Note 3 - Regulatory Matters and Note 22 - Supplemental Financial Information for additional information regarding the amortization of the Registrants' regulatory assets.
Asset Retirement Obligations (All Registrants)
The Registrants estimate and recognize a liability for their legal obligation to perform asset retirement activities even though the timing and/or methods of settlement may be conditional on future events. The Registrants update their AROs either annually or on a rotational basis at least once every three years, based on a risk profile, unless circumstances warrant more frequent updates. The updates factor in new cost estimates, credit-adjusted, risk-free rates (CARFR) and escalation rates, and the timing of cash flows. AROs are accreted throughout each year to reflect the time value of money for these present value obligations through an increase to regulatory assets. See Note 9 - Asset Retirement Obligations for additional information.
Guarantees (All Registrants)
If necessary, the Registrants recognize a liability at the time of issuance of a guarantee for the fair value of the obligations they have undertaken by issuing the guarantee. The liability 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 evaluate the carrying value of long-lived assets 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 specific regulatory disallowance, abandonment, or plans to dispose of a long-lived asset significantly before the end of its useful life. When the estimated undiscounted future cash flows attributable to the long-lived asset may not be recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset over its fair value.
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 assessed 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.
Derivative Financial Instruments (All Registrants)
Derivatives 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 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 recognized in earnings are recorded in Electric operating revenues, Purchased power and fuel, or Interest expense in the Consolidated Statements of Operations and Comprehensive Income based on the activity the transaction is economically hedging. Changes in fair value are also 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. 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 the hedged item. See Note 3 - Regulatory Matters and Note 15 - Derivative Financial Instruments for additional information.
Retirement Benefits (All Registrants)
Exelon sponsors defined benefit pension plans and OPEB plans for substantially 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.
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:
•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 cash payment to Constellation and for general corporate purposes. See Note 16 - Debt and Credit Agreements for additional information.
•Exelon made a cash payment of $1.75 billion to Constellation on January 31, 2022.
•Exelon contributed its equity ownership interest in Generation to Constellation. Exelon no longer retains any equity ownership interest in Generation or Constellation.
•Exelon transferred certain corporate assets and employee-related obligations to Constellation.
•Exelon received cash from Generation of $258 million to settle the intercompany loan on January 31, 2022. See Note 16 - Debt and Credit Agreements for additional information.
Continuing Involvement
In order to govern the ongoing relationships between Exelon and Constellation after the separation, and to facilitate an orderly transition, Exelon and Constellation have entered into several agreements, including the following:
•Separation Agreement - governs the rights and obligations between Exelon and Constellation regarding certain actions to be taken in connection with the separation, among others, including the allocation of assets and liabilities between Exelon and Constellation.
•Transition Services Agreement (TSA) - governs the terms and conditions of the services that Exelon will provide to Constellation and Constellation will provide to Exelon for an expected period of two years, provided that certain services may be longer than the term and services may be extended with approval from both parties. The services 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, 2022 to December 31, 2022, the amounts Exelon billed
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 2 - Discontinued 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 respective rights, responsibilities and obligations of Exelon and Constellation with respect to all tax matters, including tax liabilities and benefits, tax attributes, tax returns, tax contests and other tax sharing regarding U.S. federal, state, local and foreign income taxes, other tax matters and related tax returns. See Note 13 - Income Taxes for additional Information.
In addition, the Utility 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 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 separation represented a strategic shift that would have a major effect on Exelon’s operations and financial results. Accordingly, the separation meets the criteria for discontinued operations.
The following table presents the results of Constellation that have been reclassified from continuing operations and included in 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 Operations, as these transactions will be ongoing after the separation. Certain BSC costs that were historically allocated to Generation are presented as part of continuing operations in
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 2 - Discontinued Operations
Exelon’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 transition costs related to the separation of $52 million and $43 million for the years ended December 31, 2022 and 2021, respectively. There were no separation related costs incurred in 2020. See discussion above for additional 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, 2022. Refer to the Distribution of Constellation line in Exelon's Consolidated Statement of Changes in Shareholders' Equity for further information.
The following table presents the assets and liabilities of discontinued operations in Exelon’s Consolidated Balance Sheets as of December 31, 2021.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 2 - Discontinued Operations
December 31, 2021
ASSETS
Current assets
Cash and cash equivalents $ 510
Restricted cash and cash equivalents 72
Accounts receivable
Customer accounts receivable 1,724
Customer allowance for credit losses (55)
Customer accounts receivable, net 1,669
Other accounts receivable 596
Other allowance for credit losses (4)
Other accounts receivable, net 592
Mark-to-market derivative assets 2,169
Inventories, net
Fossil fuel and emission allowances 284
Materials and supplies 1,004
Renewable energy credits 529
Assets held for sale 13
Other 993
Total current assets of discontinued operations 7,835
Property, plant, and equipment (net of accumulated depreciation and amortization of $15,888)
19,661
Deferred debits and other assets
Nuclear decommissioning trust funds 15,938
Investments 193
Mark-to-market derivative assets 949
Other 1,768
Total property, plant, and equipment, deferred debits, and other assets of discontinued operations 38,509
Total assets of discontinued operations $ 46,344
Combined Notes to Consolidated Financial Statements
(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.
Distribution Base Rate Case Proceedings
The following tables show the completed and pending distribution base rate case proceedings in 2022.
Completed Distribution Base Rate Case Proceedings
Registrant/Jurisdiction Filing Date Service Requested Revenue Requirement Increase Approved Revenue Requirement Increase Approved ROE Approval Date Rate Effective Date
ComEd - Illinois(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. 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).
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 3 - Regulatory Matters
ComEd’s 2022 approved revenue requirement reflects an increase of $37 million for the initial year revenue requirement for 2022 and an increase of $9 million related to the annual reconciliation for 2020. The revenue requirement for 2022 provides for a weighted average debt and equity return on distribution rate base of 5.72% inclusive of an allowed ROE of 7.36%, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points. The reconciliation revenue requirement for 2020 provides for a weighted average debt and equity return on distribution rate base of 5.69%, inclusive of an allowed ROE of 7.29%, reflecting the monthly yields on 30-year treasury bonds plus 580 basis points less a performance metrics penalty of 7 basis points.
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 discussion of CEJA below for details 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.
(c)Reflects a three-year cumulative multi-year plan for 2021 through 2023. BGE proposed to use certain tax benefits to fully offset the increases 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 2021.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 3 - Regulatory Matters
Pending Distribution Base Rate Case Proceedings
Registrant/Jurisdiction 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
__________
(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.
Transmission Formula Rates
The Utility Registrants' transmission rates are each established based on a FERC-approved formula. ComEd, BGE, Pepco, DPL, and ACE are required to file an annual update to the FERC-approved formula on or before May 15, and PECO is required to file on or before May 31, with the resulting rates effective on June 1 of the same year. The annual update for ComEd is based on prior year actual costs and current year projected capital additions (initial year revenue requirement). The update for ComEd also reconciles any differences between the revenue requirement in effect beginning June 1 of the prior year and actual costs incurred for that year (annual reconciliation). The annual update for PECO is based on prior year actual costs and current year projected capital additions, accumulated depreciation, and accumulated deferred income taxes. The annual update for BGE, Pepco, DPL, and ACE is based on prior year actual costs and current year projected capital additions, accumulated depreciation, depreciation and amortization expense, and accumulated deferred income taxes. The update for 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
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 ROE 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 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 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
_________
(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.
Maryland Regulatory Matters
Maryland Revenue 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 June 15, 2021, the MDPSC issued an order authorizing the disbursal of funds to utilities in accordance with Maryland COVID-19 relief legislation. Under this order, BGE, Pepco, and DPL received funds of $50 million,
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 Filings (Exelon, PHI, and ACE). On February 28, 2018, ACE filed with the NJBPU the company’s 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 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. Under the legislation, the NJBPU will issue ZECs to the qualifying nuclear power plants and the 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 procurement of the ZECs effective April 18, 2019.
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. 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. In the fourth quarter of 2017, ComEd, BGE, Pepco, DPL, and ACE fully impaired their associated transmission-related income tax regulatory assets for the portion of the income tax regulatory assets that would have been previously amortized.
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 rehearing request of FERC's November 16, 2017 order and (2) the February 23, 2018 (as amended on July 9, 2018) filing 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 U.S. Court of Appeals for the D.C. Circuit. On March 27, 2020, the U.S. Court of Appeals for the D.C. Circuit Court denied BGE’s November 2, 2018 appeal.
On October 1, 2018, ComEd, BGE, Pepco, DPL, and ACE submitted filings to recover ongoing non-TCJA amortization amounts and credit TCJA transmission-related income tax regulatory liabilities to customers for the prospective period starting on October 1, 2018. 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 other parties filed a settlement agreement with FERC, which FERC approved on September 24, 2020. The settlement agreement provides for the recovery of ongoing transmission-related income tax regulatory assets and establishes the amount and amortization period for excess deferred income taxes resulting from TCJA. The settlement resulted in a reduction to Operating revenues and an offsetting reduction to Income tax expense 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
FERC Audit (Exelon and ComEd). 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.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 3 - Regulatory Matters
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
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
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
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 3 - Regulatory Matters
December 31, 2021 Exelon ComEd PECO BGE PHI Pepco DPL ACE
Regulatory liabilities
Deferred income taxes $ 4,005 $ 2,105 $ - $ 819 $ 1,081 $ 525 $ 354 $ 202
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 OPEB 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 OPEB 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 OPEB 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 OPEB - merger 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 OPEB 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 BGE - 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 taxes Represents 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. Amounts 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 programs - deployment costs
Represents 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 - 2029
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 programs - legacy meters Represents early retirement costs of legacy meters. ComEd - 2028
BGE - 2026
Pepco - 2029
DPL - 2030
ACE - To be determined in next distribution rate case filed with NJBPU
ComEd, Pepco (District of Columbia), DPL (Delaware), ACE - Yes
BGE, Pepco (Maryland), DPL (Maryland) - No
Electric distribution formula rate annual reconciliations
Represents 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.
Yes
Electric distribution formula rate significant one-time events Represents 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. 2026 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 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. 2034 Yes
Fair value of long-term debt
Represents the difference between the carrying value and fair value of long-term debt of BGE and PHI of $107 million and $414 million, respectively, as of December 31, 2022, and $114 million and $443 million, respectively, as of December 31, 2021, as of the PHI and Constellation merger dates.
BGE - 2036
PHI - 2045 No
Fair value of PHI’s 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 obligations Represents future legally required removal costs associated with existing AROs. Over the life of the related assets Yes, once the removal activities have been performed
MGP remediation costs
Represents environmental remediation costs for MGP 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 energy 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
Line Item Description End Date of Remaining Recovery/Refund Period Return
Electric energy and natural gas costs Represents under (over)-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 Represents 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.
2024 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 - 2025
BGE - 2027
Pepco, DPL - 2037
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
Removal costs
For BGE, 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, 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, Pepco, DPL, and ACE - Asset is generally recovered over the life of the underlying assets.
ComEd, BGE, Pepco, and DPL - Liability is reduced as costs are incurred. Yes
DC PLUG charge
Represents costs associated with DC PLUG, which is a projected 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.
2024 Portion of asset funded by Pepco-Yes
Deferred storm costs For Pepco, DPL, ACE, and BGE, 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 - 2027
ACE - $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
Decommissioning the Regulatory Units
Represents estimated excess funds at the end of decommissioning the Regulatory Agreement Units. See below regarding Decommissioning the Regulatory Agreement Units for additional information.
Not currently being 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 the Registrants' 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 the Utility Registrants' customers.
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 and ACE's authorized amounts capitalized for ratemaking purposes primarily relate to earnings on shareholders' investment on their respective 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, and for Pepco District of Columbia revenue decoupling program. The earnings on energy efficiency are on Pepco District of Columbia and DPL Delaware programs only.
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. The 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.
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 Registrants 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
Regulated Electric and Gas Tariff Sales 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. (a)
Within the month following delivery of the electricity or natural gas to the customer.
Regulated Transmission Services 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. (b)
Paid weekly by PJM.
__________
(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 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.
(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.
The Utility Registrants do not incur any material costs to obtain or fulfill contracts with customers.
Contract Liabilities
The Registrants record contract liabilities when consideration is received or due prior to the satisfaction of the performance obligations. The Registrants record contract liabilities in Other current liabilities and Other noncurrent liabilities in the Registrants' 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 liabilities reflected in Exelon's, PHI's, Pepco's, DPL's, and ACE'S Consolidated Balance Sheets. As of December 31, 2022, 2021, and 2020, ComEd's, PECO's, and BGE's contract liabilities were 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
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, 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 the Utility Registrants' gas and electric tariff sales contracts and transmission revenue contracts as they generally have an original expected duration of one year or less and, therefore, do not contain any future, unsatisfied performance obligations to be included in this disclosure.
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
The Registrants disaggregate revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. See Note 5 - Segment Information for the presentation of the Registrant's revenue disaggregation.
5. Segment Information (All Registrants)
Operating segments for each of the Registrants are determined based on information used by the CODMs in deciding how to evaluate performance and allocate resources at each of the Registrants.
Exelon has six reportable segments, which include ComEd, PECO, BGE, and PHI's three 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 separation of Constellation Energy Corporation, 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. Furthermore, the reportable segment information related to the discontinued operations has been excluded from the tables presented below. See Note 2 - Discontinued Operations for additional information.
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, 2022, 2021, and 2020 is as follows:
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 5 - Segment Information
ComEd PECO BGE PHI Other(a)
Intersegment
Eliminations Exelon
Operating revenues(b):
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
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
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
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.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 5 - Segment Information
PHI:
Pepco DPL ACE Other(a)
Intersegment
Eliminations PHI
Operating revenues(b):
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
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
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)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
(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)Includes intersegment revenues with ComEd, BGE, and PECO, which are eliminated at Exelon.
The following tables disaggregate the Registrants' revenues 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 the Utility Registrants, the disaggregation of revenues reflects the two primary utility services of electric sales and natural gas sales (where applicable), with further disaggregation of these tariff sales provided by major customer groups. Exelon's disaggregated revenues are consistent with the Utility Registrants, but exclude any intercompany revenues.
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
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 5 - Segment Information
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
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 5 - Segment Information
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
__________
(a)Includes revenues from transmission revenue from PJM, wholesale electric revenue and 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.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 6 - Accounts Receivable
6. Accounts Receivable (All Registrants)
Allowance for Credit Losses on Accounts Receivable
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
_________
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 6 - Accounts 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.
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, 2022 and 2021:
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)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 ComEd PECO BGE PHI Pepco DPL ACE
Electric - transmission and distribution 5-80 5-80 5-70 5-80 5-75 5-75 5-75 5-75
Gas - transportation and distribution 5-80 N/A 5-70 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 5-75 N/A
Other property, plant, and equipment 4-61 31-50 50 20-50 10-43 10-33 10-43 13-15
The following table presents the annual depreciation rates for each asset category.
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
AFUDC
The following table summarizes credits to AFUDC by year:
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 ACE’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, PECO, PHI, DPL, and ACE)
PECO's, DPL's, and ACE's material undivided ownership interests in jointly owned electric plants and transmission facilities as of December 31, 2022 and 2021 were as follows:
Transmission
NJ/DE(a)
Operator PSEG/DPL
Ownership interest various
Exelon’s share as of December 31, 2022:
Plant in service $ 103
Accumulated depreciation 56
Exelon’s share as of December 31, 2021:
Plant in service $ 103
Accumulated depreciation 55
__________
(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. PECO's, DPL's, and ACE's share of direct expenses of the jointly owned plants are included in Operating and maintenance expenses in Exelon's, PECO's, PHI's, DPL's, and ACE's Consolidated Statements of Operations and Comprehensive Income.
9. Asset Retirement Obligations (All Registrants)
The 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 AROs reflected in the Registrants’ Consolidated Balance Sheets from December 31, 2020 to December 31, 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.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 10 - Leases
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 leases at each registrant and other terms and conditions of the lease agreements as of December 31, 2022. Exelon, ComEd, PECO, and BGE did not have material finance leases in 2022, 2021, or in 2020.
Exelon ComEd PECO BGE PHI Pepco DPL ACE
Real estate ● ● ● ● ● ● ● ●
Vehicles and equipment ● ● ● ● ● ● ● ●
(in years) Exelon ComEd PECO BGE PHI Pepco DPL ACE
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 N/A N/A N/A 3-30 5 3-30 5
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 were as follows:
Exelon ComEd PECO BGE PHI Pepco DPL ACE
For the year ended December 31, 2022
Operating lease costs $ 66 $ 2 $ - $ 15 $ 42 $ 10 $ 12 $ 6
Variable lease costs 8 1 - - 2 1 1 1
Total lease costs(a)
$ 74 $ 3 $ - $ 15 $ 44 $ 11 $ 13 $ 7
For the year ended December 31, 2021
Operating lease costs $ 84 $ 3 $ - $ 30 $ 43 $ 10 $ 12 $ 6
Variable lease costs 7 1 - 1 1 - - -
Total lease costs(a)
$ 91 $ 4 $ - $ 31 $ 44 $ 10 $ 12 $ 6
For the year ended December 31, 2020
Operating lease costs $ 98 $ 3 $ 1 $ 33 $ 46 $ 11 $ 13 $ 6
Variable lease costs 7 1 - 1 2 1 1 -
Total lease costs(a)
$ 105 $ 4 $ 1 $ 34 $ 48 $ 12 $ 14 $ 6
__________
(a)Excludes sublease income recorded at Exelon, PHI, and DPL of $4 million, $4 million, and $4 million for the years ended December 31, 2022, 2021, and 2020, 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 tables provide additional information regarding the presentation of operating and finance lease ROU assets and lease liabilities within the Registrants’ Consolidated Balance 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
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 as of December 31, 2022 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
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
Cash paid for amounts included in the measurement of operating and finance lease liabilities 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
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 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) -
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 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 ComEd PECO BGE PHI Pepco DPL
Real estate ● ● ● ● ● ● ●
(in years) Exelon ComEd PECO BGE PHI Pepco DPL
Remaining lease terms 1-80 1-14 1-80 20 1-10 1-3 9-10
Options to extend the term 5-79 5-79 5-50 N/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 11 - Asset Impairments
11. Asset Impairments (Exelon and BGE)
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, in 2022, a pre-tax impairment charge of $48 million was recorded in Operating and maintenance expense in Exelon’s and BGE’s Consolidated Statements of Operations and Comprehensive Income. The fair value used in the analysis was based on an estimate of an expected sales price. However, the office building did not meet all of the criteria for classification as held for sale as of December 31, 2022, and therefore continues to be reported within Property, plant and equipment in Exelon’s and BGE’s Balance Sheets as of December 31, 2022.
12. Intangible Assets
Goodwill (Exelon, ComEd, PHI, Pepco, DPL, and ACE)
The following table presents the gross amount, accumulated impairment loss, and carrying amount of goodwill at Exelon, ComEd, and PHI as of December 31, 2022 and 2021. There were no additions or impairments during the years ended December 31, 2022 and 2021.
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.
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 assessed 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 assessment 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 performed. If an entity bypasses the qualitative assessment, a quantitative, fair value-based assessment is performed, 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 entity recognizes an impairment charge, which is limited to the amount of goodwill allocated to the reporting unit.
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
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.
2022 and 2021 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, 2022 and 2021. The last quantitative assessments performed were as of November 1, 2016 for ComEd and November 1, 2018 for PHI.
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.
Other Intangible Assets and Liabilities (Exelon and PHI)
Exelon’s other intangible assets, included in Other current assets 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, 2022 and 2021. The intangible assets and liabilities shown below are amortized on a straight-line basis, except for unamortized energy contracts which are amortized in relation to the expected realization of the underlying cash flows:
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, 2022, 2021, and 2020:
For the Years Ended December 31, Exelon(a)
PHI(a)
2022(b)
$ (182) $ (190)
2021 (83) (92)
2020 (98) (115)
__________
(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, 2022:
For the Years Ending December 31, Exelon PHI
2023 $ (2) $ (10)
2024 - (8)
2025 (2) (5)
2026 (5) (5)
2027 (4) (4)
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, 2021
Exelon ComEd PECO BGE PHI Pepco DPL ACE
Included in operations:
Federal
Current $ (152) $ (30) $ 1 $ (18) $ 18 $ 22 $ 2 $ 1
Deferred 89 113 20 34 (52) (17) (14) (26)
Investment tax credit amortization (2) (1) - - (1) - - -
State
Current (46) (41) - - - 1 1 -
Deferred 149 131 (9) (51) 77 9 53 12
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)
Rate Reconciliation
The effective income tax rate from continuing operations varies from the U.S. federal statutory rate principally due to the following:
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.
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, 2022 and 2021 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)
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 13 - Income Taxes
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, 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, as well as, any corresponding valuation allowances as of December 31, 2022. ComEd does not have net operating losses or credit carryforwards for the year ended December 31, 2022.
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)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 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
The following table presents changes in unrecognized tax benefits, for 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 in noncurrent Other assets in the Consolidated Balance Sheet for Constellation’s share of unrecognized tax benefits for periods prior to the separation.
Recognition of unrecognized tax benefits
The following table presents Exelon's unrecognized tax benefits that, if recognized, would decrease the effective tax rate. The Utility Registrants' amounts are not material.
Exelon
December 31, 2022 $ 90
December 31, 2021 77
December 31, 2020 73
Reasonably possible the total amount of unrecognized tax benefits could significantly increase or decrease within 12 months after the reporting date
As of December 31, 2022, ACE has approximately $14 million of unrecognized state tax benefits that could significantly decrease within the 12 months after the reporting date based on the outcome of pending court cases involving other taxpayers. The unrecognized tax benefit, if recognized, may be included in future base rates and that portion would have no impact to the effective tax rate.
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. The Utility Registrants' amounts are not material.
Net interest and penalties receivable as of Exelon
December 31, 2022 (a) (b)
$ 45
December 31, 2021 (c)
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, 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)
2010-2021 All Registrants
Delaware separate corporate income tax returns Same as federal DPL
District of Columbia combined corporate income tax returns 2019-2021 Exelon, PHI, Pepco
Illinois unitary corporate income tax returns 2012-2021 Exelon, ComEd
Maryland separate company corporate net income tax returns Same as federal BGE, Pepco, DPL
New Jersey separate corporate income tax returns 2017-2018 Exelon
New Jersey combined corporate income tax returns 2019-2021 Exelon
New Jersey separate corporate income tax returns 2018-2021 ACE
New York combined corporate income tax returns 2015-2021 Exelon
Pennsylvania separate corporate income tax returns 2011-2016 Exelon
Pennsylvania separate corporate income tax returns 2019-2021 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
Separation (Exelon)
In the first quarter of 2022, in connection with the separation, Exelon recorded an income tax expense related to continuing operations of $148 million primarily due to the long-term marginal state income tax rate change of $67 million discussed further below, the recognition of valuation allowances of approximately $40 million against the net deferred tax assets positions for certain standalone state filing jurisdictions, the write-off of federal and 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 with Exelon to the IRS and certain state jurisdictions relating to the taxable periods prior to the separation. The TMA specifies that Constellation is liable for their share of taxes required to be paid by Exelon with respect to taxable periods prior to the separation to the extent Constellation would have been responsible for such taxes under the existing Exelon tax sharing agreement. As a result, as of March 31, 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
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 13 - Income Taxes
prior to the separation. As of December 31, 2022, Exelon recorded a payable of $18 million in Current other liabilities that is due to Constellation.
Tax Refunds. The TMA specifies that Constellation is entitled to their share of any future tax refunds claimed by Exelon with respect to taxable periods prior to the separation to the extent that Constellation would have received such tax refunds under the existing Exelon tax sharing agreement.
Tax Attributes. At the date of separation certain tax attributes, primarily pre-closing tax credit carryforwards, that were generated by Constellation were required by law to be allocated to Exelon. The TMA also provides that Exelon will reimburse Constellation when those allocated tax attribute carryforwards are utilized. As of March 31, 2022, Exelon recorded a payable of $11 million and $484 million in Current other liabilities and Noncurrent other liabilities, respectively, in the Consolidated Balance Sheet for tax credit carryforwards that are expected to be utilized and reimbursed to Constellation. As of December 31, 2022, the current and noncurrent payable amounts are $169 million and $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. 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 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). 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 income tax rates for the years ended December 31, 2021 and 2020.
Allocation of Tax Benefits (All Registrants)
The Utility Registrants are 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 federal and state benefits attributable to Exelon are reallocated to the other Registrants. That allocation is treated as a contribution from Exelon to the party receiving the benefit.
The following table presents the allocation of tax benefits from Exelon under the Tax Sharing Agreement, for the year ended December 31, 2022, 2021, and 2020.
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
__________
(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.
(b)BGE, DPL, and ACE did not record an allocation of federal tax benefits from Exelon under the Tax Sharing Agreement as a result of a tax net operating loss.
(c)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.
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 BSC non-represented, non-craft, employees, January 1, 2021 for most newly-hired utility management employees, and for certain newly-hired union employees pursuant to their collective bargaining agreements, these newly-hired employees are not eligible for pension benefits, and will instead be eligible to receive an enhanced non-discretionary employer contribution in an Exelon defined contribution savings plan. Effective January 1, 2018, most newly-hired non-represented, non-craft, employees are not eligible for OPEB benefits and employees represented by Local 614 are not eligible for retiree health care benefits. Effective January 1, 2021, most non-represented, non-craft, employees who are under the age of 40 are not eligible for retiree health care benefits. Effective January 1, 2022, management employees retiring on or after that date are no longer eligible for retiree life insurance benefits.
Effective 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 and 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 Employee Pension Plan for Clinton, TMI, and Oyster Creek, Pension Plan of Constellation Energy Nuclear Group, LLC, and Nine Mile Point Pension Plan were merged into the Pension Plan of Constellation Energy Group, Inc, which was subsequently renamed, Exelon Pension Plan (EPP). Exelon employees who participated in these plans prior to the 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 obligations.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 14 - Retirement Benefits
The tables below show the pension and OPEB plans in which employees of each operating company participated as of December 31, 2022:
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
Non-Qualified Pension Plans:
Exelon Corporation Supplemental Pension Benefit Plan and 2000 Excess Benefit Plan(a)
X X X
Exelon Corporation Supplemental Management Retirement Plan(a)
X X X X X
Constellation Energy Group, Inc. Senior Executive Supplemental Plan(b)
X X
Constellation Energy Group, Inc. Supplemental Pension Plan(b)
X X
Constellation Energy Group, Inc. Benefits Restoration Plan(b)
X X X
Baltimore Gas & Electric Company Executive Benefit Plan(b)
X
Baltimore Gas & Electric Company Manager Benefit Plan(b)
X X
Pepco Holdings LLC 2011 Supplemental Executive Retirement Plan(d)
X X X X
Conectiv Supplemental Executive Retirement Plan(d)
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:
PECO Energy Company Retiree Medical Plan(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
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 2022, Exelon received an updated valuation of its pension and OPEB to reflect actual census data as of February 1, 2022. This valuation resulted in a decrease to the pension obligations of $24 million and an increase to the OPEB obligations of $5 million. Additionally, accumulated other comprehensive loss increased by $5 million (after-tax) and regulatory assets and liabilities decreased by $30 million and $3 million, respectively.
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
2022 2021 2022 2021
Change in plan assets:
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 (2,359) 822 (225) 130
Employer contributions 570 343 42 63
Plan participants’ contributions - - 26 32
Gross benefits paid (855) (860) (157) (190)
Settlements - (23) - (5)
Fair value of net plan assets as of the end of year $ 9,521 $ 12,165 $ 1,351 $ 1,665
__________
(a)The pension and OPEB gains in 2022 and 2021 primarily reflect an increase in the discount rate.
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 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.
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 2022 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 3.24%. The majority of the 2022 OPEB cost is calculated using an expected long-term rate of return on plan assets of 6.44% for funded plans and a discount rate of 3.20%.
A portion of the net periodic benefit cost for all plans is capitalized in the Consolidated Balance Sheets. The following table presents the components of Exelon’s net periodic benefit costs, prior to capitalization, for the years ended December 31, 2022, 2021, and 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
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' allocated pension and OPEB costs. For Exelon, the service cost component is included in Operating and maintenance expense and Property, plant, and equipment, net while the non-service cost components are included in Other, net and Regulatory assets. For the Utility Registrants, the service cost and non-service cost components are included in Operating and maintenance expense and Property, plant, and equipment, net in their consolidated financial statements.
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
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 Consolidated Balance Sheets, with offsetting entries to AOCI and regulatory assets (liabilities). A portion of current year actuarial (gains) losses and prior service costs (credits) is capitalized in 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, 2022, 2021, and 2020 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)
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 as of December 31, 2022 and 2021, respectively, for all plans combined:
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) 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) losses over participants’ average remaining service period to expected retirement. The resulting average remaining service periods for pension and OPEB were as follows:
2022 2021 2020
Pension plans 12.5 12.4 12.3
OPEB plans:
Benefit Eligibility Age 7.9 7.6 9.0
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 OPEB 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 determining 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 years ended December 31, 2022 and 2021, 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.
For Exelon, the following assumptions were used to determine the benefit obligations for the plans as of December 31, 2022 and 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
2022 2021 2022 2021
Discount rate(a)
5.53 % 2.92 % 5.51 % 2.88 %
Investment crediting rate(b)
5.07 %
3.75 % N/A N/A
Rate of compensation increase 3.75 % 3.75 % 3.75 % 3.75 %
Mortality table Pri-2012 table with MP- 2021 improvement scale (adjusted) Pri-2012 table with MP- 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 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 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, 2022, 2021 and 2020:
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 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.
(b)The investment crediting rate above represents a weighted average rate.
(c)Not applicable to 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
2022 2021 2020 2022 2021 2020
Exelon $ 570 $ 343 $ 306 $ 42 $ 63 $ 40
ComEd 176 174 143 8 22 5
PECO 15 17 18 3 1 -
BGE 48 57 56 20 24 22
PHI 69 39 30 9 9 9
Pepco 3 2 2 8 9 9
DPL 1 1 - - - -
ACE 7 3 2 - - -
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. Based on this funding strategy and current market conditions, which are subject to change, Exelon’s estimated annual qualified pension contributions will be approximately $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 - - -
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 14 - Retirement Benefits
Estimated Future Benefit Payments
Estimated future benefit payments to participants in all of the pension plans and postretirement benefit plans as of December 31, 2022 were:
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 OPEB 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, 2022 were (18.69)% and (11.36)%, respectively, compared to an expected long-term return assumption of 7.00% and 6.44%, respectively. Exelon used an EROA of 7.00% and 6.50% to estimate its 2023 pension and OPEB costs, respectively.
Exelon’s pension and OPEB plan target asset allocations as of December 31, 2022 and 2021 were as follows:
December 31, 2022 December 31, 2021
Asset Category Pension Benefits OPEB Pension Benefits OPEB
Equity securities 28 % 44 % 35 % 44 %
Fixed income securities 44 % 41 % 41 % 41 %
Alternative investments(a)
28 % 15 % 24 % 15 %
Total 100 % 100 % 100 % 100 %
__________
(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, 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, 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 as of December 31, 2022 and 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
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.
(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.
(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.
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, 2022 and 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, 2021 $ 348 $ 1 $ 136 $ 485
Actual return on plan assets:
Relating to assets still held as of the
reporting date
(12) - 18 6
Purchases, sales and settlements:
Purchases 10 - 5 15
Settlements(a)
(13) - (29) (42)
Transfers into Level 3 4 1 - 5
Balance as of December 31, 2021 $ 337 $ 2 $ 130 $ 469
__________
(a)Represents cash settlements only.
(b)In 2022, transfers relate to changes in investment structure for certain investments due to the separation.
Valuation Techniques Used to Determine Fair Value
The techniques used to fair value the pension and OPEB assets invested in cash equivalents are the same as the valuation techniques used to determine the fair value of financial assets. See Cash Equivalents 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 that 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
The Registrants participate in a 401(k) defined contribution savings plan that is sponsored by Exelon. The plan is qualified under applicable sections of the IRC and allows 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, 2022, 2021, and 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
15. Derivative Financial Instruments (All Registrants)
The Registrants use derivative instruments to manage commodity price risk and interest rate 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 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. At ComEd, derivative economic hedges related to commodities are recorded at fair value and offset by a corresponding regulatory asset or liability. At Exelon, derivative economic hedges related to interest rates are recorded at 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 derivatives settle and revenue or expense is recognized in earnings as the underlying physical commodity is sold or consumed. At Exelon, derivative hedges that qualify and are designated as cash flow hedges are recorded at fair value and offsets are recorded to AOCI.
ComEd’s use of cash collateral is generally unrestricted unless ComEd is 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 meets certain qualifications.
Commodity Price Risk
The Registrants employ established policies and procedures to manage their risks associated with market fluctuations in commodity prices by entering into physical and financial derivative contracts, which are either determined to be non-derivative or classified as economic 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 Instrument
ComEd Electricity NPNS Fixed price contracts based on all requirements in the IPA procurement plans.
Electricity Changes in fair value of economic hedge recorded to an offsetting regulatory asset or liability(a)
20-year floating-to-fixed energy swap contracts beginning June 2012 based on the renewable energy resource procurement requirements in the Illinois Settlement Legislation of approximately 1.3 million MWhs per year.
PECO Electricity NPNS Fixed price contracts for default supply requirements through full requirements contracts.
Gas NPNS Fixed price contracts to cover about 10% of planned natural gas purchases in support of projected firm sales.
BGE Electricity NPNS Fixed price contracts for all SOS requirements through full requirements contracts.
Gas NPNS Fixed price contracts for between 10-20% of forecasted system supply requirements for flowing (i.e., non-storage) gas for the November through March period.
Pepco Electricity NPNS Fixed price contracts for all SOS requirements through full requirements contracts.
DPL Electricity NPNS Fixed price contracts for all SOS requirements through full requirements contracts.
Gas NPNS Fixed and index priced contracts through full requirements contracts.
Gas Changes in fair value of economic hedge recorded to an offsetting regulatory asset or liability(b)
Exchange traded future contracts for up to 50% of estimated monthly purchase requirements each month, including purchases for storage injections.
ACE Electricity NPNS Fixed price contracts for all BGS requirements through full requirements contracts.
_________
(a)See Note 3-Regulatory Matters for additional information.
(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
swaps 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 interest rate hedge balances as of December 31, 2022. 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 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.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 15 - Derivative Financial Instruments
For the year ended December 31, 2022, Exelon Corporate recognized the following net pre-tax mark-to-market losses which are also recognized in Net fair value changes related to derivatives in Exelon's Consolidated Statements of Cash Flows. Exelon had no swaps for the years ended December 31, 2021 and 2020.
Loss
Income Statement Location 2022
Electric operating revenues $ 2
Interest expense 3
Total $ 5
Credit Risk
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. 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, 2022, the amount of cash collateral held with external 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 December 31, 2022. As of December 31, 2021, the amounts for ComEd and DPL were $41 million and $43 million, respectively. The amounts for Exelon, PECO, BGE, PHI, Pepco, and ACE were not material as of December 31, 2021.
The Utility Registrants’ electric supply procurement contracts do not contain provisions that would require them to post collateral. PECO’s, BGE’s, and DPL’s natural gas procurement contracts contain provisions that could require PECO, BGE, and DPL to post collateral in the form of cash or credit support, which vary by contract and counterparty, with thresholds contingent upon PECO’s, BGE's, and DPL’s credit rating. As of December 31, 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, 2022, they could have been required to post collateral to their counterparties of $71 million, $119 million, and $15 million, respectively.
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. PECO meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the Exelon intercompany money pool. Pepco, DPL, and ACE meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the PHI intercompany money pool. PHI Corporate meets its short-term liquidity requirements primarily through the issuance of short-term notes and 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 as of December 31, 2022 and 2021:
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 2022(a)
2021(a)
2022 2021 2022 2021
Exelon(b)
$ 4,000 $ 3,700 $ 1,938 $ 599 4.77 % 0.35 %
ComEd 1,000 1,000 427 - 4.71 % - %
PECO 600 600 239 - 4.71 % - %
BGE 600 600 409 130 4.81 % 0.37 %
PHI(c)
900 900 414 469 4.78 % 0.35 %
Pepco 300 (d)
300 299 175 4.79 % 0.33 %
DPL 300 (d)
300 115 149 4.76 % 0.36 %
ACE 300 (d)
300 - 145 - % 0.35 %
__________
(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, $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.
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
As of December 31, 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
Borrower(a)
Facility Type Aggregate Bank
Commitment(b)
Facility Draws Outstanding
Letters of Credit Actual To Support
Additional
Commercial
Paper(c)
Exelon(c)
Syndicated Revolver $ 4,000 $ - $ 8 $ 3,992 $ 2,054
ComEd Syndicated Revolver 1,000 - 5 995 568
PECO Syndicated Revolver 600 - - 600 361
BGE Syndicated Revolver 600 - - 600 191
PHI(d)
Syndicated Revolver 900 - - 900 486
Pepco Syndicated Revolver 300 - - 300 1
DPL Syndicated Revolver 300 - - 300 185
ACE Syndicated Revolver 300 - - 300 300
__________
(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
Borrower Aggregate Bank Commitment Interest Rate
Exelon Corporate $ 900 SOFR plus 1.275 %
ComEd 1,000 SOFR plus 1.000 %
PECO 600 SOFR plus 0.900 %
BGE 600 SOFR plus 0.900 %
Pepco 300 SOFR plus 1.075 %
DPL 300 SOFR plus 1.000 %
ACE 300 SOFR plus 1.075 %
Borrowings under 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 SOFR-based rate, plus an adder based upon the particular Registrant’s credit rating. The adders for the prime based borrowings and SOFR-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
__________
(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 SOFR-based rate borrowings would be 65 basis points and 165 basis 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, 2022 and December 31, 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 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
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, 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
PHI
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.
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 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 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
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 16 - Debt and Credit Agreements
receivable 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 of $258 million to settle the intercompany loan.
Debt Covenants
As of December 31, 2022, the Registrants are in compliance with debt covenants.
17. Fair Value of Financial Assets and Liabilities (All Registrants)
Exelon measures and classifies fair value measurements in accordance with the hierarchy as defined by GAAP. The hierarchy prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:
•Level 1 - quoted prices (unadjusted) in active markets for identical assets or liabilities that the Registrants have the ability to liquidate as of the reporting date.
•Level 2 - inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data.
•Level 3 - unobservable inputs, such as internally developed pricing models or third-party valuations for the asset or liability due to little or no market activity for the asset or liability.
Fair Value of Financial Liabilities Recorded at Amortized Cost
The following tables present the carrying amounts and fair values of the Registrants’ short-term liabilities, long-term debt, and trust preferred securities (long-term debt to financing trusts or junior subordinated debentures) as of December 31, 2022 and 2021. The Registrants have no financial liabilities classified as Level 1 or measured using the NAV practical expedient.
The carrying amounts of the Registrants’ short-term liabilities as presented in their Consolidated Balance Sheets are representative of their fair value (Level 2) because of the short-term nature of these instruments.
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, 2022 December 31, 2021
Carrying Amount Fair Value Carrying Amount Fair Value
Level 2 Level 3 Total Level 2 Level 3 Total
Long-Term Debt, including amounts due within one year(a)
Exelon $ 37,074 $ 29,902 $ 2,327 $ 32,229 $ 32,902 $ 34,897 $ 2,217 $ 37,114
ComEd 10,518 9,006 - 9,006 9,773 11,305 - 11,305
PECO 4,612 3,864 50 3,914 4,197 4,740 50 4,790
BGE 4,207 3,613 - 3,613 3,961 4,406 - 4,406
PHI 8,120 4,507 2,277 6,784 7,547 5,970 2,167 8,137
Pepco 3,751 2,229 1,205 3,434 3,445 3,201 975 4,176
DPL 1,938 1,164 458 1,622 1,810 1,426 552 1,978
ACE 1,757 909 614 1,523 1,582 1,091 641 1,732
Long-Term Debt to Financing Trusts
Exelon $ 390 $ - $ 384 $ 384 $ 390 $ - $ 470 $ 470
ComEd 205 - 204 204 205 - 248 248
PECO 184 - 180 180 184 - 222 222
__________
(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 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:
Type Level Registrants Valuation
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, 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.
Non-Government Backed Fixed Rate Nonrecourse Debt 3 Exelon, 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 project.
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.
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, 2022 and 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.
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
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
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)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
Reconciliation of Level 3 Assets and Liabilities
The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the years ended December 31, 2022 and 2021:
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
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)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, 2022. Includes $62 million of increases in fair value and an increase for realized losses due to settlements of $20 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the year ended December 31, 2021.
(c)The balance of the current and noncurrent asset was effectively zero as of December 31, 2022. The balance consists of a current and 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.
Rabbi Trust Investments (Exelon, 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 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 Instruments for 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 and ComEd). 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. 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 forward power 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 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, 2022:
Description Exelon PHI Pepco DPL ACE
Total commitments $ 513 $ 320 $ 120 $ 89 $ 111
Remaining commitments(a)
52 45 39 4 2
__________
(a)Remaining commitments extend through 2026 and include rate credits, energy efficiency programs, and delivery system modernization.
In addition, 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 completed 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 DEPSC in 2019. The third and final 40 MW wind REC tranche was conducted in 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' commercial commitments as of December 31, 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
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 18 - Commitments and Contingencies
__________
(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 $68 million guaranteed by Exelon and PHI, of which $22 million, $28 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.
Environmental Remediation Matters
General (All Registrants). The Registrants’ operations have in the past, and may in the future, require substantial expenditures to comply with environmental laws. Additionally, under federal and state environmental laws, the Registrants are generally liable for the costs of remediating environmental contamination of property now or formerly owned by them and of property contaminated by hazardous substances generated by them. The Registrants own or lease a number of real estate parcels, including parcels on which their operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws. In addition, the Registrants are currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and may be subject to additional proceedings in the future. Unless otherwise disclosed, the Registrants cannot reasonably estimate whether they will incur significant liabilities for additional investigation and remediation costs at these or additional sites identified by the Registrants, environmental agencies or others, or whether such costs will be recoverable from third parties, including customers. Additional costs could have a material, unfavorable impact on the Registrants' financial statements.
MGP Sites (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 some sites, there are additional PRPs that may share responsibility for the ultimate remediation of each location.
•ComEd has 20 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 2031.
•PECO has 6 sites that are currently under some degree of active study and/or remediation. PECO expects the majority of the remediation at these sites to continue through at least 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 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 a 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.
In 2022, ComEd and PECO completed an annual study of their future estimated MGP remediation requirements. The study resulted in a $60 million increase to the environmental liability and 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 environmental liability for PECO.
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:
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, 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 an electric generating facility owned by Pepco subsidiary, Pepco Energy Services (PES), which became a part of Generation, following the 2016 merger between PHI and Exelon. This generating facility was deactivated in June 2012. The remaining portion of the site consists of a Pepco transmission and distribution service center that remains in operation. In December 2011, the U.S. District Court for the District of Columbia approved a Consent Decree entered into by Pepco and Pepco Energy Services (hereinafter "Pepco Entities") with the DOEE, which requires the Pepco Entities to conduct a Remedial 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.
Pursuant 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 Entities. In September 2019, the Pepco Entities issued a draft “final” RI report which DOEE approved on February 3, 2020. The Pepco Entities are completing a FS to evaluate possible remedial alternatives for submission to DOEE. In 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 project. After completion and approval of the landside FS, now scheduled for September 2023, DOEE will prepare a Proposed Plan for public comment and then issue a Record of Decision (ROD) identifying any further response actions determined to be necessary to address any landside issues. The DOEE will issue a separate ROD for the 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, and Pepco 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 Entities, DOEE and NPS have been conducting a separate RI/FS focused on the entire tidal reach of the Anacostia River extending from just north of the Maryland-District of Columbia boundary line to the confluence of the Anacostia and Potomac Rivers. The river-wide RI incorporated the results of the river sampling performed by the Pepco Entities 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.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 18 - Commitments and Contingencies
On September 30, 2020, DOEE released its Interim ROD. The Interim ROD reflects an adaptive management approach which will require several identified “hot spots” in the river to be addressed first while continuing to conduct studies and to monitor the river to evaluate improvements and determine potential future remediation plans. The adaptive management process chosen by DOEE is less intrusive, provides more long-term environmental certainty, is less costly, and allows for site specific remediation plans already underway, including the plan for the Benning Road site to proceed to conclusion.
On July 15, 2022, Pepco received a letter from the District of Columbia's Office of the Attorney General (D.C. OAG) on behalf of DOEE conveying a settlement offer to resolve all PRPs' liability to the District of Columbia (District) for their past costs and their 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 incurred and have accrued a liability for management's best estimate of its share of the costs. Pepco concluded that incremental exposure remains reasonably possible, but management cannot reasonably estimate a range of loss beyond the amounts recorded, which are included in the table above.
In addition to the activities associated with the remedial process outlined above, CERCLA separately requires federal and state (here including Washington, D.C.) Natural Resource Trustees (federal or state agencies designated by the President or the relevant state, respectively, or Indian tribes) to conduct an assessment of any damages to natural resources within their jurisdiction as a result of the contamination that is being remediated. The Trustees can seek compensation from responsible parties for such damages, including restoration costs. During the second quarter of 2018, Pepco became aware that the Trustees are in the beginning stages of a Natural Resources Damages (NRD) assessment, a process that often takes many years beyond the remedial decision to complete. Pepco has entered into negotiations with the Trustees to evaluate possible incorporation of NRD assessment and restoration as part of its remedial activities associated with the Benning site to accelerate the NRD benefits for that portion of the Anacostia River Sediment Project (ARSP) assessment. Pepco has concluded that a loss associated with the eventual NRD assessment is reasonably possible. Due to the very early stage of the assessment process, Pepco cannot reasonably estimate the final range of loss 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.
Buzzard Point Site (Exelon, PHI, and Pepco). On December 8, 2022, Pepco received a letter from the D.C. OAG, alleging wholly past violations of the District's stormwater discharge and waste disposal requirements related to operations at the Buzzard Point facility, a 9-acre parcel of waterfront property in Washington, D.C. occupied by an active substation and former 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
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, 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.
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 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 48% as calculated pursuant to the MDPSC's and DCPSC's ratemaking precedents, of 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 48% as calculated pursuant to the DCPSC'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 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.
DPA and Related Matters (Exelon and ComEd). Exelon and ComEd received a grand jury subpoena in the second quarter of 2019 from the U.S. Attorney’s Office for the Northern District of Illinois (USAO) requiring production of information concerning their lobbying activities in the State of Illinois. On October 4, 2019, Exelon and ComEd received a second grand jury subpoena from the USAO requiring production of records of any communications with certain individuals and entities. On October 22, 2019, the SEC notified Exelon and ComEd that it had also opened an investigation into their lobbying activities. On July 17, 2020, ComEd entered into a DPA with the USAO to resolve the USAO investigation. Under the DPA, the USAO filed a single charge alleging that ComEd improperly gave and offered to give jobs, vendor subcontracts, and payments associated with those jobs and subcontracts for the benefit of the 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 with the SEC. Exelon and ComEd cannot predict the outcome of the SEC investigation. No loss contingency has been reflected in Exelon's and ComEd's consolidated financial statements with respect to the SEC investigation, as this contingency is neither probable nor reasonably estimable at this time.
Combined Notes to 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, various lawsuits were filed, and various demand letters were received related to the subject of the subpoenas, the conduct described in the DPA and the SEC's investigation, including:
•Four putative class action lawsuits against ComEd and Exelon were filed in federal court on behalf of ComEd customers in the third quarter of 2020 alleging, among other things, civil violations of federal racketeering laws. In addition, the Citizens Utility Board (CUB) filed a motion to intervene in these cases on October 22, 2020 which was granted on December 23, 2020. On December 2, 2020, the court 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 passed 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 and 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 and ComEd officers and directors related to the conduct described in the DPA. In the first quarter of 2021, the Exelon Board of Directors appointed a Special Litigation Committee (SLC) consisting of disinterested and independent parties to investigate and address these shareholders' allegations and make recommendations to the Exelon Board of Directors based on the outcome of the SLC's investigation. In July 2021, one of the demand letter shareholders filed a derivative action against current and former Exelon and ComEd officers and directors, and against Exelon, as nominal defendant, asserting the same claims made in its demand letter. On October 12, 2021, the parties to the derivative action filed an agreed motion to stay that litigation for 120 days in order to allow the SLC to continue its investigation, which the court granted. The 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 books and records were received in August 2021 and January 2022. Exelon responded to both requests and both shareholders have since sent formal shareholder demands to the Exelon Board, as discussed above.
No loss contingencies have been reflected in Exelon’s and ComEd’s consolidated financial statements with respect to these matters, as such contingencies are neither probable nor reasonably estimable at this time.
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
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,
2022 2021
Warrants outstanding
60,052 60,061
Common Stock reserved for conversion 20,017 20,020
Share Repurchases
There currently is no 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 Exelon, ComEd, PECO, BGE, Pepco, and ACE's shares of preferred securities authorized, none of which were outstanding, as of December 31, 2022 and 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, 2022 and 2021.
The following table presents ComEd's, BGE's, and ACE's preference securities authorized, none of which were outstanding as of December 31, 2022 and 2021. There are no shares of preference securities authorized for Exelon, PECO, Pepco, and DPL.
Preference Securities Authorized
ComEd 6,810,451
BGE(a)
6,500,000
ACE 3,000,000
__________
(a)Includes 4,600,000 shares of unclassified preference securities and 1,900,000 shares of previously redeemed preference securities as of December 31, 2022 and 2021.
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, 2022, there were approximately 34 million shares authorized for issuance under the LTIP. For the years ended December 31, 2022, 2021, and 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.
The following table presents the stock-based compensation expense included in Exelon's Consolidated Statements of Operations and Comprehensive Income. The Utility Registrants' stock-based compensation expense for the years ended December 31, 2022, 2021, and 2020 was not material.
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,
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 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.
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)
Nonvested at December 31, 2021(a)
1,222,516 $ 44.96
Granted 727,697 43.05
Change in performance (216,981) 42.73
Vested (233,318) 47.39
Forfeited (86,128) 42.61
Awards surrendered as a result of the separation (2,308,745)
Awards granted in conversion as a result of the separation 1,870,990
Undistributed vested awards(b)(c)
(109,226) 4.55
Nonvested at December 31, 2022(a)
866,805 $ 41.86
__________
(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 vested.
Year Ended December 31,
2022(a)
2021 2020
Weighted average grant date fair value (per share) $ 43.05 $ 43.37 $ 46.61
Total fair value of performance shares vested 29 44 39
Total fair value of performance shares settled in cash 25 28 63
__________
(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 ratably over the first 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 of 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
__________
(a)Excludes 476,592 and 609,934 of restricted stock 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.
The following table summarizes the weighted average grant date fair value and the total fair value of restricted stock units vested.
Year Ended December 31,
2022(a)
2021 2020
Weighted average grant date fair value (per share) $ 42.97 $ 44.21 $ 46.33
Total fair value of restricted stock units vested 23 34 54
__________
(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, 2022 all stock options were vested and 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 $ -
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
Year Ended December 31,
2022 2021 2020
Intrinsic value(a)
$ - $ 11 $ 5
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.
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
Balance at December 31, 2019 $ (2) $ (3,165)
$ (27) $ (3,194)
OCI before reclassifications (3) (357) 4 (356)
Amounts reclassified from AOCI - 150 - 150
Net current-period OCI (3) (207) 4 (206)
Balance at December 31, 2020 $ (5) $ (3,372) $ (23) $ (3,400)
OCI before reclassifications (1) 432 - 431
Amounts reclassified from AOCI - 219 - 219
Net current-period OCI (1) 651 - 650
Balance at December 31, 2021 $ (6) $ (2,721) $ (23) $ (2,750)
Separation of Constellation 6 1,994 23 2,023
OCI before reclassifications 2 46 - 48
Amounts reclassified from AOCI - 41 - 41
Net current-period OCI 2 87 - 89
Balance at December 31, 2022 $ 2 $ (640) $ - $ (638)
__________
(a)This AOCI component is included in the computation of net periodic pension and OPEB cost. Additionally, as of February 1, 2022, in connection with the separation, Exelon's pension and OPEB plans were remeasured. See Note 14 - Retirement Benefits for additional information. See Exelon's Statements of Operations and Comprehensive Income for individual components of AOCI.
The following table presents income tax benefit (expense) allocated to each component of Exelon's other comprehensive income (loss):
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
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 22 - Supplemental Financial Information
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
Exelon ComEd PECO BGE PHI Pepco DPL ACE
For the year ended December 31, 2022
Utility(a)
$ 878 $ 306 $ 166 $ 94 $ 312 $ 283 $ 25 $ 4
Property 377 31 17 191 138 94 42 2
Payroll 117 28 16 17 25 6 4 3
For the year ended December 31, 2021
Utility(a)
$ 774 $ 246 $ 139 $ 88 $ 301 $ 278 $ 22 $ 3
Property 364 39 18 176 131 88 40 3
Payroll 124 27 16 18 27 7 5 3
For the year ended December 31, 2020
Utility(a)
$ 759 $ 238 $ 135 $ 87 $ 299 $ 275 $ 21 $ 3
Property 336 30 16 164 126 84 39 3
Payroll 121 27 16 17 25 7 5 3
__________
(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 22 - 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
__________
(a)Exelon's amounts include amounts related to Generation prior to the separation. See Note 2 - Discontinued Operations for additional information.
(b)Included in Depreciation and amortization in the Registrants' Consolidated Statements of Operations and Comprehensive Income.
(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 22 - 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.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 22 - Supplemental Financial Information
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)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 22 - Supplemental Financial Information
The following tables provide a reconciliation of cash, restricted cash, and cash equivalents 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
__________
(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 22 - 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
__________
(a)The Registrants’ debt and equity security investments are recorded at fair market value.
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)Primarily includes accrued payroll, bonuses and other incentives, vacation, and benefits.
23. Related Party Transactions (All Registrants)
Utility Registrants' expense with Generation
The Utility Registrants incurred expenses from transactions with the Generation affiliate as described in the footnotes to the table below 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:
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 23 - Related Party Transactions
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
__________
(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 Generation.
(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 Generation 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 Corporate Support
The Registrants receive a variety of corporate support services from BSC. Pepco, DPL, and ACE also receive corporate support services from PHISCO. See Note 1 - Significant Accounting Policies for additional information regarding BSC and PHISCO.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 23 - 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 Receivables from affiliates and current Payables to affiliates:
December 31, 2022
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
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 23 - 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. PECO, and PHI Corporate participate in the Exelon money pool. Pepco, DPL, and ACE participate in the PHI intercompany money pool.
Noncurrent Receivables from affiliates
ComEd and PECO have noncurrent 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. 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 3 - Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Long-term debt to financing trusts
The following table presents Long-term debt to financing trusts:
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
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 Consolidated Statements of Operations and Comprehensive Income with the offset in Accrued expenses and Other Deferred credits and other liabilities on the Consolidated Balance Sheets.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
All Registrants
None.

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ITEM 9A. CONTROLS AND PROCEDURES
ITEM 9A. CONTROLS AND PROCEDURES
All Registrants-Disclosure Controls and Procedures
During the fourth quarter of 2022, each of the Registrant's management, including its principal executive officer and principal financial officer, evaluated disclosure controls and procedures related to the recording, processing, summarizing, and reporting of information in that Registrant’s periodic reports that it files with the SEC. These disclosure controls and procedures have been designed by the Registrants to ensure that (a) material information relating to that Registrant, including its consolidated subsidiaries, is accumulated and made known to that Registrant’s management, including its principal executive officer and principal financial officer, by other employees of that Registrant and its subsidiaries as appropriate to allow timely decisions regarding required disclosure, and (b) this information is recorded, processed, summarized, evaluated, and reported, as applicable, within the time periods specified in the SEC’s rules and forms. Due to the inherent limitations of control systems, not all misstatements may be detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Additionally, controls could be circumvented by the individual acts of some persons or by collusion of two or more people.
Accordingly, as of December 31, 2022, the principal executive officer and principal financial officer of each of the Registrants concluded that such Registrant’s disclosure controls and procedures were effective to accomplish its objectives.
All Registrants-Changes in Internal Control Over Financial Reporting
Each Registrant continually strives to improve its disclosure controls and procedures to enhance the quality of its financial reporting and to maintain dynamic systems that change as conditions warrant. However, there have been no changes in internal control over financial reporting that occurred during the fourth quarter of 2022 that have materially affected, or are reasonably likely to materially affect, any of the Registrant'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, 2022. As a result of that assessment, management determined that there were no material weaknesses as of December 31, 2022 and, therefore, concluded that each Registrant’s internal control over financial reporting was effective. Management’s Report on Internal Control Over Financial Reporting is included in ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

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ITEM 9B. OTHER INFORMATION
ITEM 9B. OTHER INFORMATION
All Registrants
None.

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE
Executive Officers
The information required by ITEM 10 relating to executive officers is set forth above in ITEM 1. BUSINESS-Executive officers of the Registrants at February 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 2023 proxy statement (2023 Exelon Proxy Statement) and the ComEd information statement (2023 ComEd Information Statement) to be filed with the SEC on or before April 30, 2023 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.

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ITEM 11. EXECUTIVE COMPENSATION
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 2023 Annual Meeting of Shareholders or the ComEd 2023 Information Statement, which are incorporated herein by reference.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
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 2023 Exelon Proxy Statement or the ComEd 2023 Information Statement and incorporated herein by reference.
Securities Authorized for Issuance under Exelon Equity Compensation Plans
[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)
Equity compensation plans approved by security holders 3,991,435 $ - 43,893,655
__________
(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.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
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 2023 Annual Meeting of Shareholders or the ComEd 2023 Information Statement, which are incorporated herein by reference.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
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 2023 in the Exelon Proxy Statement for the 2023 Annual Meeting of Shareholders and the ComEd 2023 Information Statement, which are incorporated herein by reference.
PART IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
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 14, 2023 of PricewaterhouseCoopers LLP (PCAOB ID 238)
Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2022, 2021, and 2020
Consolidated Statements of Cash Flows for the Years Ended December 31, 2022, 2021, and 2020
Consolidated Balance Sheets at December 31, 2022 and 2021
Consolidated Statements of Changes in Equity for the Years Ended December 31, 2022, 2021, and 2020
Notes to Consolidated Financial Statements
(ii) Financial Statement Schedules:
Schedule I-Condensed Financial Information of Parent (Exelon Corporate) at December 31, 2022 and 2021 and for the Years Ended December 31, 2022, 2021, and 2020
Schedule II-Valuation and Qualifying Accounts for the Years Ended December 31, 2022, 2021, and 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
See the Notes to Financial Statements
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) 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
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
See the Notes to Financial Statements
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
See the Notes to Financial Statements
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 owned 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%. As of February 1, 2022, as a result of the completion of 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 $449 million in outstanding commercial paper borrowings as of December 31, 2022 and no outstanding commercial paper as of December 31, 2021.
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 Corporation's 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 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 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. The remaining $575 million outstanding balance was repaid on October 11, 2022 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.
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%.
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.
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
As of December 31,
(in millions) 2022 2021
Accounts receivable from affiliates (current):
BSC(a)
$ 3 $ 4
Generation - 13
ComEd 4 5
PECO 2 4
BGE 1 2
PHISCO 7 6
Exelon Enterprises - 1
Total accounts receivable from affiliates (current): $ 17 $ 35
Notes receivable from affiliates (current):
BSC(a)
$ 138 $ 210
PHI
44 7
Total notes receivable from affiliates (current): $ 182 $ 217
Investments in affiliates from continuing operations:
BSC(a)
$ 384 $ 146
EEDC(b)
35,092 32,621
PCI 52 62
UII 365 365
Voluntary Employee Beneficiary Association trust 4 3
Exelon Enterprises 3 3
Conectiv 12 -
Exelon InQB8R 15 26
Other(d)
(2) (3,663)
Total investments in affiliates from continuing operations: $ 35,925 $ 29,563
Notes receivable from affiliates (noncurrent):
Generation(c)
$ - $ 319
Accounts payable to affiliates (current):
UII $ 360 $ 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)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
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)
$ 392
$ 174 (b)
$ 28 $ 185 (c)
$ 409
Deferred tax valuation allowance 37
-
57 - 94
Reserve for obsolete materials 13
8 - 6 15
For the year ended December 31, 2021
Allowance for credit losses(a)
$ 405
$ 107 (b)
$ -
$ 120 (c)
$ 392
Deferred tax valuation allowance 4
-
33 (d)
- 37
Reserve for obsolete materials 11
- 3 13
For the year ended December 31, 2020
Allowance for credit losses(a)
$ 213
$ 228 (b)
$ 38 $ 74 (c)
$ 405
Deferred tax valuation allowance 2
-
2 - 4
Reserve for obsolete materials 12
- 6 11
__________
(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 and Subsidiary Companies
(2) ComEd
(i) Financial Statements (Item 8):
Report of Independent Registered Public Accounting Firm dated February 14, 2023 of PricewaterhouseCoopers LLP (PCAOB ID 238)
Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2022, 2021, and 2020
Consolidated Statements of Cash Flows for the Years Ended December 31, 2022, 2021, and 2020
Consolidated Balance Sheets at December 31, 2022 and 2021
Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2022, 2021, and 2020
Notes to Consolidated Financial Statements
(ii) Financial Statement Schedule:
Schedule II-Valuation and Qualifying Accounts for the Years Ended December 31, 2022, 2021, and 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 Edison 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, 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)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) PECO
(i) Financial Statements (Item 8):
Report of Independent Registered Public Accounting Firm dated February 14, 2023 of PricewaterhouseCoopers LLP (PCAOB ID 238)
Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2022, 2021, and 2020
Consolidated Statements of Cash Flows for the Years Ended December 31, 2022, 2021, and 2020
Consolidated Balance Sheets at December 31, 2022 and 2021
Consolidated Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2022, 2021, and 2020
Notes to Consolidated Financial Statements
(ii) Financial Statement Schedule:
Schedule II-Valuation and Qualifying Accounts for the Years Ended December 31, 2022, 2021, and 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 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, 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 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
(i) Financial Statements (Item 8):
Report of Independent Registered Public Accounting Firm dated February 14, 2023 of PricewaterhouseCoopers LLP (PCAOB ID 238)
Statements of Operations and Comprehensive Income for the Years Ended December 31, 2022, 2021 and 2020
Statements of Cash Flows for the Years Ended December 31, 2022, 2021 and 2020
Balance Sheets at December 31, 2022 and 2021
Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2022, 2021 and 2020
Notes to Financial Statements
(ii) Financial Statement Schedule:
Schedule II-Valuation and Qualifying Accounts for the Years Ended December 31, 2022, 2021, and 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 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, 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)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.
Pepco Holdings LLC and Subsidiary Companies
(5) PHI
(i) Financial Statements (Item 8):
Report of Independent Registered Public Accounting Firm dated February 14, 2023 of PricewaterhouseCoopers LLP (PCAOB ID 238)
Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2022, 2021, and 2020
Consolidated Statements of Cash Flows for the Years Ended December 31, 2022, 2021, and 2020
Consolidated Balance Sheets at December 31, 2022 and 2021
Consolidated Statements of Changes in Equity for the Years Ended December 31, 2022, 2021, and 2020
Notes to Consolidated Financial Statements
(ii) Financial Statement Schedule:
Schedule II-Valuation and Qualifying Accounts for the Years Ended December 31, 2022, 2021, and 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
Pepco Holdings 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, 2022
Allowance for credit losses $ 143 $ 69 (a)
$ - $ 57 (b)
$ 155
Deferred tax valuation allowance 31 - 4 - 35
Reserve for obsolete materials 3 - - 1 2
For the year ended December 31, 2021
Allowance for credit losses $ 119 $ 41 (a)
$ 2 $ 19 (b)
$ 143
Deferred tax valuation allowance - - 31 (c)
- 31
Reserve for obsolete materials 2 1 - - 3
For the year ended December 31, 2020
Allowance for credit losses $ 53 $ 69 (a)
$ 13 $ 16 (b)
$ 119
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
(i) Financial Statements (Item 8):
Report of Independent Registered Public Accounting Firm dated February 14, 2023 of PricewaterhouseCoopers LLP (PCAOB ID 238)
Statements of Operations and Comprehensive Income for the Years Ended December 31, 2022, 2021 and 2020
Statements of Cash Flows for the Years Ended December 31, 2022, 2021 and 2020
Balance Sheets at December 31, 2022 and 2021
Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2022, 2021 and 2020
Notes to Financial Statements
(ii) Financial Statement Schedule:
Schedule II-Valuation and Qualifying Accounts for the Years Ended December 31, 2022, 2021, and 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 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, 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
(i) Financial Statements (Item 8):
Report of Independent Registered Public Accounting Firm dated February 14, 2023 of PricewaterhouseCoopers LLP (PCAOB ID 238)
Statements of Operations and Comprehensive Income for the Years Ended December 31, 2022, 2021 and 2020
Statements of Cash Flows for the Years Ended December 31, 2022, 2021 and 2020
Balance Sheets at December 31, 2022 and 2021
Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2022, 2021 and 2020
Notes to Financial Statements
(ii) Financial Statement Schedule:
Schedule II-Valuation and Qualifying Accounts for the Years Ended December 31, 2022, 2021, and 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, 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
(i) Financial Statements (Item 8):
Report of Independent Registered Public Accounting Firm dated February 14, 2023 of PricewaterhouseCoopers LLP (PCAOB ID 238)
Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2022, 2021, and 2020
Consolidated Statements of Cash Flows for the Years Ended December 31, 2022, 2021, and 2020
Consolidated Balance Sheets at December 31, 2022 and 2021
Consolidated Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2022, 2021, and 2020
Notes to Consolidated Financial Statements
(ii) Financial Statement Schedule:
Schedule II-Valuation and Qualifying Accounts for the Years Ended December 31, 2022, 2021, and 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
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, 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)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
2-1
Separation Agreement, dated January 31, 2022, between Exelon Corporation and Constellation Energy Corporation File No. 001-16169, Form 8K dated February 2, 2022, Exhibit 2.1
(3) Articles of Incorporation and Bylaws
Exelon Corporation
Exhibit No. Description Location
3-1
Amended and Restated Articles of Incorporation of Exelon Corporation, as amended July 24, 2018 File No. 001-16169, Form 8-K dated July 27, 2018, Exhibit 3.1
3-2
Amended and Restated Bylaws of Exelon Corporation, as amended on August 3, 2022 File No. 001-16169, Form 10-Q dated August 3, 2022, Exhibit 3.1
Baltimore Gas and Electric Company
Exhibit No. Description Location
3-3
Articles of Restatement to the Charter of Baltimore Gas and Electric Company, restated as of August 16, 1996 File No. 001-01910, Form 10-Q dated November 14, 1996, Exhibit 3
3-4
Articles of Amendment to the Charter of Baltimore Gas and Electric Company as of February 2, 2010 File No. 001-01910, Form 8-K dated February 4, 2010, Exhibit 3.1
3-5
Amended and Restated Bylaws of Baltimore Gas and Electric Company dated August 3, 2020 File No. 001-01910, Form 10-Q dated August 4, 2020, Exhibit 3.4
Commonwealth Edison Company
Exhibit No. Description Location
3-6
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 No. 001-01839, Form 10-K dated March 30, 1995, Exhibit 3.2
3-7
Amended and Restated Bylaws of Commonwealth Edison Company, Effective February 22, 2021 File No. 001-01839, Form 10-K dated February 24, 2021, Exhibit 3.6
PECO Energy Company
Exhibit No. Description Location
3-8
Amended and Restated Articles of Incorporation of PECO Energy Company File No. 001-01401, Form 10-K dated April 2, 2001, Exhibit 3.3
3-9
Amended and Restated Bylaws of PECO Energy Company dated August 3, 2020 File No. 000-16844, Form 10-Q dated August 4, 2020, Exhibit 3.3
Pepco Holdings LLC
Exhibit No. Description Location
3-10
Certificate of Formation of Pepco Holdings LLC, dated March 23, 2016 File No. 001-31403, Form 8-K dated March 24, 2016, Exhibit 3.2
3-11
Amended and Restated Limited Liability Company Agreement of Pepco Holdings LLC, dated August 3, 2020 File No. 001-31403, Form 10-Q dated August 4, 2020, Exhibit 3.5
Atlantic City Electric Company
Exhibit No. Description Location
3-12
Restated Certificate of Incorporation of Atlantic City Electric Company (filed in New Jersey on August 9, 2002) File No. 001-03559, Amendment No. 1 to Form U5B dated February 13, 2003, Exhibit B.8.1
3-13
Bylaws of Atlantic City Electric Company File No. 001-03559, Form 10-Q dated May 9, 2005, Exhibit 3.2.2
Delmarva Power & Light Company
Exhibit No. Description Location
3-14
Restated Certificate and Articles of Incorporation of Delmarva Power & Light Company (as filed in Delaware and Virginia) File No. 001-01405, Form 10-K dated March 1, 2007, Exhibit 3.3
3-15
Bylaws of Delmarva Power & Light Company File No. 001-01405, Form 10-Q dated May 9, 2005, Exhibit 3.2.1
Potomac Electric Power Company
Exhibit No. Description Location
3-16
Restated Articles of Incorporation of Potomac Electric Power Company (as filed in the District of Columbia) File No. 001-31403, Form 10-Q dated May 5, 2006, Exhibit 3.1
3-17
Restated Articles of Incorporation and Articles of Restatement of Potomac Electric Power Company (as filed in Virginia) File No. 001-01072, Form 10-Q dated November 4, 2011, Exhibit 3.3
3-18
Bylaws of Potomac Electric Power Company File No. 001-01072, Form 10-Q dated May 5, 2006, Exhibit 3.2
(4) Instruments Defining the Rights of Securities Holders, Including Indentures
Exelon Corporation
Exhibit No. Description Location
4-1
Exelon Corporation Direct Stock Purchase Plan File No. 333-206474, Registration Statement on Form S-3 dated August 19, 2015
4-2
Indenture dated May 1, 2001 between Exelon Corporation and The Bank of New York Mellon Trust Company, National Association, as trustee File No. 001-16169, Form 10-Q dated July 26, 2005, Exhibit 4.10
4-3
Form of $500,000,000 5.625% senior notes due 2035 dated June 9, 2005 issued by Exelon Corporation File No. 001-16169, Form 8-K dated June 9, 2005, Exhibit 99.3
4-4
Indenture, dated as of June 17, 2014, between Exelon Corporation and The Bank of New York Mellon Trust Company, N.A., as Trustee File No. 001-16169, Form 8-K dated June 23, 2014, Exhibit 4.1
4-4-1
First Supplemental Indenture, dated as of June 17, 2014, between Exelon Corporation and The Bank of New York Mellon Trust Company, N.A., as Trustee File No. 001-16169, Form 8-K dated June 23, 2014, Exhibit 4.2
4-4-2
Second Supplemental Indenture, dated April 3, 2017, between Exelon and The Bank of New York Mellon Trust Company, N.A., as trustee, to that certain Indenture (For Unsecured Subordinated Debt Securities), dated June 17, 2014 File No. 001-16169, Form 8-K dated April 4, 2017, Exhibit 4.3
4-5
Indenture, dated as of June 11, 2015, among Exelon Corporation and The Bank of New York Mellon Trust Company, National Association, as trustee
File No. 001-16169, Form 8-K dated June 11, 2015, Exhibit 4.1
4-5-1
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
File No. 001-16169, Form 8-K dated June 11, 2015, Exhibit 4.2
Exhibit No. Description Location
4-5-2
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
File No. 001-16169, Form 8-K dated December 2, 2015, Exhibit 4.1
4-5-3
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 File No. 001-16169, Form 8-K dated April 7, 2016, Exhibit 4.2
4-5-4
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 File No. 001-16169, Form 8-K dated April 1, 2020, Exhibit 4.2
4-5-5
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 File No. 001-16169, Form 8-K dated March 7, 2022, Exhibit 4.2
4-6
Description of Exelon Securities File No. 001-16169, Form 10-K dated February 11, 2020, Exhibit 4.63
Baltimore Gas and Electric Company
Exhibit No. Description Location
4-7
Form of 3.350% Note due 2023 issued June 17, 2013 by Baltimore Gas and Electric Company File No. 001-01910, Form 8-K dated June 17, 2013, Exhibit 4.1
4-8
Indenture dated as of July 24, 2006 between Baltimore Gas and Electric Company and Deutsche Bank Trust Company Americas, as trustee File No. 333-135991, Registration Statement on Form S-3 dated July 24, 2006, Exhibit 4(b)
4-9
Form of 2.400% notes due 2026 issued August 18, 2016 by Baltimore Gas and Electric Company File No. 001-01910, Form 8-K dated August 18, 2016, Exhibit 4.1
4-10
Form of 3.500% Note due 2046 issued August 18, 2016 by Baltimore Gas and Electric Company File No. 001-01910, Form 8-K dated August 18, 2016, Exhibit 4.2
4-11
Form of 3.750% Note due 2047 issued August 24, 2017 by Baltimore Gas and Electric Company File No. 001-01910, Form 8-K dated August 24, 2017, Exhibit 4.1
4-12
Form of 4.550% Note due 2052 issued June 6, 2022 by Baltimore Gas and Electric Company File No. 001-01910, Form 8-K dated June 6, 2022, Exhibit 4.2
4-13
Indenture, dated as of September 1, 2019, between Baltimore Gas and Electric Company and U.S. Bank National Association, as trustee File No. 001-01910, Form 8-K dated September 12, 2019, Exhibit 4.1
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 Registration No. 2-60201, Form S-7, Exhibit 2-1(a)
4-14-1
Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of January 13, 2003 File No. 001-01839, Form 8-K dated February 13, 2003, Exhibit 4.4
4-14-2
Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of February 22, 2006 File No. 001-01839, Form 8-K dated March 6, 2006, Exhibit 4.1
4-14-3
Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of March 1, 2007 File No. 001-01839, Form 8-K dated March 23, 2007, Exhibit 4.1
4-14-4
Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of December 20, 2007 File No. 001-01839, Form 8-K dated January 16, 2008, Exhibit 4.1
4-14-5
Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of September 17, 2012 File No. 001-01839, Form 8-K dated October 1, 2012, Exhibit 4.1
4-14-6
Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of August 1, 2013 File No. 001-01839, Form 8-K dated August 19, 2013, Exhibit 4.1
4-14-7
Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of January 2, 2014 File No. 001-01839, Form 8-K dated January 10, 2014, Exhibit 4.1
4-14-8
Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of October 28, 2014 File No. 001-01839, Form 8-K dated November 10, 2014, Exhibit 4.1
4-14-9
Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of February 18, 2015 File No. 001-01839, Form 8-K dated March 2, 2015, Exhibit 4.1
4-14-10
Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of November 4, 2015 File No. 001-01839, Form 8-K dated November 19, 2015, Exhibit 4.1
4-14-11
Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of June 15, 2016 File No. 001-01839, Form 8-K dated June 27, 2016, Exhibit 4.1
4-14-12
Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of August 9, 2017 File No. 001-01839, Form 8-K dated August 23, 2017, Exhibit 4.1
Exhibit No. Description Location
4-14-13
Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of February 6, 2018 File No. 001-01839, Form 8-K dated February 20, 2018, Exhibit 4.1
4-14-14
Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of July 26, 2018 File No. 001-01839, Form 8-K dated August 14, 2018, Exhibit 4.1
4-14-15
Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of February 7, 2019 File No. 001-01839, Form 8-K dated February 19, 2019, Exhibit 4.1
4-14-16
Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of October 29, 2019 File No. 001-01839, Form 8-K dated November 12, 2019, Exhibit 4.1
4-14-17
Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of February 10, 2020 File No. 001-01839, Form 8-K dated February 25, 2020, Exhibit 4.1
4-14-18
Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of February 16, 2021 File No. 001-01839, Form 8-K dated March 9, 2021, Exhibit 4.1
4-14-19
Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of August 2, 2021 File No. 001-01839, Form 8-K dated August 12, 2021, Exhibit 4.1
4-14-20
Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of February 23, 2022 File No. 001-01839, Form 8-K/A dated March 15, 2022, Exhibit 4.1
4-14-21
Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of December 21, 2022 File No. 001-01839, Form 8-K dated January 10, 2023, Exhibit 4.1
4-15
Instrument of Resignation, Appointment and Acceptance dated as of February 20, 2002, under the provisions of the Mortgage of Commonwealth Edison Company dated July 1, 1923, and Indentures Supplemental thereto, regarding corporate trustee File No. 001-01839, Form 10-K dated April 1, 2002, Exhibit 4.4.2
4-16
Instrument dated as of January 31, 1996, under the provisions of the Mortgage of Commonwealth Edison Company dated July 1, 1923 and Indentures Supplemental thereto, regarding individual File No. 001-01839, Form 10-K dated March 29, 1996, Exhibit 4.29
4-17
Description of ComEd Securities File No. 001-16169, Form 10-K dated February 11, 2020, Exhibit 4.65
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)
4-18-2
Supplemental Indenture to PECO Energy Company’s First and Refunding Mortgage dated as of April 15, 2004 File No. 000-16844, Form 10-Q dated September 30, 2004, Exhibit 4-1-1
4-18-3
Supplemental Indenture to PECO Energy Company’s First and Refunding Mortgage dated as of September 15, 2006 File No. 000-16844, Form 8-K dated September 25, 2006, Exhibit 4.1
4-18-4
Supplemental Indenture to PECO Energy Company’s First and Refunding Mortgage dated as of March 1, 2007 File No. 000-16844, Form 8-K dated March 19, 2007, Exhibit 4.1
4-18-5
Supplemental Indenture to PECO Energy Company’s First and Refunding Mortgage dated as of September 1, 2012 File No. 000-16844, Form 8-K dated September 17, 2012, Exhibit 4.1
4-18-6
Supplemental Indenture to PECO Energy Company’s First and Refunding Mortgage dated as of September 1, 2014 File No. 000-16844, Form 8-K dated September 15, 2014, Exhibit 4.1
4-18-7
Supplemental Indenture to PECO Energy Company’s First and Refunding Mortgage dated as of September 15, 2015 File No. 000-16844, Form 8-K dated October 5, 2015, Exhibit 4.1
4-18-8
Supplemental Indenture to PECO Energy Company’s First and Refunding Mortgage dated as of September 1, 2017 File No. 000-16844, Form 8-K dated September 18, 2017, Exhibit 4.1
4-18-9
Supplemental Indenture to PECO Energy Company’s First and Refunding Mortgage dated as of February 1, 2018 File No. 000-16844, Form 8-K dated February 23, 2018, Exhibit 4.1
4-18-10
Supplemental Indenture to PECO Energy Company’s First and Refunding Mortgage dated as of September 1, 2018 File No. 000-16844, Form 8-K dated September 11, 2018, Exhibit 4.1
4-18-11
Supplemental Indenture to PECO Energy Company’s First and Refunding Mortgage dated as of August 15, 2019 File No. 000-16844, Form 8-K dated September 10, 2019, Exhibit 4.1
4-18-12
Supplemental Indenture to PECO Energy Company’s First and Refunding Mortgage dated as of June 1, 2020 File No. 000-16844, Form 8-K dated June 8, 2020, Exhibit 4.1
4-18-13
Supplemental Indenture to PECO Energy Company’s First and Refunding Mortgage dated as of February 15, 2021 File No. 000-16844, Form 8-K dated March 8, 2021, Exhibit 4.1
Exhibit No. Description Location
4-18-14
Supplemental Indenture to PECO Energy Company’s First and Refunding Mortgage dated as of September 1, 2021 File No. 000-16844, Form 8-K dated September 14, 2021, Exhibit 4.1
4-18-15
Supplemental Indenture to PECO Energy Company’s First and Refunding Mortgage dated as of May 1, 2022 File No. 000-16844, Form 8-K dated May 24, 2022, Exhibit 4.1
4-18-16
Supplemental Indenture to PECO Energy Company’s First and Refunding Mortgage dated as of August 1, 2022 File No. 000-16844, Form 8-K dated August 23, 2022, Exhibit 4.1
4-19
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 No. 000-16844, Form 10-Q dated July 30, 2003, Exhibit 4.1
4-20
Preferred Securities Guarantee Agreement between PECO Energy Company, as Guarantor, and U.S. Bank National Association, as Trustee, dated as of June 24, 2003 File No. 000-16844, Form 10-Q dated July 30, 2003, Exhibit 4.2
4-21
PECO Energy Capital Trust IV Amended and Restated Declaration of Trust among PECO Energy Company, as Sponsor, U.S. Bank Trust National Association, as Delaware Trustee and Property Trustee, and J. Barry Mitchell, George R. Shicora and Charles S. Walls as Administrative Trustees dated as of June 24, 2003 File No. 000-16844, Form 10-Q dated July 30, 2003, Exhibit 4.3
4-22
Description of PECO Securities File No. 001-16169, Form 10-K dated February 11, 2020, Exhibit 4.64
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)
4-23-1 Supplemental Indenture to Atlantic City Electric Company Mortgage dated as of June 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, 1991, Exhibit 4(d)(1)(a)
4-23-3
Supplemental Indenture to Atlantic City Electric Company Mortgage dated as of April 1, 2004 File No. 001-03559, Form 8-K dated April 6, 2004, Exhibit 4.3
4-23-4
Supplemental Indenture to Atlantic City Electric Company Mortgage dated as of March 8, 2006 File No. 001-03559, Form 8-K dated March 17, 2006, Exhibit 4
4-23-5
Supplemental Indenture to Atlantic City Electric Company Mortgage dated as of March 29, 2011 File No. 001-03559, Form 8-K dated April 1, 2011, Exhibit 4.2
4-23-6
Supplemental Indenture to Atlantic City Electric Company Mortgage dated as of August 18, 2014 File No. 001-03559, Form 8-K dated August 19, 2014, Exhibit 4.2
4-23-7
Supplemental Indenture to Atlantic City Electric Company Mortgage dated as of December 1, 2015 File No. 001-03559, Form 8-K dated December 2, 2015, Exhibit 4.2 (included as Exhibit A to Exhibit 1.1).
4-23-8
Supplemental Indenture to Atlantic City Electric Company Mortgage dated as of October 9, 2018 File No. 001-03559, Form 8-K dated October 16, 2018, Exhibit 4.1
4-23-9
Supplemental Indenture to Atlantic City Electric Company Mortgage dated as of May 2, 2019 File No. 001-03559, Form 8-K dated May 21, 2019, File No. 4.3
4-23-10
Supplemental Indenture to Atlantic City Electric Company Mortgage dated as of June 1, 2020 File No. 001-03559, Form 8-K dated June 9, 2020, Exhibit 4.2
4-23-11
Supplemental Indenture to Atlantic City Electric Company Mortgage dated as of February 15, 2021 File No. 001-03559, Form 8-K dated March 10, 2021, Exhibit 4.1
4-23-12
Supplemental Indenture to Atlantic City Electric Company Mortgage dated as of November 1, 2021 File No. 001-03559, Form 8-K dated November 16, 2021, Exhibit 4.2
4-23-13
Supplemental Indenture to Atlantic City Electric Company Mortgage dated as of February 1, 2022 File No. 001-03559, Form 8-K dated February 15, 2022, Exhibit 4.2
4-24
Pollution Control Facilities Loan Agreement, dated as of June 1, 2020, between The Pollution Control Financing Authority of Salem County and Atlantic City Electric File No. 001-03559, Form 8-K dated June 2, 2020, Exhibit 4.1
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 33-1763, Registration Statement dated November 27, 1985, Exhibit 4-(A)(a)
4-25-1 Supplemental Indenture to Delmarva Power & Light Company Mortgage dated as of October 1, 1993 33-53855, Registration Statement dated January 30, 1995, Exhibit 4-L(a)
4-25-2 Supplemental Indenture to Delmarva Power & Light Company Mortgage dated as of October 1, 1994 33-53855, Registration Statement dated January 30, 1995, Exhibit 4-N(a)
4-25-3
Supplemental Indenture to Delmarva Power & Light Company Mortgage dated as of November 7, 2013 File No. 001-01405, Form 8-K dated November 8, 2013, Exhibit 4.2
4-25-4
Supplemental Indenture to Delmarva Power & Light Company Mortgage dated as of June 2, 2014 File No. 001-01405, Form 8-K dated June 3, 2014, Exhibit 4.3
4-25-5
Supplemental Indenture to Delmarva Power & Light Company Mortgage dated as of May 4, 2015 File No. 001-01405, Form 8-K dated May 5, 2015, Exhibit 4.2
4-25-6
Supplemental Indenture to Delmarva Power & Light Company Mortgage dated as of December 5, 2016 File No. 001-01405, Form 8-K dated December 12, 2016, Exhibit 4.2
4-25-7
Supplemental Indenture to Delmarva Power & Light Company Mortgage dated as of June 1, 2018 File No. 001-01405, Form 8-K dated June 21, 2018, Exhibit 4.2
4-25-8
Supplemental Indenture to Delmarva Power & Light Company Mortgage dated as of May 2, 2019 File No. 001-01405, Form 8-K dated December 12, 2019, Exhibit 4.2
4-25-9
Supplemental Indenture to Delmarva Power & Light Company Mortgage dated as of January 1, 2020 File No. 001-01405, Form 10-Q dated May 8, 2020, Exhibit 4.4
4-25-10
Supplemental Indenture to Delmarva Power & Light Company Mortgage dated as of June 1, 2020 File No. 001-01405, Form 8-K dated June 9, 2020, Exhibit 4.4
4-25-11
Supplemental Indenture to Delmarva Power & Light Company Mortgage dated as of February 15, 2021 File No. 001-01405, Form 8-K dated March 30, 2021, Exhibit 4.4
4-25-12
Supplemental Indenture to Delmarva Power & Light Company Mortgage dated as of February 1, 2022 File No. 001-01405, Form 8-K dated February 15, 2022, Exhibit 4.4
Exhibit No. Description Location
4-25-13
Supplemental Indenture to Delmarva Power & Light Company Mortgage dated as of January 1, 2022 File No. 001-01405, Form 10-Q dated May 9, 2022, Exhibit 4.1
4-26
Gas Facilities Loan Agreement, dated as of July 1, 2020, between The Delaware Economic Development Authority and Delmarva Power & Light Company File No. 001-01405, Form 8-K dated July 1, 2020, Exhibit 4.1
Potomac Electric Power Company
Exhibit No. Description Location
4-27 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)
4-27-1 Supplemental Indenture to Potomac Electric Power Company Mortgage dated as of December 10, 1939 8-K dated January 3, 1940, Exhibit B(a)
4-27-2
Supplemental Indenture to Potomac Electric Power Company Mortgage dated as of March 16, 2004 File No. 001-01072, Form 8-K dated March 23, 2004, Exhibit 4.3
4-27-3
Supplemental Indenture to Potomac Electric Power Company Mortgage dated as of May 24, 2005 File No. 001-01072, Form 8-K dated May 26, 2005, Exhibit 4.2
4-27-4
Supplemental Indenture to Potomac Electric Power Company Mortgage dated as of November 13, 2007 File No. 001-01072, Form 8-K dated November 15, 2007, Exhibit 4.2
4-27-5
Supplemental Indenture to Potomac Electric Power Company Mortgage dated as of March 24, 2008 File No. 001-01072, Form 8-K dated March 28, 2008, Exhibit 4.1
4-27-6
Supplemental Indenture to Potomac Electric Power Company Mortgage dated as of December 3, 2008 File No. 001-01072, Form 8-K dated December 8, 2008, Exhibit 4.2
4-27-7
Supplemental Indenture to Potomac Electric Power Company Mortgage dated as of March 28, 2012 File No. 001-01072, Form 8-K dated March 29, 2012, Exhibit 4.2
4-27-8
Supplemental Indenture to Potomac Electric Power Company Mortgage dated as of March 11, 2013 File No. 001-01072, Form 8-K dated March 12, 2013, Exhibit 4.2
4-27-9
Supplemental Indenture to Potomac Electric Power Company Mortgage dated as of November 14, 2013 File No. 001-01072, Form 8-K dated November 15, 2013, Exhibit 4.2
4-27-10
Supplemental Indenture to Potomac Electric Power Company Mortgage dated as of March 11, 2014 File No. 001-01072, Form 8-K dated March 12, 2014, Exhibit 4.2
Exhibit No. Description Location
4-27-11
Supplemental Indenture to Potomac Electric Power Company Mortgage dated as of March 9, 2015 File No. 001-01072, Form 8-K dated March 10, 2015, Exhibit 4.3
4-27-12
Supplemental Indenture to Potomac Electric Power Company Mortgage dated as of May 15, 2017 File No. 001-01072, Form 8-K dated May 22, 2017, Exhibit 4.2
4-27-13
Supplemental Indenture to Potomac Electric Power Company Mortgage dated as of June 1, 2018 File No. 001-01072, Form 8-K dated June 21, 2018, Exhibit 4.2
4-27-14
Supplemental Indenture to Potomac Electric Power Company Mortgage dated as of May 2, 2019 File No. 001-01072, Form 8-K dated June 13, 2019, Exhibit 4.2
4-27-15
Supplemental Indenture to Potomac Electric Power Company Mortgage dated as of February 12, 2020 File No. 001-01072, Form 8-K dated February 25, 2020, Exhibit 4.2
4-27-16
Supplemental Indenture to Potomac Electric Power Company Mortgage dated as of February 15, 2021 File No. 001-01072, Form 8-K dated March 30, 2021, Exhibit 4.4
4-27-17
Supplemental Indenture to Potomac Electric Power Company Mortgage dated as of March 1, 2022 File No. 001-01072, Form 8-K dated March 24, 2022, Exhibit 4.2
4-28
Exempt Facilities Loan Agreement dated as of June 1, 2019 between the Maryland Economic Development Corporation and Potomac Electric Power Company File No. 001-01072, Form 8-K dated June 27, 2019, Exhibit 4.1
(10) Material Contracts
Exelon Corporation
Exhibit No. Description Location
10-1
Transition Services Agreement, dated January 31, 2022, between Exelon Corporation and Constellation Energy Corporation File No. 001-16169, Form 8K dated February 2, 2022, Exhibit 10.1
10-2
Tax Matters Agreement, dated January 31, 2022, between Exelon Corporation and Constellation Energy Corporation File No. 001-16169, Form 8K dated February 2, 2022, Exhibit 10.2
10-3
Employee Matters Agreement, dated January 31, 2022, between Exelon Corporation and Constellation Energy Corporation File No. 001-16169, Form 8K dated February 2, 2022, Exhibit 10.3
10-4
Credit Agreement for $900,000,000 dated February 1, 2022, between Exelon Corporation and various financial institutions File No. 001-16169, Form 10-K dated February 25, 2022, Exhibit 10.40
10-5
Exelon Corporation Non-Employee Directors’ Deferred Stock Unit Plan (As Amended and Restated Effective April 28, 2020) File No. 001-16169, Form 10-Q dated August 4, 2020, Exhibit 10.1
Exhibit No. Description Location
10-6
Form of Exelon Corporation Unfunded Deferred Compensation Plan for Directors (as amended and restated Effective March 12, 2012) * File No. 001-16169, Form 10-K dated February 13, 2015, Exhibit 10.3
10-7
Exelon Corporation Supplemental Management Retirement Plan (As Amended and Restated Effective January 1, 2009) * File No. 001-16169, Form 10-K dated February 6, 2009, Exhibit 10.19
10-8
Exelon Corporation Annual Incentive Plan for Senior Executives (As Amended Effective January 1, 2014) * File No. 001-16169, Proxy Statement dated April 1, 2014, Appendix A
10-9
Exelon Corporation Employee Stock Purchase Plan, as amended and restated effective September 25, 2019 File No. 001-16169, Form 10-Q dated October 31, 2019, Exhibit 10.3
10-10
Exelon Corporation Employee Stock Purchase Plan for Unincorporated Subsidiaries, as amended and restated effective September 25, 2019 File No. 001-16169, Form 10-Q dated October 31, 2019, Exhibit 10.4
10-11
Exelon Corporation 2020 Long-Term Incentive Plan (Effective April 28, 2020) File No. 001-16169, Proxy Statement dated March 18, 2020, Appendix A
10-12
Exelon Corporation 2020 Long-Term Incentive Plan Prospectus, dated May 27, 2020 File No. 001-16169, Form 10-Q dated August 4, 2020, Exhibit 10.3
10-13
Form of Restricted Stock Unit Award Notice and Agreement under the Exelon Corporation 2020 Long-Term Incentive Plan File No. 001-16169, Form 10-Q dated August 4, 2020, Exhibit 10.4
10-14
Form of Performance Share Award Notice and Agreement under the Exelon Corporation 2020 Long-Term Incentive Plan File No. 001-16169, Form 10-Q dated August 4, 2020, Exhibit 10.5
10-15
Exelon Corporation Senior Management Severance Plan File No. 001-16169, Form 10-K dated February 11, 2020, Exhibit 10.13
10-16
Form of Separation Agreement under Exelon Corporation Senior Management Severance Plan (As Amended and Restated Effective January 1, 2020) File No. 001-16169, Form 10-K dated February 11, 2020, Exhibit 10.21
10-17
Exelon Corporation Executive Death Benefits Plan dated as of January 1, 2003 * File No. 001-16169, Form 10-K dated February 13, 2007, Exhibit 10.52
10-17-1
First Amendment to Exelon Corporation Executive Death Benefits Plan, Effective January 1, 2006 * File No. 001-16169, Form 10-K dated February 13, 2007, Exhibit 10.53
Exhibit No. Description Location
10-18
Exelon Corporation Deferred Compensation Plan (As Amended and Restated Effective January 1, 2005) File No. 001-16169, Form 10-K dated February 13, 2007, Exhibit 10.56
10-19
Exelon Corporation Stock Deferral Plan (As Amended and Restated Effective September 25, 2019) File No. 001-16169, Form 10-Q dated October 31, 2019, Exhibit 10.5
10-20
Form of Exelon Corporation Change in Control Agreement File No. 001-16169, Form 10-Q dated October 26, 2016, Exhibit 10.1
10-21
Letter Agreement, dated June 4, 2020, between Exelon Corporation and William A. Von Hoene, Jr. File No. 001-16169, Form 10-K dated February 24, 2021, Exhibit 10.74
Commonwealth Edison Company
Exhibit No. Description Location
10-22
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 File No. 001-01839, Form 8-K dated July 17, 2020, Exhibit 10.1
10-23
Credit Agreement for $1,000,000,000 dated February 1, 2022, between Commonwealth Edison Company and various financial institutions File No. 001-01839, Form 10-K dated February 25, 2022, Exhibit 10.42
Baltimore Gas and Electric Company
Exhibit No. Description Location
10-24
Credit Agreement for $600,000,000 dated February 1, 2022, between Baltimore Gas and Electric Company and various financial institutions File No. 001-01910, Form 10-K dated February 25, 2022, Exhibit 10.41
PECO Energy Company
Exhibit No. Description Location
10-25
PECO Energy Company Supplemental Pension Benefit Plan (As Amended and Restated Effective January 1, 2009) File No. 000-16844, Form 10-K dated February 6, 2009, Exhibit 10.20
10-26
Credit Agreement for $600,000,000 dated February 1, 2022, between PECO Energy Company and various financial institutions File No. 000-16844, Form 10-K dated February 25, 2022, Exhibit 10.43
Atlantic City Electric Company, Potomac Electric Power Company, Delmarva Power & Light Company
Exhibit No. Description Location
10-27
Bond Purchase Agreement, dated December 1, 2015, among Atlantic City Electric Company and the purchasers signatory thereto File No. 001-03559, Form 8-K dated December 2, 2015, Exhibit 1.1
10-28
Credit Agreement for $900,000,000 dated February 1, 2022, between Potomac Electric Power Company, Delmarva Power & Light Company, Atlantic City Electric Company and various financial institutions File Nos. 001-010172, 001-01405, 001-03559, Form 10-K dated February 25, 2022, Exhibit 10.44
(14) Code of Ethics
Exelon Corporation
Exhibit No. Description Location
14-1
Exelon Code of Conduct, as amended June 20, 2022 File No. 001-16169, Form 10-Q dated August 3, 2022, Exhibit 14
Exhibit No. Description
Subsidiaries
21-1
Exelon Corporation
21-2
Commonwealth Edison Company
21-3
PECO Energy Company
21-4
Baltimore Gas and Electric Company
21-5
Pepco Holdings LLC
21-6
Potomac Electric Power Company
21-7
Delmarva Power & Light Company
21-8
Atlantic City Electric Company
Consent of Independent Registered Public Accountants
23-1
Exelon Corporation
23-2
Commonwealth Edison Company
23-3
PECO Energy Company
23-4
Baltimore Gas and Electric Company
23-5
Potomac Electric Power Company
23-6
Delmarva Power & Light Company
23-7
Atlantic City Electric Company
Power of Attorney (Exelon Corporation)
24-1
Anthony K. Anderson
24-2
Ann C. Berzin
24-3
Calvin G. Butler, Jr.
Exhibit No. Description
24-4
W. Paul Bowers
24-5
Marjorie Rodgers Cheshire
24-6
Carlos Gutierrez
24-7
Linda P. Jojo
24-8
Paul Joskow
24-9
John F. Young
Power of Attorney (Commonwealth Edison Company)
24-10
Calvin G. Butler, Jr.
24-11
Ricardo Estrada
24-12
Zaldwaynaka Scott
24-13
Smita Shah
24-14
Gil C. Quiniones
Power of Attorney (PECO Energy Company)
24-15
Nicholas Bertram
24-16
Calvin G. Butler, Jr.
24-17
Nelson A. Diaz
24-18
John S. Grady
24-19
Michael A. Innocenzo
24-20
Charisse R. Lillie
24-21
Sharmaine Matlock-Turner
24-22
Michael Nutter
Power of Attorney (Baltimore Gas and Electric Company)
24-23
Calvin G. Butler, Jr.
24-24
James R. Curtiss
24-25
Carim V. Khouzami
24-26
Keith Lee
24-27
Rachel Garbow Monroe
24-28
Byron Marchant
24-29
Tim Regan
24-30
Amy Seto
24-31
Maria Harris Tildon
Power of Attorney (Pepco Holdings LLC)
24-32
Antoine Allen
24-33
J. Tyler Anthony
Exhibit No. Description
24-34
Charlene Dukes
24-35
Calvin G. Butler, Jr.
24-36
Debra P. DiLorenzo
24-37
Benjamin Wu
24-38
Linda W. Cropp
Power of Attorney (Potomac Electric Power Company)
24-39
J. Tyler Anthony
24-40
Phillip S. Barnett
24-41
Calvin G. Butler, Jr.
24-42
Rodney Oddoye
24-43
Elizabeth O'Donnell
24-44
Tamla Olivier
24-45
Anne Bancroft
Power of Attorney (Delmarva Power & Light Company)
24-46
J. Tyler Anthony
24-47
Calvin G. Butler, Jr.
Power of Attorney (Atlantic City Electric Company)
24-48
J. Tyler Anthony
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, 2022 filed by the following officers for the following registrants:
Exhibit No. Description
31-1
Filed by Calvin G. Butler, Jr. for Exelon Corporation
31-2
Filed by Jeanne M. Jones for Exelon Corporation
31-3
Filed by Gil C. Quiniones for Commonwealth Edison Company
31-4
Filed by Elisabeth J. Graham for Commonwealth Edison Company
31-5
Filed by Michael A. Innocenzo for PECO Energy Company
31-6
Filed by Marissa Humphrey for PECO Energy Company
31-7
Filed by Carim V. Khouzami for Baltimore Gas and Electric Company
31-8
Filed by David M. Vahos for Baltimore Gas and Electric Company
31-9
Filed by J. Tyler Anthony for Pepco Holdings LLC
31-10
Filed by Phillip S. Barnett for Pepco Holdings LLC
31-11
Filed by J. Tyler Anthony for Potomac Electric Power Company
31-12
Filed by Phillip S. Barnett for Potomac Electric Power Company
31-13
Filed by J. Tyler Anthony for Delmarva Power & Light Company
Exhibit No. Description
31-14
Filed by Phillip S. Barnett for Delmarva Power & Light Company
31-15
Filed by J. Tyler Anthony for Atlantic City Electric Company
31-16
Filed by Phillip S. Barnett for Atlantic City Electric Company
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, 2022 filed by the following officers for the following registrants:
Exhibit No. Description
32-1
Filed by Calvin G. Butler, Jr. for Exelon Corporation
32-2
Filed by Jeanne M. Jones for Exelon Corporation
32-3
Filed by Gil C. Quiniones for Commonwealth Edison Company
32-4
Filed by Elisabeth J. Graham for Commonwealth Edison Company
32-5
Filed by Michael A. Innocenzo for PECO Energy Company
32-6
Filed by Marissa Humphrey for PECO Energy Company
32-7
Filed by Carim V. Khouzami for Baltimore Gas and Electric Company
32-8
Filed by David M. Vahos for Baltimore Gas and Electric Company
32-9
Filed by J. Tyler Anthony for Pepco Holdings LLC
32-10
Filed by Phillip S. Barnett for Pepco Holdings LLC
32-11
Filed by J. Tyler Anthony for Potomac Electric Power Company
32-12
Filed by Phillip S. Barnett for Potomac Electric Power Company
32-13
Filed by J.Tyler Anthony for Delmarva Power & Light Company
32-14
Filed by Phillip S. Barnett for Delmarva Power & Light Company
32-15
Filed by J. Tyler Anthony for Atlantic City Electric Company
32-16
Filed by Phillip S. Barnett for Atlantic City Electric Company
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.