Table of ~~which 11,845 or 34% were covered by collective bargaining agreements (CBAs):~~Contents

IBEW
Local 15^(a)

IBEW
Local 614^(b)
Other CBAs
Total
Employees
Covered by
CBAs

Total
Employees
Generation^(c)
1,660
97
2,729
4,486
15,011
ComEd 3,515
—
—
3,515
6,280
PECO —
1,148
—
1,148
2,534
BGE^(d)
—
—
—
—
3,022
PHI^(e)
—
—
322
322
1,320
Pepco^(e)
—
—
1,151
1,151
1,582
DPL^(e)
—
—
688
688
944
ACE^(e)
—
—
421
421
647
Other^(f)
65
—
49
114
3,281
Total 5,240

1,245

5,360

11,845

34,621

~~__________~~


~~(a)~~	A separate CBA between ComEd and IBEW Local 15 covers approximately 65 employees in ComEd’s System Services Group and was renewed in 2016. Generation’s and ComEd’s separate CBAs with IBEW Local 15 will expire in 2022.


~~(b)~~	PECO craft and call center employees in the Philadelphia service territory are covered by CBAs with IBEW Local 614, both expiring in 2021. Additionally, Exelon Power, an operating unit of Generation, has an agreement covering 97 employees, which was renewed in 2016 and expiring in 2019.

~~(c)~~

During 2017, Generation finalized CBAs with the Security Officer unions at LaSalle, Limerick and Quad Cities, which all will expire in 2020 and Dresden expiring in 2021. Additionally, during 2017, Generation acquired and combined two CBAs at FitzPatrick into one CBA covering both craft and security employees, which will expire in 2023. During 2016, Generation finalized its CBA with the Security Officer union at Oyster Creek, expiring in 2022 and New Energy IUOE Local 95-95A, which will expire in 2021. Also, during 2016, Generation finalized a 5-year agreement with the New England ENEH, UWUA Local 369, which will expire in 2022. During 2015, Generation finalized its CBA with Clinton Local 51 which will expire in 2020; its two CBAs with Local 369 at Mystic 7 and Mystic 8/9, both expiring in 2020; and four Security Officer unions at Braidwood, Byron, Clinton and TMI, all expiring between 2018 and 2021, respectively. During 2014, Generation finalized CBAs with TMI Local 777 and Oyster Creek Local 1289, expiring in 2019 and 2021, respectively and CENG finalized its CBA with Nine Mile Point which will expire in 2020. Additionally, during 2014, an agreement was negotiated with Las Vegas District Energy and IUOE Local 501, which will expire in 2018.


~~(d)~~	In January 2017, an election was held at BGE which resulted in union representation for 1,394 employees at the end of the year. BGE and IBEW Local 410 are negotiating an initial agreement which could result in some modifications to wages, hours and other terms and conditions of employment. No agreement has been finalized to date and management cannot predict the outcome of such negotiations.


~~(e)~~	PHI’s utility subsidiaries are parties to five CBAs with four local unions. CBAs are generally renegotiated every three to five years. All of these CBAs were renegotiated in 2014 and were extended through various dates ranging from October 2018 through June 2020.


~~(f)~~	~~Other includes shared services employees at BSC.~~

Environmental Matters and Regulation

~~General~~

The Registrants are subject to comprehensive and complex environmental legislation ~~regarding environmental matters by~~and regulation at the federal, ~~government and various~~ state, and local ~~jurisdictions in which they operate their facilities. The Registrants are also subject~~levels, including requirements relating to ~~environmental regulations administered by the EPA~~climate change, air and ~~various state and local environmental protection agencies. Federal, state and local regulation includes the authority to regulate air,~~ water ~~and~~quality, solid and hazardous waste, ~~disposal.~~and impacts on species and habitats.

The Exelon Board of Directors is responsible for overseeing the management of environmental matters. Exelon has a management team to address environmental compliance and strategy, including the CEO; the Senior Vice President ~~Corporate~~and Chief Strategy and ~~Chief~~ Sustainability Officer; ~~the Senior Vice President, Competitive Market Policy; and the Director, Safety & Sustainability,~~ as well as senior management of ~~Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE.~~the Utility Registrants. Performance of those individuals directly involved in environmental compliance and strategy is reviewed and affects compensation as part of the annual individual performance review process. The ~~Exelon Board of Directors has delegated~~Audit and Risk Committee oversees compliance with environmental laws and regulations, including environmental risks related to ~~its Generation Oversight Committee~~Exelon's operations and ~~the~~facilities, as well as SEC disclosures related to environmental matters. Exelon's Corporate Governance Committee has the authority to oversee Exelon’s ~~compliance with health, environmental and safety laws and regulations and its strategies and efforts to protect and improve the quality of the environment, including Exelon’s internal~~ climate change and sustainability policies and programs, as discussed in further detail below. The respective Boards of ~~ComEd, PECO, BGE, Pepco, DPL and ACE~~the Utility Registrants oversee environmental ~~health and safety~~ issues related to these companies. The Exelon Board of Directors has general oversight responsibilities for ESG matters, including strategies and efforts to protect and improve the quality of the environment.

Climate Change

As detailed below, the Registrants face climate change mitigation and transition risks as well as adaptation risks. Mitigation and transition risks include changes to the energy systems as a result of new technologies, changing customer expectations and/or voluntary GHG goals, as well as local, state or federal regulatory requirements intended to reduce GHG emissions. Adaptation risk refers to risks to the Registrants' facilities or operations that may result from changes to the physical climate and environment, such as changes to temperature, weather patterns and sea level.

Climate Change Mitigation and Transition

The Registrants support comprehensive federal climate legislation that addresses the urgent need to substantially reduce national GHG emissions while providing appropriate protections for consumers, businesses, and the economy. In the absence of comprehensive federal climate legislation, Exelon supports the EPA moving forward with meaningful regulation of GHG emissions under the Clean Air ~~Quality~~Act.

~~Air quality~~The Registrants currently are subject to, and may become subject to additional, federal and/or state legislation and/or regulations ~~promulgated~~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 ~~EPA~~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 ~~various state~~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.

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In August 2021, Exelon announced a Path to Clean goal to collectively reduce their operations-driven GHG emissions 50% by 2030 against a 2015 baseline, and to reach net zero operations-driven GHG emissions by 2050, while also supporting customers and communities to achieve their clean energy and emissions goals. Exelon’s quantitative goals include its Scope 1 and 2 GHG emissions, with the exception of Scope 2 line losses, and builds upon Exelon's long-standing commitment to reducing our GHG emissions. Exelon's activities in support of the Path to Clean goal will include efficiency and clean electricity for operations, vehicle fleet electrification, equipment and processes to reduce sulfur hexafluoride (SF6) leakage, investments in natural gas infrastructure to minimize methane leaks and increase safety and reliability, and investment and collaboration to develop new technologies. Beyond 2030, Exelon recognizes that technology advancement and continued policy support will be needed to ensure achievement of Net-Zero by 2050. Exelon is laying the groundwork by partnering with national labs, universities and research consortia to research, develop, and pilot clean technologies that will be needed, as well as working with our states, jurisdictions and policy makers to understand the scope and scale of energy transformation, and needed policies and incentives, that will be needed to reach local ~~environmental agencies impose restrictions on emission~~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 ~~particulates, sulfur dioxide (SO~~2~~), nitrogen oxides (NO~~x~~), mercury~~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 ~~air pollutants~~emerging technologies can also support the transition, lessen the strain on electric system expansion, and ~~require permits~~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 ~~operation~~the Utility Registrants and their service territories. Exelon believes its market and business model could be significantly affected by the transition of ~~emitting sources. Such permits have been obtained~~the energy system, such as ~~needed by Exelon’s subsidiaries. However, due to its low emitting generation fleet comprised of nuclear,~~through an increased electric load and decreased demand for natural gas, ~~hydroelectric, wind~~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

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accepted the Agreement, which resulted in the United States’ formal re-entry on February 19, 2021. The United States has set an economy-wide target of reducing its net GHG emissions by 50-52% below 2005 levels by 2030. On November 11, 2022 at the UNFCCC Conference of the Parties (COP 27), President Biden recommitted the U.S. to these goals and detailed the significant domestic climate actions the U.S. had taken to spur a new era of clean American manufacturing, enhance energy security, and drive down the costs of clean energy for consumers in the U.S. and around the world.

Federal Climate Change Legislation and Regulation.On August 16, 2022, President Biden signed the Inflation Reduction Act (IRA), which aims to reduce U.S. carbon emissions and promote economic development through investments in clean and renewable energy projects. The consumer-facing clean energy tax credits created or expanded by the IRA are intended to drive rapid adoption of energy efficiency, electric transportation, and solar ~~compliance with~~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 ~~Federal~~Clean Air Act.TheEPA’s 2015 Clean Power Plan (CPP) established regulations addressing carbon dioxide emissions from existing fossil-fired power plants under Clean Air Act ~~does not~~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 ~~a material~~state and regional programs to reduce GHG emissions and renewable and other portfolio standards, which impact ~~on Generation’s operations.~~

the power sector. See ~~ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~discussion below for additional information ~~regarding clean air regulation~~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 ~~forms~~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 ~~CSAPR,~~Combined Notes to Consolidated Financial Statements for additional information on CEJA.

The Registrants cannot predict the ~~regulation~~nature of ~~hazardous air pollutants~~future regulations or how such regulations might impact future financial statements.

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Renewable and Clean Energy Standards. Each of the states where Exelon operates have adopted some form of renewable or clean energy procurement requirement. These standards impose varying levels of mandates for procurement of renewable or clean electricity (the definition of which varies by state) and/or energy efficiency. These are generally expressed as a percentage of annual electric load, often increasing by year. The Utility Registrants comply with these various requirements through acquiring sufficient bundled or unbundled credits such as RECs, CMCs, or ZECs, or paying an alternative compliance payment, and/or a combination of these compliance alternatives. The Utility Registrants are permitted to recover from ~~coal- and oil-fired electric generating facilities under MATS, and regulation~~retail customers the costs of ~~GHG emissions.~~complying with their state RPS requirements, including the procurement of RECs or other alternative energy resources. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

Other Environmental Regulation

Water Quality

Under the federal Clean Water Act, NPDES permits for discharges into waterways are required to be obtained from the EPA or from the state environmental agency to which the permit program has been delegated, and permits must be renewed periodically. Certain of Exelon's facilities discharge ~~stormwater and industrial wastewater~~water into waterways and are therefore subject to these regulations and operate under NPDES permits or pending applications for renewals of such permits after being granted an administrative extension. Generation is also subject to the jurisdiction of the Delaware River Basin Commission and the Susquehanna River Basin Commission, regional agencies that primarily regulate water usage.permits.

~~Section 316(b) of the Clean Water Act~~

Section 316(b) requires that the cooling water intake structures at electric power plants reflect the best technology available to minimize adverse environmental impacts, and is implemented through state-level NPDES permit programs. All of Generation’s power generation facilities with cooling water systems are subject to the regulations. Facilities without closed-cycle recirculating systems (e.g., cooling towers)

are potentially most affected by recent changes to the regulations. For Generation, those facilities are Calvert Cliffs, Clinton, Dresden, Eddystone, Fairless Hills, FitzPatrick, Ginna, Gould Street, Mountain Creek, Handley, Mystic 7, Nine Mile Point Unit 1, Peach Bottom, Quad Cities, Riverside and Salem.

On October 14, 2014, the EPA's Section 316(b) rule became effective. The rule requires that a series of studies and analyses be performed to determine the best technology available to minimize adverse impacts on aquatic life, followed by an implementation period for the selected technology. The timing of the various requirements for each facility is related to the status of its current NPDES permit and the subsequent renewal period. There is no fixed compliance schedule, as this is left to the discretion of the state permitting director.

Until the compliance requirements are determined by the applicable state permitting director on a site-specific basis for each plant, Generation cannot estimate the effect that compliance with the rule will have on the operation of its generating facilities and its future results of operations, cash flows, and financial position. Should a state permitting director determine that a facility must install cooling towers to comply with the rule, that facility’s economic viability could be called into question. However, the potential impact of the rule has been significantly reduced since the final rule does not mandate cooling towers as a national standard and sets forth technologies that are presumptively compliant, and the state permitting director is required to apply a cost-benefit test and can take into consideration site-specific factors, such as those that would make cooling towers infeasible.

Pursuant to discussions with the NJDEP in 2010 regarding the application of Section 316(b) to Oyster Creek, Generation agreed to permanently cease generation operations at Oyster Creek by December 31, 2019, ten years before the expiration of its operating license in 2029. The agreement only applies to Oyster Creek based on its unique circumstances and does not set any precedent for the ultimate compliance requirements for Section 316(b) at Exelon’s other plants. On February 2, 2018, Exelon announced that Generation will permanently cease generation operations at Oyster Creek at the end of its current operating cycle in October 2018.

~~New York Facilities~~

In July 2011, the New York Department of Environmental Conservation (DEC) issued a policy regarding the best available technology for cooling water intake structures. Through its policy, the DEC established closed-cycle cooling or its equivalent as the performance goal for all existing facilities, but also provided that the DEC will select a feasible technology whose costs are not wholly disproportionate to the environmental benefits to be gained and allows for a site-specific determination where the entrainment performance goal cannot be achieved (i.e., the requirement most likely to support cooling towers). The R.E Ginna and Nine Mile Point Unit 1 power generation facilities received renewals of their state water discharge permits in 2014 and cooling towers were not required. These facilities are now engaged in the required analyses to enable the environmental agency to determine the best technology available in the next permit renewal cycles.

~~Salem~~

On July 28, 2016, the NJDEP issued a final permit for Salem that did not require the installation of cooling towers and allows Salem to continue to operate utilizing the existing cooling water system with certain required system modifications. However, the permit is being challenged by an environmental organization, and if successful, could result in additional costs forUnder Clean Water Act ~~compliance. Potential cooling~~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 ~~system modification costs could be material and could adversely impact the economic competitiveness of this facility.~~

quality certification under Clean Water Act section 401.

Solid and Hazardous Waste and Environmental Remediation

CERCLA provides for ~~immediate~~ response and removal actions coordinated by the EPA in the event of threatened releases of hazardous substances and authorizes the EPA either to clean up sites at which hazardous substances have created actual or potential environmental hazards or to order persons responsible for the situation to do so. Under CERCLA, generators and transporters of hazardous substances, as well as past and present owners and operators of hazardous waste sites, are strictly, jointly and severally liable for the cleanup costs of hazardous waste at sites, ~~most~~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 prior~~oversight. Most states have also enacted statutes that contain provisions substantially similar to ~~listing on~~CERCLA. Such statutes apply in many states where the ~~NPL. Various states,~~Registrants currently own or operate, or previously owned or operated, facilities, including Delaware, Illinois, Maryland, New Jersey, and Pennsylvania and the District of ~~Columbia have also enacted statutes that contain provisions substantially similar to CERCLA.~~Columbia. In addition, RCRA governs treatment, storage and disposal of solid and hazardous wastes and cleanup of sites where such activities were conducted.

Generation, ComEd, PECO, BGE, Pepco, DPL and ACE and their subsidiaries are, or could become in the future, parties to proceedings initiated by the EPA, state agencies and/or other responsible parties under CERCLA and RCRA with respect to a number of sites, including MGP sites, or may undertake to investigate and remediate sites for which they may be subject to enforcement actions by an agency or third-party.

~~See Note 23 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information regarding solid and hazardous waste regulation and legislation.~~

~~Environmental Remediation~~

ComEd’s and PECO’s environmental liabilities primarily arise from contamination at former MGP sites. ComEd, pursuant to an ICC order, and PECO, pursuant to settlements of natural gas distribution rate cases with the PAPUC, have an on-going process to recover environmental remediation costs of the MGP sites through a provision within customer rates. BGE, ACE, Pepco and DPL do not have material contingent liabilities relating to MGP sites. The amount to be expended in 2018 for compliance with environmental remediation related to contamination at former MGP sites and other gas purification sites is expected to total $48 million, consisting of $42 million and $6 million at ComEd and PECO respectively. The Utility Registrants also have contingent liabilities for environmental remediation of non-MGP contaminants (e.g., PCBs). As of December 31, 2017, the Utility Registrants have established appropriate contingent liabilities for environmental remediation requirements.

The Registrants’ operations have in the past, and may in the future, require substantial expenditures in order to comply with ~~environmental laws. Additionally, under~~these Federal and state environmental laws. Under these laws, the Registrants ~~are generally~~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.

~~In addition, Generation,~~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

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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 ~~Notes~~Note 3 — Regulatory Matters and 23Note 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’ ~~results of operations, cash flows and financial positions.~~

~~Global Climate Change~~

Exelon has utility and generation assets, and customers, that are and will be further subject to the impacts of climate change. Accordingly, Exelon is engaged in a variety of initiatives to understand and mitigate these impacts, including investments in resiliency, partnering with federal, state and local governments to minimize impacts, and, importantly, advocating for public policy that reduces emissions that cause climate change. Exelon, as a producer of electricity from predominantly low- and zero-carbon generating facilities (such as nuclear, hydroelectric, natural gas, wind and solar photovoltaic), has a relatively small greenhouse gas (GHG) emission profile, or carbon footprint, compared to other domestic generators of electricity (Exelon neither owns or operates any coal-fueled generating assets). Exelon's natural gas and biomass fired generating plants produce GHG emissions, most notably, CO2~~. However, Generation’s owned-asset emission intensity, or rate of carbon dioxide equivalent (CO~~₂e) emitted per unit of electricity generated, is among the lowest in the industry. In 2017, while fossil fuel powered approximately 33 percent of Exelon's owned generating capacity, fossil fuel-fired generation represents less than 12 percent of Exelon's overall generation on a MWh basis. Other GHG emission sources at Exelon include natural gas (methane) leakage on the natural gas systems, sulfur hexafluoride (SF6) leakage from electric transmission and distribution operations, refrigerant leakage from chilling and cooling equipment, and fossil fuel combustion in motor vehicles. Exelon facilities and operations are subject to the global impacts of climate change and Exelon believes its operations could be significantly affected by the physical risks of climate change. See ITEM 1A. RISK FACTORS for information regarding the market and financial, regulatory and legislative, and operational risks associated with climate change.

~~Climate Change Regulation~~

~~Exelon is or may become subject to additional climate change regulation or legislation at the federal, regional and state levels.~~

~~International Climate Change Agreements.~~ ~~At the international level, the United States is a Party to the United Nations Framework Convention on Climate Change (UNFCCC). The Parties to the UNFCCC adopted the Paris Agreement at the 21~~^stsession of the UNFCCC Conference of the Parties (COP 21) on December 12, 2015, and it became effective on November 4, 2016. Under the Paris Agreement, the Parties agreed to try to limit the global average temperature increase to 2°C (3.6°F) above pre-industrial levels. In doing so, Parties developed their own national reduction commitments. The United States submitted a non-binding target of 17% below 2005 emission levels by 2020 and 26% to 28% below 2005 levels by 2025. President Trump has stated his intention to withdraw the U.S. from the Paris Agreement, but no formal action has been initiated.

~~Federal Climate Change Legislation and Regulation.~~ It is highly unlikely whether federal legislation to reduce GHG emissions will be enacted in the near-term. If such legislation is adopted, Exelon may incur costs either to further limit or offset the GHG emissions from its operations or to procure emission allowances or credits. More importantly, continued inaction could negatively impact the value of Exelon’s low-carbon fleet.

Under the Obama Administration, the EPA proposed and finalized regulations for fossil fuel-fired power plants, referred to as the Clean Power Plan, which are currently being litigated. However, the Trump Administration has proposed a repeal of the Clean Power Plan, and is expected to seek broad public comment on whether and how to regulate GHGs at the federal level. Details are not yet known and are likely to be further informed by the public comment process.

Given this uncertainty, Exelon and Generation cannot at this time predict the future of the Clean Power Plan, or its repeal and/or replacement, or individual state responses to Clean Power Plan developments or how developments will impact their future results of operations, cash flows and financial positions.

~~Regional and State Climate Change Legislation and Regulation.~~ A number of states in which Exelon operates have state and regional programs to reduce GHG emissions, including from the power sector. As the nation’s largest generator of carbon-free electricity, our fleet supports these efforts to produce safe, reliable electricity with minimal GHGs. Notably, nine northeast and mid-Atlantic states (Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New York, Rhode Island and Vermont) currently participate in the Regional Greenhouse Gas Initiative (RGGI), which is in the process of strengthening its requirements. The program requires most fossil fuel-fired power plants in the region to hold allowances, purchased at auction, for each ton of CO₂ ~~emissions. Non-emitting resources do not have to purchase or hold these allowances.~~

Many states in which Exelon subsidiaries operate also have state-specific programs to address GHGs, including from power plants. Most notable of these, besides RGGI, are through renewable and other portfolio standards. Additionally, in response to a court decision clarifying obligations under the Global Warming Solutions Act, the Massachusetts Department of Environmental Protection in 2017 finalized regulations establishing a statewide cap on CO₂ emissions from fossil fuel power plants (Massachusetts remains in RGGI as well). The effect of this new obligation and potential for market illiquidity in the early years represent a risk to Generation’s Massachusetts fossil facilities, including Medway and Mystic. At the same time, the District of Columbia is considering a plan to incorporate the cost of carbon into electricity, via consumption, as well as directly into the cost of transportation and home heating fuels. Details remain to be developed, but the specifics could have implications for Pepco’s operations.

Regardless of whether GHG regulation occurs at the local, state, or federal level, Exelon remains one of the largest, lowest-carbon electric generators in the United States, relying mainly on nuclear, natural gas, hydropower, wind, and solar. The extent that the low-carbon generating fleet will continue to be a competitive advantage for Exelon depends on what, if anything, replaces the Clean Power Plan at the federal level, new or expanded state action on greenhouse gas emissions or direct support of clean energy technologies, including nuclear, as well as potential market reforms that value our fleet’s emission-free attributes.

~~Renewable and Alternative Energy Portfolio Standards~~

Thirty-nine states and the District of Columbia, incorporating the vast majority of Exelon operations as well as all utility operations, have adopted some form of RPS requirement. These standards impose varying levels of mandates for procurement of renewable or clean electricity (the definition of which varies by state) and/or energy efficiency. These are generally expressed as a percentage of annual electric load, often increasing by year. Exelon's utilities comply with these various requirements through purchasing qualifying renewables, implementing efficiency programs, acquiring sufficient credits (e.g., RECs), paying an alternative compliance payment, and/or a combination of these compliance alternatives. The Utility Registrants are permitted to recover from retail customers the costs of complying with their state RPS requirements, including the procurement of RECs or other alternative energy resources. New York and Illinois adopted standards targeted at preserving the zero-carbon attributes of certain Exelon’s nuclear-powered generating facilities. Generation owns multiple facilities participating in these programs within both states. Other states in which Generation and our utilities operate are considering similar programs.

~~See Note 3 — Regulatory Matters of the Combined Notes to~~ Consolidated Financial ~~Statements for additional information on renewable portfolio standards.~~Statements.

Table of Contents

Information about our Executive Officers ~~of the Registrants~~ as of February ~~9, 2018~~14, 2023

Exelon

Name

Age

Position

~~Position~~

Period

~~Crane, Christopher M.~~Butler, Calvin G. Jr.

5953

~~Chief Executive Officer, Exelon~~

~~2012 - Present~~

~~Chairman, ComEd, PECO & BGE~~

~~2012 - Present~~

~~Chairman, PHI~~

~~2016 - Present~~

~~President, Exelon~~

~~2008 - Present~~

~~President, Generation~~

~~2008 - 2013~~

~~Cornew, Kenneth W.~~

~~Senior Executive Vice President and Chief Commercial Officer, Exelon~~

~~2013 - Present~~

~~President and CEO, Generation~~

~~2013 - Present~~

~~Executive Vice President and Chief Commercial Officer, Exelon~~

~~2012 - 2013~~

President and Chief Executive Officer, ~~Constellation~~Exelon

~~2012~~2022 - ~~2013~~Present

Chief Operating Officer, Exelon

2021 - 2022

~~O’Brien, Denis P.~~

Senior Executive Vice President, ~~Exelon;~~ Exelon

2019 - 2022

Chief Executive Officer, Exelon Utilities

~~2012~~2019 - ~~Present~~2022

~~Vice Chairman, ComEd, PECO & BGE~~

~~2012 - Present~~

~~Vice Chairman, PHI~~

~~2016 - Present~~

~~Pramaggiore, Anne R.~~

~~Chief Executive Officer, ComEd~~

~~2012 - Present~~

~~President, ComEd~~

~~2009 - Present~~

~~Adams, Craig L.~~

~~President and Chief Executive Officer, PECO~~

~~2012 - Present~~

~~Butler, Calvin G.~~

Chief Executive Officer, BGE

2014 - ~~Present~~

~~Senior Vice President, Regulatory and External Affairs, BGE~~

~~2013 - 2014~~

~~Senior Vice President, Corporate Affairs, Exelon~~

~~2011 - 2013~~

~~David M. Velazquez~~

~~President and Chief Executive Officer, PHI~~

~~2016 - Present~~

~~President and Chief Executive Officer, Pepco, DPL & ACE~~

~~2009 - Present~~

~~Executive Vice President, Pepco Holdings, Inc.~~

~~2009 - 2016~~

~~Von Hoene Jr., William A.~~

~~Senior Executive Vice President and Chief Strategy Officer, Exelon~~

~~2012 - Present~~

~~Thayer, Jonathan W.~~

~~Senior Executive Vice President and Chief Financial Officer, Exelon~~

~~2012 - Present~~

~~Aliabadi, Paymon~~

~~Executive Vice President and Chief Risk Officer, Exelon~~

~~2013 - Present~~

~~Managing Director, Gleam Capital Management~~

~~2012 - 2013~~

~~DesParte, Duane M.~~

~~Senior Vice President and Corporate Controller, Exelon~~

~~2008 - Present~~

~~Generation~~

2019

~~Name~~

~~Age~~

~~Position~~

~~Period~~

~~Cornew, Kenneth W.~~

~~Senior Executive Vice President and Chief Commercial Officer, Exelon~~

~~2013 - Present~~

~~President and CEO, Generation~~

~~2013 - Present~~

~~Executive Vice President and Chief Commercial Officer, Exelon~~

~~2012 - 2013~~

~~President and Chief Executive Officer, Constellation~~

~~2012 - 2013~~

~~Pacilio, Michael J.~~

~~Executive Vice President and Chief Operating Officer, Generation~~

~~2015 - Present~~

~~President, Exelon Nuclear; Senior Vice President~~

~~2010 - 2015~~

~~and Chief Nuclear Officer, Generation~~

~~Hanson, Bryan C~~

~~President and Chief Nuclear Officer, Exelon Nuclear; Senior Vice President, Generation~~

~~2015 - Present~~

~~Nigro, Joseph~~

~~Executive Vice President, Exelon; Chief Executive Officer, Constellation~~

~~2013 - Present~~

~~Senior Vice President, Portfolio Management and Strategy~~

~~2012 - 2013~~

~~DeGregorio, Ronald~~

~~Senior Vice President, Generation; President, Exelon Power~~

~~2012 - Present~~

~~Wright, Bryan P.~~

~~Senior Vice President and Chief Financial Officer, Generation~~

~~2013 - Present~~

~~Senior Vice President, Corporate Finance, Exelon~~

~~2012 - 2013~~

~~Bauer, Matthew N.~~

~~Vice President and Controller, Generation~~

~~2016 - Present~~

~~Vice President and Controller, BGE~~

~~2014 - 2016~~

~~Vice President of Power Finance, Exelon Power~~

~~2012 - 2014~~

~~ComEd~~



~~Name~~	~~Age~~	~~Position~~	~~Period~~
~~Pramaggiore, Anne R.~~	59	~~Chief Executive Officer, ComEd~~	~~2012 - Present~~
		~~President, ComEd~~	~~2009 - Present~~

~~Donnelly, Terence R.~~	57	~~Executive Vice President and Chief Operating Officer, ComEd~~	~~2012 - Present~~

~~Trpik Jr., Joseph R.~~	48	~~Senior Vice President, Chief Financial Officer and Treasurer, ComEd~~	~~2009 - Present~~

~~Jensen, Val~~	62	~~Senior Vice President, Customer Operations, ComEd~~	~~2012 - Present~~

~~Gomez, Veronica~~	48	~~Senior Vice President, Regulatory and Energy Policy and General Counsel, ComEd~~	~~2017 - Present~~
		~~Vice President and Deputy General Counsel, Litigation, Exelon~~	~~2012 - 2017~~

~~Marquez Jr., Fidel~~	56	~~Senior Vice President, Governmental & External Affairs, Exelon~~	~~2012 - Present~~

~~McGuire, Timothy M.~~	59	~~Senior Vice President, Distribution Operations, ComEd~~	~~2016 - Present~~
		~~Vice President, Transmission and Substations, ComEd~~	~~2010 - 2016~~

~~Kozel, Gerald J.~~	45	~~Vice President, Controller, ComEd~~	~~2013 - Present~~
		~~Assistant Corporate Controller, Exelon~~	~~2012 - 2013~~

~~PECO~~



~~Name~~	~~Age~~	~~Position~~	~~Period~~
~~Adams, Craig L.~~	65	~~President and Chief Executive Officer, PECO~~	~~2012 - Present~~

~~Barnett, Phillip S.~~	54	~~Senior Vice President and Chief Financial Officer, PECO~~	~~2007 - Present~~
		~~Treasurer, PECO~~	~~2012 - Present~~

~~Innocenzo, Michael A.~~	52	~~Senior Vice President and Chief Operations Officer, PECO~~	~~2012 - Present~~

~~Murphy, Elizabeth A.~~	58	~~Senior Vice President, Governmental & External Affairs, PECO~~	~~2016 - Present~~
		~~Vice President, Governmental & External Affairs, PECO~~	~~2012 - 2016~~

~~Webster Jr., Richard G.~~	56	~~Vice President, Regulatory Policy and Strategy, PECO~~	~~2012 - Present~~

~~Jiruska, Frank J.~~	57	~~Vice President, Customer Operations, PECO~~	~~2013 - Present~~

~~Diaz Jr., Romulo L.~~	71	~~Vice President and General Counsel, PECO~~	~~2012 - Present~~

~~Bailey, Scott A.~~	41	~~Vice President and Controller, PECO~~	~~2012 - Present~~

~~BGE~~



~~Name~~	~~Age~~	~~Position~~	~~Period~~
~~Butler, Calvin G.~~	48	~~Chief Executive Officer, BGE~~	~~2014 - Present~~
		~~Senior Vice President, Regulatory and External Affairs, BGE~~	~~2013 - 2014~~
		~~Senior Vice President, Corporate Affairs, Exelon~~	~~2011 - 2013~~

~~Woerner, Stephen J.~~	50	~~President, BGE~~	~~2014 - Present~~
		~~Chief Operating Officer, BGE~~	~~2012 - Present~~
		~~Senior Vice President, BGE~~	~~2009 - 2014~~

~~Vahos, David M.~~	45	~~Senior Vice President, Chief Financial Officer and Treasurer, BGE~~	~~2016 - Present~~
		~~Vice President, Chief Financial Officer and Treasurer, BGE~~	~~2014 - 2016~~
		~~Vice President and Controller, BGE~~	~~2012 - 2014~~

~~Núñez, Alexander G.~~	46	~~Senior Vice President, Regulatory and External Affairs, BGE~~	~~2016 - Present~~
		~~Vice President, Governmental & External Affairs, BGE~~	~~2013 - 2016~~
		~~Director, State Affairs, BGE~~	~~2012 - 2013~~

~~Case, Mark D.~~	56	~~Vice President, Regulatory Policy and Strategy, BGE~~	~~2012 - Present~~

~~Biagiotti, Robert D.~~	48	~~Vice President, Customer Operations, BGE~~	~~2015 - Present~~
		~~Vice President, Gas Distribution, BGE~~	~~2011 - 2015~~

~~Gahagan, Daniel P.~~	64	~~Vice President and General Counsel, BGE~~	~~2007 - Present~~

~~Andrew W. Holmes~~	49	~~Vice President and Controller, BGE~~	~~2016 - Present~~
		~~Director, Generation Accounting, Exelon~~	~~2013 - 2016~~
		~~Director, Derivatives and Technical Accounting, Exelon~~	~~2008 - 2013~~

~~PHI, Pepco, DPL and ACE~~

~~Name~~Jones, Jeanne

~~Age~~43

~~Position~~

Executive Vice President and Chief Financial Officer, Exelon

~~Period~~

2022 - Present

~~Velazquez,~~

Senior Vice President, Corporate Finance, Exelon

2021 - 2022

Senior Vice President and Chief Financial Officer, ComEd

2018 - 2021

Glockner, David M.

5862

Executive Vice President, Compliance, Audit and Risk, Exelon

2020 - Present

Chief Compliance Officer, Citadel LLC

2017 - 2020

Littleton, Gayle E.

Executive Vice President, General Counsel, Exelon

2020 - Present

Partner, Jenner & Block LLP

2015 - 2020

Quiniones, Gil

Chief Executive Officer, ComEd

2021 - Present

President and Chief Executive Officer, New York Power Authority

2011 - 2021

Innocenzo, Michael A.

President and Chief Executive Officer, PECO

2018 - Present

Khouzami, Carim V.

President, BGE

2021 - Present

Chief Executive Officer, BGE

2019 - Present

Senior Vice President & COO, Exelon Utilities

2018 - 2019

Anthony, J. Tyler

President and Chief Executive Officer, PHI, Pepco, DPL, and ACE

~~2016~~2021 - Present

~~Executive Vice President, Pepco Holdings, Inc.~~

~~2009-2016~~

~~President and Chief Executive Officer, Pepco, DPL & ACE~~

~~2009 - Present~~

~~Anthony, J. Tyler~~

Senior Vice President and Chief Operating Officer, PHI, Pepco, DPL, &and ACE

2016 - ~~Present~~2021

Trpik, Joseph R.

Senior Vice President ~~Distribution~~and Corporate Controller, Exelon

2022 - Present

Interim Senior Vice President & CFO, ComEd

2021 - 2022

Senior Vice President & CFO, Exelon Utilities

2018 - 2021

Table of Contents

ComEd

Name

Age

Position

Period

Quiniones, Gil

Chief Executive Officer, ComEd

2021 - Present

President and Chief Executive Officer, New York Power Authority

2011 - 2021

Donnelly, Terence R.

President and Chief Operating Officer, ComEd

2018 - Present

Graham, Elisabeth J.

Senior Vice President, Chief Financial Officer & Treasurer, ComEd

2022 - Present

Treasurer, Exelon

2018 - 2022

Rippie, E. Glenn

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

Senior Vice President, Customer Operations, ComEd

~~2010~~2021 - ~~2016~~Present

~~Kinzel, Donna~~

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

Senior Vice President, Governmental, Regulatory and External Affairs, ComEd

2022 - Present

Vice President, External Affairs, Nicor Gas

2013 - 2022

Table of Contents

PECO

Name

Age

Position

Period

Innocenzo, Michael A.

President and Chief Executive Officer, PECO

2018 - Present

Levine, Nicole

Senior Vice President and Chief Operations Officer, PECO

2022 - Present

Vice President, Electrical Operations, PECO

2018 - 2022

Humphrey, Marissa

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.

Senior Vice President, Governmental, Regulatory and External Affairs, PECO

2016 - Present

Williamson, Olufunmilayo

Senior Vice President, Customer Operations, PECO

2021 - Present

Senior Vice President, Chief Commercial Risk Officer, Exelon

2017 - 2020

Gay, Anthony

Vice President and General Counsel, PECO

2019 - Present

Vice President, Governmental and External Affairs, PECO

2016 - 2019

Table of Contents

BGE

Name

Age

Position

Period

Khouzami, Carim V.

President, BGE

2021 - Present

Chief Executive Officer, BGE

2019 - Present

Senior Vice President & COO, Exelon Utilities

2018 - 2019

Dickens, Derrick

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.

Senior Vice President, Chief Financial Officer and Treasurer, BGE

2016 - Present

Núñez, Alexander G.

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

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

Vice President and General Counsel, BGE

2021 - Present

Associate General Counsel, BGE

2019 - 2021

Assistant General Counsel, Exelon

2017 - 2019

Table of Contents

PHI, Pepco, DPL, and ACE

Name

Age

Position

Period

Anthony, J. Tyler

5058

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

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.

Senior Vice President, Chief Financial Officer and Treasurer, PHI, Pepco, DPL, &and ACE

~~2016~~2018 - Present

~~Vice President, Treasurer and Chief Risk Officer, Pepco Holdings~~

~~2012 - 2016~~

~~Bonney, Paul R.~~

~~Senior Vice President, Legal and Regulatory Strategy, PHI, Pepco, DPL & ACE~~

~~2016 - Present~~

Oddoye, Rodney

~~Senior Vice President and General Counsel, Constellation~~

~~2012 - 2016~~

~~Lavinson, Melissa A.~~

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 - ~~Present~~2020

~~Vice President, Federal Affairs and Policy, and Chief Sustainability Officer, PG&E Corporation~~

~~2015 - 2018~~

~~Vice President, Federal Affairs, PG&E Corporation~~

~~2012 - 2015~~

Bancroft, Anne

~~Stark, Wendy E.~~

Vice President and General Counsel, PHI, Pepco, DPL, &and ACE

~~2016~~2021 - Present

~~Deputy~~Associate General Counsel, ~~Pepco Holdings, Inc.~~Exelon

~~2012~~2017 - ~~Present~~2021

~~McGowan, Kevin M.~~

~~Vice President, Regulatory Policy and Strategy, PHI, Pepco, DPL & ACE~~

~~2016 - Present~~

~~Vice President, Regulatory Affairs, Pepco Holdings, Inc.~~

~~2012 - 2016~~

~~Aiken, Robert M.~~

~~Vice President and Controller, PHI, Pepco, DPL & ACE~~

~~2016 - Present~~

~~Vice President and Controller, Generation~~

~~2012 - 2016~~

Bell-Izzard, Morlon

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


ITEM 1A.			RISK FACTORS

Each of the Registrants operates in a complex market and regulatory environment that ~~poses~~involves significant risks, many of which are beyond that Registrant’s direct control. ~~Management of each Registrant regularly meets with the Chief Risk Officer and the Registrant's Risk Management Committee (RMC),~~Such risks, which comprises officers of the Registrant, to identify and evaluate the most significant risks of the Registrant's business and the appropriate steps to manage and mitigate those risks. The Chief Risk Officer and senior executives of the Registrants discuss those risks with the Finance and Risk Committee and Audit Committee of the Exelon Board of Directors and the ComEd, PECO, BGE and PHI boards of directors. In addition, the Generation Oversight Committee of the Exelon Board of Directors evaluates risks related to the generation business. The risk factors discussed below could ~~adversely~~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 ~~financial positions~~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 ~~market prices~~laws and regulations that govern:

•utility regulatory business models,

•environmental and climate policy, and

•tax policy.

Table of Contents

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 ~~publicly traded securities. Each~~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 ~~Registrants has disclosed~~separation primarilyinclude:

•challenges to achieving the ~~known material risks that affect its business at this time. However, there~~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 ~~by a Registrant~~ to be material that could ~~adversely~~negatively affect ~~its performance or~~the Registrants' consolidated financial ~~condition~~statements in the future.

Exelon's results of operations, cash flows and financial position are affected to a significant degree by: (1) Generation’s position as a predominantly nuclear generator selling power into competitive energy markets with a concentration in select regions and (2) the role of the Utility Registrants as operators of electric transmission and distribution systems in six of the largest metropolitan areas in the United States. Factors that affect the results of operations, cash flows or financial positions of the Registrants fall primarily under the following categories, all of which are discussed in further detail below:

~~Market and Financial Factors.~~ Exelon’s and Generation’s results of operations are affected by price fluctuations in the energy markets. Power prices are a function of supply and demand, which in turn are driven by factors such as (1) the price of fuels, in particular the price of natural gas, which affects the prices that Generation can obtain for the output of its power plants, (2) the presence of other generation resources in the markets in which Generation’s output is sold, (3) the demand for electricity in the markets where the Registrants conduct their business, (4) the impacts of on-going competition in the retail channel and (5) emerging technologies.

~~Regulatory and Legislative Factors.~~ The regulatory and legislative factors that affect the Registrants include changes to the laws and regulations that govern competitive markets and utility cost recovery, tax policy, zero emission credit programs and environmental policy. In particular, Exelon’s and Generation’s financial performance could be affected by changes in the design of competitive wholesale power markets or Generation’s ability to sell power in those markets. In addition, potential regulation and legislation, including regulation or legislation regarding climate change and renewable portfolio standards (RPS), could have significant effects on the Registrants. Also, returns for the Utility Registrants are influenced significantly by state regulation and regulatory proceedings.

~~Operational Factors.~~ The Registrants’ operational performance is subject to those factors inherent in running the nation’s largest fleet of nuclear power reactors and large electric and gas distribution systems. The safe, secure and effective operation of the nuclear facilities and the ability to effectively manage the associated decommissioning obligations as well as the ability to maintain the availability, reliability, safety and security of its energy delivery systems are fundamental to Exelon’s ability to achieve value-added growth for customers, communities and shareholders. Additionally, the operating costs of the Registrants and the opinions of their customers, regulators and shareholders are affected by those companies’ ability to maintain the reliability, safety and efficiency of their energy delivery systems.

Risks Related to ~~the PHI Merger.Exelon is subject to additional risks related to the merger with PHI, which closed on March 23, 2016.~~

~~A discussion of each of these risk categories and other risk factors is included below.~~

Market and Financial Factors

~~Generation is exposed to depressed prices in the wholesale and retail power markets, which could negatively affect its results of operations, cash flows or financial position (Exelon and Generation).~~

Generation is exposed to commodity price risk for the unhedged portion of its electricity generation supply portfolio. Generation’s earnings and cash flows are therefore exposed to variability of spot and forward market prices in the markets in which it operates.

~~Price of Fuels~~

The spot market price of electricity for each hour is generally determined by the marginal cost of supplying the next unit of electricity to the market during that hour. Thus, the market price of power is affected by the market price of the marginal fuel used to generate the electricity unit. Often, the next unit of electricity will be supplied from generating stations fueled by fossil fuels. Consequently, changes in the market price of fossil fuels often result in comparable changes to the market price of power. For example, the use of technologies to recover natural gas from shale deposits has increased natural gas supply and reserves, placing downward pressure on natural gas prices and, therefore, on power prices. The continued addition of supply from new alternative generation resources, such as wind and solar, whether mandated through RPS or otherwise subsidized or encouraged through climate legislation or regulation, could displace a higher marginal cost plant, further reducing power prices. In addition, further delay or elimination of EPA air quality regulations could prolong the duration for which the cost of pollution from fossil fuel generation is not factored into market prices.

~~Demand and Supply~~

The market price for electricity is also affected by changes in the demand for electricity and the available supply of electricity. Unfavorable economic conditions, milder than normal weather, and the growth of energy efficiency and demand response programs could each depress demand. The result is that higher-cost generating resources do not run as frequently, putting downward pressure on electricity market prices. The tepid economic environment in recent years and growing energy efficiency and demand response initiatives have limited the demand for electricity in Generation’s markets. In addition, in some markets, the supply of electricity through wind or solar generation, when combined with other base-load generation such as nuclear, could often exceed demand during some hours of the day, resulting in loss of revenue for base-load generating plants such as Exelon's nuclear plants. Increased supply in excess of demand is furthered by the continuation of RPS mandates and subsidies for renewable energy.

~~Retail Competition~~

Generation’s retail operations compete for customers in a competitive environment, which affects the margins that Generation can earn and the volumes that it is able to serve. In periods of sustained low natural gas and power prices and low market volatility, retail competitors can aggressively pursue market share because the barriers to entry can be low and wholesale generators (including Generation) use their retail operations to hedge generation output. Increased or more aggressive competition could adversely affect overall gross margins and profitability in Generation’s retail operations.

~~Sustained low market prices or depressed demand and over-supply could adversely affect Exelon’s and Generation’s results of operations, cash flows or financial positions and such impacts could be~~

emphasized given Generation’s concentration of base-load electric generating capacity within primarily two geographic market regions, namely the Midwest and the Mid-Atlantic. These impacts could adversely affect Exelon’s and Generation’s ability to fund regulated utility growth for the benefit of customers, reduce debt and provide attractive shareholder returns. In addition, such conditions may no longer support the continued operation of certain generating facilities, which could adversely affect Exelon's and Generation's result of operations through accelerated depreciation expense, impairment charges related to inventory that cannot be used at other nuclear units and cancellation of in-flight capital projects, accelerated amortization of plant specific nuclear fuel costs, severance costs, accelerated asset retirement obligation expense related to future decommissioning activities, and additional funding of decommissioning costs, which can be offset in whole or in part by reduced operating and maintenance expenses. A slow recovery in market conditions could result in a prolonged depression of or further decline in commodity prices, including low forward natural gas and power prices and low market volatility, which could also adversely affect Exelon’s and Generation’s results of operations, cash flows or financial positions. See Note 8 — Early Nuclear Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information.

~~In addition to price fluctuations, Generation is exposed to other risks in the power markets that are beyond its control and could negatively affect its results of operations (Exelon and Generation).~~

~~Credit Risk~~

In the bilateral markets, Generation is exposed to the risk that counterparties that owe Generation money, or are obligated to purchase energy or fuel from Generation, will not perform under their obligations for operational or financial reasons. In the event the counterparties to these arrangements fail to perform, Generation could be forced to purchase or sell energy or fuel in the wholesale markets at less favorable prices and incur additional losses, to the extent of amounts, if any, already paid to the counterparties. In the spot markets, Generation is exposed to risk as a result of default sharing mechanisms that exist within certain markets, primarily RTOs and ISOs, the purpose of which is to spread such risk across all market participants. Generation is also a party to agreements with entities in the energy sector that have experienced rating downgrades or other financial difficulties. In addition, Generation’s retail sales subject it to credit risk through competitive electricity and natural gas supply activities to serve commercial and industrial companies, governmental entities and residential customers. Retail credit risk results when customers default on their contractual obligations. This risk represents the loss that could be incurred due to the nonpayment of a customer’s account balance, as well as the loss from the resale of energy previously committed to serve the customer.

~~Market Designs~~

The wholesale markets vary from region to region with distinct rules, practices and procedures. Changes in these market rules, problems with rule implementation, or failure of any of these markets could adversely affect Generation’s business. In addition, a significant decrease in market participation could affect market liquidity and have a detrimental effect on market stability.

The Registrants are potentially affected by emerging technologies that could over time affect or transform the energy industry ~~including technologies related to energy generation, distribution and consumption~~ (All Registrants).

~~Some~~Advancements in power generation technology, including commercial and residential solar generation installations and commercial micro turbine installations, are improving the cost-effectiveness of ~~these technologies include, but are not limited~~customer self-supply of electricity. Improvements in energy storage technology, including batteries and fuel cells, could also better position customers to ~~further development or applications of technologies related to shale gas production, cost-effective renewable energy technologies,~~meet their around-the-clock electricity requirements. Improvements in energy efficiency ~~distributed~~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 ~~storage devices. Such~~consumption.

These developments could affect ~~the price of energy,~~ levels of customer-owned generation, customer expectations, and current business models and make portions of ~~our electric system power supply and~~the Utility Registrants' transmission and/or distribution facilities

~~obsolete~~ uneconomic prior to the end of their useful lives. ~~Such technologies~~Increasing pressure from both the private and public sectors to take actions to mitigate climate change could also ~~result in further declines in commodity prices or demand for delivered energy. Each~~push the speed and nature of ~~these~~this transition. These factors could ~~materially~~ affect the Registrants’ ~~results of operations, cash flows or~~consolidated financial ~~positions~~statements through, among other things, ~~reduced operating revenues,~~ increased operating and maintenance expenses, ~~and~~ increased capital expenditures, ~~as well as~~and potential asset impairment charges or accelerated depreciation ~~and decommissioning expenses~~ over shortened remaining asset useful lives.

Market performance and other factors could decrease the value of ~~NDT funds and~~ employee benefit plan assets and could increase the related employee benefit plan obligations, which then could require significant additional funding (All Registrants).

Disruptions in the capital markets and their actual or perceived effects on particular businesses and the greater economy could adversely affect the value of the investments held within ~~Generation’s NDTs and~~ Exelon’s employee benefit plan trusts. ~~The Registrants have significant obligations in these areas and Exelon and Generation hold substantial assets in these trusts to meet those obligations.~~ The asset values are subject to market fluctuations and will yield uncertain returns, which could fall below ~~the Registrants’~~Exelon's projected return rates. ~~A decline in the market value of the NDT fund investments could increase Generation’s funding requirements to decommission its nuclear plants.~~ A decline in the market value of the pension and OPEB plan assets ~~will~~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. If future increases in pension and other postretirement costs as a result of reduced plan assets or other factors cannot be recovered, or cannot be recovered in a timely manner, from the Utility Registrants' customers, the results of operations, cash flows or financial positionsSee Note 14 — Retirement Benefits of the ~~Utility~~Combined Notes to Consolidated Financial Statements for additional information.

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The Registrants could be negatively affected. Ultimately, if the Registrants are unable to manage the investments within the NDT funds and benefit plan assets, and are unable to manage the related benefit plan liabilities, their results of operations, cash flows or financial positions could be negatively impacted.

~~Unstable~~affected by unstable capital and credit markets and increased volatility in commodity markets could adversely affect the Registrants’ businesses in several ways, including the availability and cost of short-term funds for liquidity requirements, the Registrants’ ability to meet long-term commitments, Generation’s ability to hedge effectively its generation portfolio, and the competitiveness and liquidity of energy markets; each could negatively impact the Registrants’ results of operations, cash flows or financial positions (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 if internal funds are not available from the Registrants’ respective operations.~~needs. Disruptions in the capital and credit markets in the United States or abroad could ~~adversely~~negatively affect the Registrants’ ability to access the capital markets or draw on their respective bank revolving credit facilities. The ~~Registrants’ access to funds under their credit facilities depends on the ability of the banks that are parties to the facilities to meet their funding commitments. Those~~ 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 ~~from the Registrants and other borrowers~~ within a short period of time. The inability to access capital markets or credit facilities, and longer-term disruptions in the capital and credit markets ~~as a result~~because of uncertainty, changing or increased regulation, reduced alternatives, or failures of significant financial institutions could result in the deferral of discretionary capital

expenditures, ~~changes to Generation’s hedging strategy in order to reduce collateral posting requirements,~~ or require a reduction in dividend payments or other discretionary uses of cash.

In addition, the Registrants have exposure to worldwide financial markets, including Europe, Canada, and Asia. Disruptions in these markets could reduce or restrict the Registrants’ ability to secure sufficient liquidity or secure liquidity at reasonable terms. As of December 31, ~~2017,~~2022, approximately ~~19%~~23%, ~~or $1.8 billion, 19%~~10%, ~~or $1.8 billion,~~ and ~~17%, or $1.6 billion~~16% of the Registrants’ available credit facilities were with European, Canadian, and Asian banks, respectively. The credit facilities include $9.5 billion in aggregate total commitments of which $8.3 billion was available as of December 31, 2017. As of December 31, 2017, there were no borrowings under Generation's bilateral credit facilities.Additionally, higher interest rates may put pressure on the Registrants’ overall liquidity profile, financial health and impact financial results. See Note 1316 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the credit facilities.

The strength and depth of competition in energy markets depend heavily on active participation by multiple trading parties, which could be adversely affected by disruptions in the capital and credit markets and legislative and regulatory initiatives that could affect participants in commodities transactions. Reduced capital and liquidity and failures of significant institutions that participate in the energy markets could diminish the liquidity and competitiveness of energy markets that are important to the respective businesses of the Registrants. Perceived weaknesses in the competitive strength of the energy markets could lead to pressures for greater regulation of those markets or attempts to replace market structures with other mechanisms for the sale of power, including the requirement of long-term contracts, which could have a material adverse effect on Exelon’s and Generation’s results of operations, cash flows or financial positions.

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 ~~under~~that could affect its ~~agreements with counterparties~~liquidity and could experience higher borrowing costs (All Registrants).

Generation’s business is subject to credit quality standards that could require market participants to post collateral for their obligations. If Generation were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating) or otherwise fail to satisfy the credit standards of trading counterparties, it would be required under its hedging arrangements to provide collateral in the form of letters of credit or cash, which could have a material adverse effect upon its liquidity. The amount of collateral required to be provided by Generation at any point in time depends on a variety of factors, including (1) the notional amount of the applicable hedge, (2) the nature of counterparty and related agreements, and (3) changes in power or other commodity prices. In addition, if Generation were downgraded, it could experience higher borrowing costs as a result of the downgrade. Generation could experience a downgrade in its ratings if any of the credit rating agencies concludes that the level of business or financial risk and overall creditworthiness of the power generation industry in general, or Generation in particular, has deteriorated. Changes in ratings methodologies by the credit rating agencies could also have a negative impact on the ratings of Generation. Generation has project-specific financing arrangements and must meet the requirements of various agreements relating to those financings. Failure to meet those arrangements could give rise to a project-specific financing default which, if not cured or waived, could result in the specific project being required to repay the associated debt or other borrowings earlier than otherwise anticipated, and if such repayment were not made, the lenders or security holders would generally have broad remedies, including rights to foreclose against the project assets and related collateral or to force the Exelon subsidiaries in the project-specific financings to enter into bankruptcy proceedings.

The 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. ~~Given the relationship to forward market prices, contract collateral requirements can be volatile. In addition, if~~If the Utility Registrants were downgraded, they could experience higher borrowing costs as a result of the downgrade.

A Utility Registrant could experience a downgrade in its ratings if any of the credit rating agencies concludes that the level of business or financial risk and overall creditworthiness of the utility industry in general, or a Utility Registrant in particular, has deteriorated. A Utility Registrant could experience a downgrade if its current regulatory environment becomes less predictable by materially lowering returns for the Utility Registrant or adopting other measures to limit utility rates. Additionally, the ratings for a Utility Registrant could be downgraded if its financial results are weakened from current levels due to weaker operating performance or due to a failure to properly manage its capital structure. In addition, changes in ratings methodologies by the agencies could also have aan adverse negative impact on the ratings of the Utility Registrants.

The Utility Registrants conduct their respective businesses and operate under governance models and other arrangements and procedures intended to assure that the Utility Registrants are treated as separate, independent companies, distinct from Exelon and other Exelon subsidiaries in order to isolate the Utility Registrants from Exelon and other Exelon subsidiaries in the event of financial difficulty at Exelon or another Exelon subsidiary. These measures (commonly referred to as “ring-fencing”) could help avoid or limit a downgrade in the credit ratings of the Utility Registrants in the event of a reduction in the credit rating of Exelon. Despite these ring-fencing measures, the credit ratings of the Utility Registrants could remain linked, to some degree, to the credit ratings of Exelon. Consequently, a reduction in the credit rating of Exelon could result in a reduction of the credit rating of some or all of the Utility Registrants. A reduction in the credit rating of a Utility Registrant could have a material adverse effect on the Utility Registrant.

See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Liquidity and Capital Resources — Credit Matters and Cash Requirements — ~~Market Conditions and~~ Security Ratings for ~~further~~additional information regarding the potential impacts of credit downgrades on the Registrants’ cash flows.

~~Generation’s financial performance could be negatively affected by price volatility, availability and other risk factors associated with the procurement~~

Table of ~~nuclear and fossil fuel (Exelon and Generation).~~Contents

Generation depends on nuclear fuel and fossil fuels to operate most of its generating facilities. Nuclear fuel is obtained predominantly through long-term uranium supply contracts, contracted conversion services, contracted enrichment services, or a combination thereof, and contracted fuel fabrication services. Natural gas and oil are procured for generating plants through annual, short-term and spot-market purchases. The supply markets for nuclear fuel, natural gas and oil are subject to price fluctuations, availability restrictions and counterparty default that could negatively affect the results of operations, cash flows or financial position for Generation.

~~Generation’s risk management policies cannot fully eliminate the risk associated with its commodity trading activities (Exelon and Generation).~~

Generation’s asset-based power position as well as its power marketing, fuel procurement and other commodity trading activities expose Generation to risks of commodity price movements. Generation buys and sells energy and other products and enters into financial contracts to manage risk and hedge various positions in Generation’s power generation portfolio. Generation is exposed to volatility in financial results for unhedged positions as well as the risk of ineffective hedges. Generation attempts to manage this exposure through enforcement of established risk limits and risk management procedures. These risk limits and risk management procedures may not work as planned and cannot eliminate all risks associated with these activities. Even when its policies and procedures are followed, and decisions are made based on projections and estimates of future performance, results of operations could be diminished if the judgments and assumptions underlying those decisions prove to be incorrect. Factors, such as future prices and demand for power and other energy-related commodities, become more difficult to predict and the calculations become less reliable the further into the future estimates are made. As a result, Generation cannot predict the impact that its commodity trading activities and risk management decisions could have on its business, results of operations, cash flows or financial position.

~~Financial performance and load requirements could be adversely affected if Generation is unable to effectively manage its power portfolio (Exelon and Generation).~~

A significant portion of Generation’s power portfolio is used to provide power under procurement contracts with the Utility Registrants and other customers. To the extent portions of the power portfolio are not needed for that purpose, Generation’s output is sold in the wholesale power markets. To the extent its power portfolio is not sufficient to meet the requirements of its customers under the related agreements, Generation must purchase power in the wholesale power markets. Generation’s financial results could be negatively affected if it is unable to cost-effectively meet the load requirements of its customers, manage its power portfolio or effectively address the changes in the wholesale power markets.

Challenges to tax positions taken by the Registrants as well as tax law changes and the inherent difficulty in quantifying potential tax effects of business decisions, could impact the Registrants’ results of operations, cash flows or financial positions. (All Registrants).

~~Corporate Tax Reform~~

~~On December 22, 2017, President Trump signed into law the TCJA. See Note 14 - Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.~~

While the Registrants’ current tax accounting and future expectations are based on management’s present understanding of the provisions under the TCJA, further interpretive guidance of the TCJA’s provisions could result in further adjustments that could have a material impact to the Registrants’ future results of operations, cash flows or financial positions.

In addition, as allowed under SEC Staff Accounting Bulletin No. 118 (SAB 118), the Registrants have recorded provisional income tax amounts as of December 31, 2017 for changes pursuant to the TCJA related to depreciation for which the impacts could not be finalized upon issuance of the Registrants’ financial statements, but reasonable estimates could be determined. However, the provisional amounts may change as the Registrants finalize their analysis and computations and such changes could be material to the Registrants’ future results of operations, cash flows or financial positions.

The ~~Utility Registrants have made their best estimate regarding the probability and timing~~impacts of settlements of net regulatory liabilities established pursuant to the TCJA. However, the amount and timing of the settlements may change based on decisions and actions by the rate regulators, which could

~~have a material impact on the Utility Registrants’ future results of operations, cash flows~~significant economic downturns or ~~financial positions.~~

~~Tax reserves~~

The Registrants are required to make judgments in order to estimate their obligations to taxing authorities. These tax obligations include income, real estate, sales and use and employment-related taxes and ongoing appeal issues related to these tax matters. These judgments include reserves established for potential adverse outcomes regarding tax positions that have been taken that could be subject to challenge by the tax authorities. See Note 1 — Significant Accounting Policies and Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.

~~Increases in customer rates, including~~ increases in ~~the cost of purchased power and increases in natural gas prices for the Utility Registrants, and the impact of economic downturns could lead to greater expense for uncollectible~~ customer ~~balances. Additionally, increased~~ rates, could lead to decreased volumes ~~delivered. Both of these factors could decrease Generation’s~~delivered and ~~the Utility Registrants' results from operations, cash flows or financial positions~~increased expense for uncollectible customer balances (All Registrants).

The impacts of significant economic downturns on the Utility Registrants' ~~customers, such as unemployment for residential customers and less demand for products and services provided by commercial and industrial~~ customers and the related regulatory limitations on residential service terminations for the Utility Registrants, could result in an increase in the number of uncollectible customer ~~balances', which would negatively affect~~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' results of operations, cash flows or financial positions. Generation's customer-facing energy delivery activities face similar economic downturn risks, such as lower volumes sold and increased expense for uncollectible customer balances which could negatively affect Generation's results of operations, cash flows or financial position. Registrants that do not have decoupling mechanisms.

See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for ~~further discussion of~~additional information on the Registrants’ credit risk.

~~The Utility~~Public health crises, epidemics, or pandemics, such as COVID-19 could negatively impact the Registrants' ~~current procurement plans include purchasing power through contracted suppliers and~~results (All Registrants).

COVID-19 disrupted economic activity in the ~~spot market. ComEd’s, PECO’s~~Registrants’ respective markets and ACE's costs of purchased power are charged to customers without a return or profit component. BGE's, Pepco's and DPL's SOS rates charged to customers recover their wholesale power supply costs and include a return component. For PECO and DPL, purchased natural gas costs are charged to customers with no return or profit component. For BGE, purchased natural gas costs are charged to customers using a MBR mechanism that compares the actual cost of gas to a market index. The difference between the actual cost and the market index is shared equally between shareholders and customers. Purchased power and natural gas prices fluctuate based on their relevant supply and demand. Significantly higher rates related to purchased power and natural gas could result in declines in customer usage, lower revenues and potentially additional uncollectible accounts expense for the Utility Registrants. In addition, any challenges by the regulators or the Utility Registrants as to the recoverability of these costs could have a material adverse effect onnegatively affected the Registrants’ results of operations ~~cash flows~~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 ~~financial positions. Also,~~other local or global health issue could adversely affect our vendors, competitors or customers and customer demand as well as the ~~Utility Registrants' cash flows~~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 ~~adversely~~negatively affected by ~~differences between~~ the ~~time period when electricity and natural gas are purchased and the ultimate recovery from customers.~~

~~The effects~~impacts of weather ~~could impact the Registrants’ results of operations, cash flows or financial positions~~ (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 ~~and ACE.~~Delaware. Due to revenue decoupling,

operating revenues from electric distribution at ComEd, BGE, Pepco, ~~and~~ DPL Maryland, ~~recognize revenues at MDPSC~~ and ~~DCPSC-approved levels per customer, regardless of what actual distribution volumes are for a billing period, and~~ACE are not affected by actual weather with the exception of major storms. Pursuant to the Future Energy Jobs Act (FEJA), beginning in 2017, customer rates for ComEd are adjusted to eliminate the favorable and unfavorable impacts of weather and customer usage patterns on distribution revenue.abnormal weather.

Extreme weather conditions or damage resulting from storms could stress the Utility Registrants' transmission and distribution systems, communication systems, and technology, resulting in increased maintenance and capital costs and limiting each company’s ability to meet peak customer demand. ~~These extreme conditions could have detrimental effects on the Utility Registrants' results of operations, cash flows or financial positions.~~ First and third quarter financial results, in particular, are substantially dependent on weather conditions, and could make period comparisons less relevant.

~~Generation’s operations are also affected by weather, which affects demand for electricity~~Climate change projections suggest increases to summer temperature and humidity trends, as well as ~~operating conditions. To~~more erratic precipitation and storm patterns over the ~~extent that weather is warmer~~long-term in the ~~summer or colder~~areas where the Utility Registrants have transmission and distribution assets. The frequency in ~~the winter than assumed, Generation could require greater resources to meet its contractual commitments. Extreme~~which weather conditions ~~or storms~~emerge outside the current expected climate norms could ~~affect the availability of generation and its transmission, limiting Generation’s ability~~contribute to ~~source or send power to where it is sold. In addition, drought-like conditions limiting water usage could impact Generation’s ability to run certain generating~~weather-related impacts discussed above.

Long-lived assets, at full capacity. These conditions, which cannot be accurately predicted, could have an adverse effect by causing Generation to seek additional capacity at a time when wholesale markets are tight or to seek to sell excess capacity at a time when markets are weak.

~~Certain long-lived assets~~goodwill, and other assets ~~recorded on the Registrants’ statements of financial position~~ could become impaired ~~which would result in write-offs of the impaired amounts~~ (All Registrants).

Long-lived assets represent the single largest asset class on the Registrants’ statements of financial position. Specifically, long-lived assets account for 64%, 51%, 70%, 79%, 84%, 77%, 82% and 79% of total assets for Exelon, Generation, ComEd, PECO, BGE, Pepco, DPL and ACE, respectively, as of December 31, 2017. In addition, Exelon, ComEd, and ~~Generation~~PHI have ~~significant balances related to unamortized energy contracts, as further disclosed in Note 10 — Intangible Assets of the Combined Notes to Consolidated Financial Statements.~~ 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 when evaluating long-lived assets~~considered.

ComEd and PHI perform an assessment for ~~potential impairment. An~~possible impairment of their goodwill at least annually or more frequently if an event occurs or circumstances change that would ~~require the Registrants to~~more likely than not reduce the carrying value of the long-lived asset to fair value through a non-cash charge to expense by the amount of the impairment, and such an impairment could have a material adverse impact on the Registrants’ results of operations, cash flows or financial positions.

As of December 31, 2017, Exelon's $6.7 billion carrying amount of goodwill primarily consists of $2.6 billion at ComEd relating to the acquisition of ComEd in 2000 upon the formation of Exelon and $4.0 billion at PHI primarily resulting from Exelon's acquisition of PHI in the first quarter of 2016. Under GAAP, goodwill remains at its recorded amount unless it is determined to be impaired, which is generally based upon an annual analysis that compares the implied fair value of the ~~goodwill to its~~

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reporting units below their carrying value. If an impairment occurs, the amount of the impaired goodwill will be written-off to expense, which will also reduce equity. The actual timing and amounts of any goodwill impairments will depend on many sensitive, interrelated and uncertain variables. Such an impairment would result in a non-cash charge to expense, which could have a material adverse impact on Exelon's, ComEd's, and PHI's results of operations.

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 ~~and ComEd’s~~goodwill.

An impairment would require the Registrants to reduce the carrying value of the long-lived asset or goodwill ~~which could be material.~~

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, ~~and~~ Note 67 — Property, Plant, and Equipment, Note 711 — ~~Impairment of Long-Lived Assets and Intangibles~~Asset Impairments, and Note 1012 — Intangible Assets of the Combined Notes to the Consolidated Financial Statements for additional ~~discussion~~information on long-lived asset impairments and goodwill impairments.

~~Exelon and its subsidiaries at times guarantee the performance of third parties, which~~The Registrants could ~~result in~~incur substantial costs in the event of non-performance by ~~such third parties. In addition,~~third-parties under indemnification agreements, or when the Registrants ~~could~~ have rights under agreements which obligate third parties to indemnify the Registrants for various obligations, and the Registrants could incur substantial costs in the event that the applicable Registrant is unable to enforce those agreements or the applicable third-party is otherwise unable to perform. The Registrants could also incur substantial costs in the event that third parties are entitled to indemnification related to environmental or other risks in connection with the acquisition and divestiture of assetsguaranteed their performance (All Registrants).

Some of the Registrants have issued guarantees of the performance of third parties, which obligate the Registrant or its subsidiaries to perform in the event that the third parties do not perform. In the event of non-performance by those third parties, a Registrant could incur substantial cost to fulfill its obligations under these guarantees. Such performance guarantees could have a material impact on the results of operations, cash flows or financial position of the Registrant. Some of the Registrants have issued indemnities to third parties regarding environmental or other matters in connection with purchases and sales of assets and a Registrant could incur substantial costs to fulfill its obligations under these indemnities and such costs could adversely affect a Registrant’s results of operations, cash flows or financial position.

~~Some of the~~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, which could adversely impact that Registrant’s results of operations, cash flows or financial position.~~obligations. Each of the Utility Registrants has transferred its former generation business to a third party and in each case the transferee ~~may have~~has agreed to assume certain obligations and to indemnify the applicable Utility Registrant for such obligations. In connection with the restructurings under which ComEd, PECO, and BGE transferred their generating assets to ~~Generation, Generation~~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 ~~may~~ have entered into agreements with third parties under which the third-party agreed to indemnify ComEd, PECO, or BGE for certain obligations related to their respective former generation businesses that have been assumed by ~~Generation~~Constellation as part of the restructuring. If the third-party, ~~Generation~~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, which could impact that Utility Registrant's results of operations, cash flows or financial position.~~claims. In addition, the Utility Registrants ~~may~~ have residual liability under certain laws in connection with their former generation facilities. ~~For example, under CERCLA, former owners of property may retain certain liability for environmental claims and remediation.~~

The Registrants have issued indemnities to third parties ~~to whom~~regarding environmental or other matters in connection with purchases and sales of assets, including several of the Utility Registrants ~~transferred~~in connection with Constellation's absorption of their former ~~generation facilities may~~generating assets. The Registrants could incur substantial costs to fulfill their obligations under these indemnities.

The Registrants have ~~agreed to indemnify~~issued guarantees of the ~~Utility Registrants for all or a portion~~

performance of ~~such liability but if such~~ third parties, ~~fail or are unable~~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 ~~the indemnity, the applicable Utility Registrant may be liable for certain remediation costs.~~these guarantees.

Risks Related to Legislative, Regulatory, and ~~Legislative~~Legal Factors

The ~~Registrants’ generation and energy delivery~~Registrants' businesses are highly regulated and electric and gas revenue and earnings could be ~~subject to~~negatively affected by legislative and/or regulatory ~~and legislative~~ actions that adversely affect their results of operations, cash flows or financial positions. Fundamental changes in regulation or legislation or violation of tariffs or market rules and anti-manipulation laws, could disrupt the Registrants’ business plans and adversely affect their operations, cash flows or financial results (All Registrants).

~~Substantially all~~Substantial aspects of the Registrants' businesses ~~of the Registrants~~ are subject to comprehensive Federal or state ~~regulation and legislation. Further, Exelon’s and Generation’s results of operations, cash flows~~ legislation and/or financial positions are significantly affected by Generation's sales and purchases of commodities at market-based rates, as opposed to cost-based or other similarly regulated rates, and Exelon’s and theregulation.

The Utility Registrants' ~~results of operations, cash flows or~~consolidated financial ~~positions~~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. Similarly, there is risk that financial market regulations could increase the Registrants’ compliance costs and limit their ability to engage in certain transactions. In the planning and management of operations, the Registrants must address the effects of regulation on their businesses and changes in the regulatory framework, including initiatives by Federal and state legislatures, RTOs, exchanges, ratemaking agencies and taxing authorities. Additionally, the Registrants need to be cognizant and understand rule changes or Registrant actions that could result in potential violation of tariffs, market rules and anti-manipulation laws.

Fundamental changes in regulations or ~~other~~ adverse legislative actions affecting the Registrants’ businesses would require changes in their business planning models and ~~operations and could negatively impact their respective results of operations, cash flows or financial positions.~~

State and federal regulatory and legislative developments related to emissions, climate change, tax reform, capacity market mitigation, energy price information, resilience, fuel diversity and RPS could also significantly affect Exelon’s and Generation’s results of operations, cash flows or financial positions. Various legislative and regulatory proposals to address climate change through GHG emission reductions, if enacted, could result in increased costs to entities that generate electricity through carbon-emitting fossil fuels, which could increase the market price at which all generators in a region, including Generation, could sell their output, thereby increasing the revenue Generation could realize from its low-carbon nuclear assets. Conversely, existing or new regulations intended to reduce GHG emissions could be rolled back, allowing fossil fueled facilities which were otherwise scheduled to retire to continue to operate if economical. This could result in decreases in market prices thereby reducing Generation’s revenues. However, national regulation or legislation addressing climate change through an RPS could also increase the pace of development of wind energy facilities in the Midwest, which could put downward pressure on wholesale market prices for electricity from Generation’s Midwest nuclear assets, partially offsetting any additional value Exelon and Generation might derive from Generation’s nuclear assets under a carbon constrained regulatory regime that might exist in the future. Similarly, final regulations under Section 111(d) of the Clean Air Act may not provide sufficient incentives for states to utilize carbon-free nuclear power as a means of meeting GHG reduction requirements, while continuing a policy of favoring renewable energy sources. Current state level climate change and renewable regulation is already providing incentives for regional wind development.operations. The Registrants cannot predict when or whether ~~any of these various~~ legislative ~~and~~or regulatory proposals could become law or what their effect ~~will~~would be on the Registrants.

~~Legislative and regulatory efforts in Illinois and New York to preserve the environmental attributes and reliability benefits~~Table of zero-emission nuclear-powered generating facilities through zero emission credit programs are subject to legal challenges and, if overturned, could negatively impact Exelon’s and Generation’s results of operations, cash flows or financial positions and result in the early retirement of certain of Generation’s nuclear plants.Contents

~~Generation could be negatively affected by possible Federal or state legislative or regulatory actions that could affect the scope and functioning of the wholesale markets (Exelon and Generation).~~

Federal and state legislative and regulatory bodies are facing pressures to address consumer concerns, or are themselves raising concerns, that energy prices in wholesale markets are too high or insufficient generation is being built because the competitive model is not working and, therefore, are considering some form of re-regulation or some other means of reducing wholesale market prices or subsidizing new generation. Generation is dependent on robust and competitive wholesale energy markets to achieve its business objectives.

Approximately 61% of Generation’s generating resources, which include directly owned assets and capacity obtained through long-term contracts, are located in the area encompassed by PJM. Generation’s future results of operations will depend on (1) FERC’s continued adherence to and support for, policies that favor the preservation of competitive wholesale power markets and recognize the value of zero-carbon electricity and resiliency and (2) the absence of material changes to market structures that would limit or otherwise negatively affect market competition. Generation could also be adversely affected by state laws, regulations or initiatives designed to reduce wholesale prices artificially below competitive levels or to subsidize existing or new generation.

FERC’s requirements for market-based rate authority, established in Order 697 and 816 and related subsequent orders, could pose a risk that Generation may no longer satisfy FERC’s tests for market-based rates. Since Order 697 became final in June 2007, Generation has obtained orders affirming Generation’s authority to sell at market-based rates and none denying that authority.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (the Act) was enacted in July 2010. The part of the Act that affects Exelon most significantly is Title VII, which is known as the Dodd-Frank Wall Street Transparency and Accountability Act (Dodd-Frank). Dodd-Frank requires a new regulatory regime for over-the-counter swaps (swaps), including mandatory clearing for certain categories of swaps, incentives to shift swap activity to exchange trading, margin and capital requirements, and other obligations designed to promote transparency. The primary aim of Dodd-Frank is to regulate the key intermediaries in the swaps market, which entities are swap dealers (SDs), major swap participants (MSPs), or certain other financial entities, but the law also applies to a lesser degree to end-users of swaps. The CFTC’s Dodd-Frank regulations generally preserved the ability of end users in the energy industry to hedge their risks using swaps without being subject to mandatory clearing, and many of the other substantive regulations that apply to SDs, MSPs, and other financial entities. Generation manages, and expects to be able to continue to manage, its commercial activity to ensure that it does not have to register as an SD or MSP or other type of covered financial entity.

There are some rulemaking proceedings that have not yet been finalized, in particular, proposed rules on position limits that would apply to both Exchange-traded futures contracts and economically-equivalent over-the-counter swaps. It is possible that those rules will be finalized by the end of 2018. Although the company would incur some costs associated with monitoring and compliance with such rules, it does not expect the rules to have a material impact on its business operations.

The Utility Registrants could also be subject to some Dodd-Frank requirements to the extent they were to enter into swaps. However, at this time, management of the Utility Registrants continue to expect that their companies will not be materially affected by Dodd-Frank.

Generation’s affiliation with the Utility Registrants, together with the presence of a substantial percentage of Generation’s physical asset base within the Utility Registrants' service territories, could increase Generation’s cost of doing business to the extent future complaints or challenges regarding the Utility Registrants' retail rates result in settlements or legislative or regulatory requirements funded in part by Generation (Exelon and Generation).

Generation has significant generating resources within the service areas of the Utility Registrants and makes significant sales to each of them. Those facts tend to cause Generation to be directly affected by developments in those markets. Government officials, legislators and advocacy groups are aware of Generation’s affiliation with the Utility Registrants and its sales to each of them. In periods of rising utility rates, particularly when driven by increased costs of energy production and supply, those officials and advocacy groups could question or challenge costs and transactions incurred by the Utility Registrants with Generation, irrespective of any previous regulatory processes or approvals underlying those transactions. These challenges could increase the time, complexity and cost of the associated regulatory proceedings, and the occurrence of such challenges could subject Generation to a level of scrutiny not faced by other unaffiliated competitors in those markets. In addition, government officials and legislators could seek ways to force Generation to contribute to efforts to mitigate potential or actual rate increases, through measures such as generation-based taxes and contributions to rate-relief packages.

~~The Registrants could incur substantial costs to fulfill their obligations related to environmental and other matters (All Registrants).~~

The businesses which the Registrants operate are subject to extensive environmental regulation and legislation by local, state and Federal authorities. These laws and regulations affect the manner in which the Registrants conduct their operations and make capital expenditures including how they handle air and water emissions and solid waste disposal. Violations of these emission and disposal requirements could subject the Registrants to enforcement actions, capital expenditures to bring existing facilities into compliance, additional operating costs for remediation and clean-up costs, civil penalties and exposure to third parties’ claims for alleged health or property damages or operating restrictions to achieve compliance. In addition, the Registrants are subject to liability under these laws for the remediation costs for environmental contamination of property now or formerly owned by the Registrants and of property contaminated by hazardous substances they generate. The Registrants have incurred and expect to incur significant costs related to environmental compliance, site remediation and clean-up. Remediation activities associated with MGP operations conducted by predecessor companies are one component of such costs. Also, the Registrants are currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and could be subject to additional proceedings in the future.

If application of Section 316(b) of the Clean Water Act, which establishes a national requirement for reducing the adverse impacts to aquatic organisms at existing generating stations, requires the retrofitting of cooling water intake structures at Salem or other Exelon power plants, this development could result in material costs of compliance. See Note 23 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.

Additionally, Generation is subject to exposure for asbestos-related personal injury liability alleged at certain current and formerly owned generation facilities. Future legislative action could require Generation to make a material contribution to a fund to settle lawsuits for alleged asbestos-related disease and exposure.

In some cases, a third-party who has acquired assets from a Registrant has assumed the liability the Registrant could otherwise have for environmental matters related to the transferred property. If the transferee is unable, or fails, to discharge the assumed liability, a regulatory authority or injured person

could attempt to hold the Registrant responsible, and the Registrant’s remedies against the transferee could be limited by the financial resources of the transferee. See Note 23 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.

Changes in the Utility Registrants' respective terms and conditions of service, including their respective rates, along with adoption of new rate structures and constructs, or establishment of new rate cases, are subject to regulatory approval proceedings and/or negotiated settlements that are at times contentious, lengthy, and subject to appeal, which lead to uncertainty as to the ultimate result, and which could introduce time delays in effectuating rate changes ~~(Exelon and the Utility~~(All Registrants).

The Utility Registrants are required to engage in regulatory approval proceedings as a part of the process of establishing the terms and rates for their respective ~~services.~~services, adoption of new rate structures and constructs or establishment of new rate cases. These proceedings typically involve multiple parties, including governmental bodies and officials, consumer advocacy groups, and various consumers of energy, who have differing concerns but who have the common objective of limiting rate increases or even reducing rates. ~~The proceedings generally have timelines that may not be limited by statute.~~ Decisions are subject to appeal, potentially leading to additional uncertainty associated with the approval proceedings. The potential duration of such proceedings creates a risk that rates ultimately approved by the applicable regulatory body may not be sufficient for a Utility Registrant to recover its costs by the time the rates become effective. Established rates are also subject to subsequent prudency reviews by state regulators, whereby various portions of rates could be adjusted, subject to refund or disallowed, including recovery mechanisms for costs associated with the procurement of electricity or gas, ~~bad debt,~~credit losses, MGP remediation, smart grid infrastructure, and energy efficiency and demand response programs.

In certain instances, the Utility Registrants could agree to negotiated settlements related to various rate matters, customer initiatives, or franchise agreements. These settlements are subject to regulatory approval.

The Utility Registrants cannot predict the ultimate outcomes of any settlements or the actions by Illinois, Pennsylvania, Maryland, the District of Columbia, Delaware, New Jersey or Federal regulators in establishing rates, including the extent, if any, to which certain costs such as significant capital projects will be recovered or what rates of return will be allowed. Nevertheless, the expectation is that the Utility Registrants will continue to be obligated to deliver electricity to customers in their respective service territories and will also retain significant default service obligations, referred to as POLR, DSP, SOS and BGS, to provide electricity and natural gas to certain groups of customers in their respective service areas who do not choose an alternative supplier. The ultimate outcome and timing of regulatory rate proceedings have a significant effect on the ability of the Utility Registrants ~~as applicable,~~ to recover their costs or earn an adequate ~~return and could have a material adverse effect on the Utility Registrants' results of operations, cash flows or financial positions.~~return. See Note 3 — Regulatory Matters of the Combined Notes to the Consolidated Financial Statements for ~~information regarding rate proceedings.~~

~~Federal or~~ additional state RPS and/or energy conservation legislation, along with energy conservation by customers, could negatively affect the results of operations, cash flows or financial positions of Generation and the Utility Registrants (All Registrants).

Changes to current state legislation or the development of Federal legislation that requires the use of renewable and alternate fuel sources, such as wind, solar, biomass and geothermal, could significantly impact Generation and the Utility Registrants, especially if timely cost recovery is not allowed for Utility Registrants. The impact could include increased costs for RECs and purchased power and increased rates for customers.

Federal and state legislation mandating the implementation of energy conservation programs that require the implementation of new technologies, such as smart meters and smart grid, have increased capital expenditures and could significantly impact the Utility Registrants if timely cost recovery is not allowed. Furthermore, regulated energy consumption reduction targets and declines in customer energy consumption resulting from the implementation of new energy conservation technologies could lead to a decline in the revenues of Exelon, Generation and the Utility Registrants. For additional information, see ITEM 1. BUSINESS — Environmental Regulation — Renewable and Alternative Energy Portfolio Standards.

The impact of not meeting the criteria of the FASB guidance for accounting for the effects of certain types of regulation could be material to Exelon and the Utility Registrants (Exelon and the Utility Registrants).

As of December 31, 2017, Exelon and the Utility Registrants have concluded that the operations of the Utility Registrants meet the criteria of the authoritative guidance for accounting for the effects of certain types of regulation. If it is concluded in a future period that a separable portion of their businesses no longer meets the criteria, Exelon, and the Utility Registrants would be required to eliminate the financial statement effects of regulation for that part of their business. That action would include the elimination of any or all regulatory assets and liabilities that had been recorded in their Consolidated Balance Sheets and the recognition of a one-time charge in their Consolidated Statements of Operations and Comprehensive Income. The impact of not meeting the criteria of the authoritative guidance could be material to the financial statements of Exelon and the Utility Registrants. The impacts and resolution of the above items could lead to an impairment of ComEd's or PHI’s goodwill, which could be significant and at least partially offset the gains at ComEd discussed above. A significant decrease in equity as a result of any changes could limit the ability of the Utility Registrants to pay dividends under Federal and state law and no longer meeting the regulatory accounting criteria could cause significant volatility in future results of operations. See Notes 1 — Significant Accounting Policies, 3 — Regulatory Matters and 10 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information regarding accounting for the effects of regulation, regulatory matters and ComEd’s and PHI's goodwill, respectively.

~~Exelon and Generation could incur material costs of compliance if Federal and/or state regulation or legislation is adopted to address climate change (Exelon and Generation).~~

Various stakeholders, including legislators and regulators, shareholders and non-governmental organizations, as well as other companies in many business sectors, including utilities, are considering ways to address the effect of GHG emissions on climate change. If carbon reduction regulation or legislation becomes effective, Exelon and Generation could incur costs either to limit further the GHG emissions from their operations or to procure emission allowance credits. For example, a Federal RPS could increase the cost of compliance by mandating the purchase or construction of more expensive supply alternatives. For more information regarding climate change, see ITEM 1. BUSINESS — Global Climate Change and Note 23 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements.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).

~~As a result of the Energy Policy Act of 2005,~~The Utility Registrants as users, owners, and operators of the bulk power transmission system ~~including Generation and the Utility Registrants,~~ are subject to mandatory reliability standards promulgated by NERC and enforced by FERC. ~~As operators of natural gas distribution systems, PECO, BGE and DPL are also subject to mandatory reliability standards of the U.S. Department of Transportation.~~ The standards are based on the functions that need to be performed to ensure the

bulk power system operates reliably and are guided by reliability and market interface principles. Compliance with or changes in the reliability standards could subject the Registrants to higher operating costs and/or increased capital expenditures. In addition, the ICC, PAPUC, MDPSC, DCPSC, ~~DPSC~~DEPSC, and NJBPU impose certain distribution reliability standards on the Utility Registrants. If the Utility Registrants were found ~~not to be~~ in ~~compliance~~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 ~~Utility~~ Registrants ~~as transmission owners~~could incur substantial costs to fulfill their obligations related to environmental and other matters (All Registrants).

The Registrants are subject to ~~NERC compliance requirements. NERC provides guidance to transmission owners regarding assessments of transmission lines. The results~~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 ~~assessments~~requirements could ~~require~~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.

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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 ~~incur incremental capital~~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 ~~operating~~transform the energy industry" above for additional information.

The Registrants could be negatively affected by challenges to tax positions taken, tax law changes, and ~~maintenance expenditures~~the inherent difficulty in quantifying potential tax effects of business decisions. (All Registrants).

The Registrants are required to ~~ensure~~make judgments to estimate their ~~transmission lines meet NERC standards.~~

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 31 — ~~Regulatory Matters~~Significant Accounting Policies and Note 2313 — ~~Commitments and Contingencies~~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 ~~have large consumer customer bases and as a result~~ could be the subject of public ~~criticism focused on the operability of their assets and infrastructure and quality of their service.~~criticism. Adverse publicity of this nature could render ~~legislatures and other governing bodies,~~ public service commissions and other regulatory ~~authorities,~~ and ~~government officials~~legislative authorities less likely to view energy companies ~~such as Exelon and its subsidiaries~~ in a favorable light, and could cause ~~Exelon and its subsidiaries~~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 (e.g. disallowances of costs, lower ROEs).~~requirements.

Exelon and ComEd have received requests for information related to an SEC investigation into their lobbying activities. The ~~imposition of any~~outcome of the ~~foregoing~~investigations could have a material ~~negative impact~~adverse effect on their reputation and consolidated financial statements (Exelon and ComEd).

On October 22, 2019, the ~~Registrants' business, results~~SEC notified Exelon and ComEd that it had opened an investigation into their lobbying activities in the state of ~~operations, cash flows or financial positions.~~

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 ~~Registrants cannot predict the~~ outcome of the ~~legal proceedings relating~~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 ~~business activities. An adverse determination could negatively impact their results~~consolidated financial

Table of ~~operations, cash flows or financial positions (All Registrants).~~Contents

~~The Registrants are involved in legal proceedings, claims and litigation arising out of their business operations, the most significant of which are summarized in~~statements. See Note 2318 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements. ~~Adverse outcomes in these proceedings could require significant expenditures~~, ~~result in lost revenue or restrict existing business activities, any of which~~

If ComEd violates its Deferred Prosecution Agreement announced on July 17, 2020, it could have ~~a material~~an adverse effect on the ~~Registrants’ results~~reputation and consolidated financial statements of ~~operations, cash flows or financial positions.~~

~~Generation could be negatively affected by possible Nuclear Regulatory Commission actions that could affect the operations~~Exelon and ~~profitability of its nuclear generating fleet~~ComEd (Exelon and ~~Generation)~~ComEd).

~~Regulatory risk~~

~~A change~~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 ~~Atomic Energy Act~~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 ~~applicable regulations~~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 ~~licenses could require~~bring a ~~substantial increase~~civil action against, ComEd for conduct alleged in ~~capital expenditures~~the DPA or known to the government, which could result in ~~increased operating~~fines or ~~decommissioning costs~~penalties and ~~significantly affect Generation’s results of operations, cash flows~~could have an adverse impact on Exelon’s and ComEd’s reputation or ~~financial position. Events at nuclear plants owned by others,~~relationships with regulatory and legislative authorities, customers and other stakeholders, as well as ~~those owned by Generation, could cause the NRC to initiate such actions.~~

~~Spent nuclear fuel storage~~

The approval of a national repository for the storage of SNF, such as the one previously considered at Yucca Mountain, Nevada, and the timing of such facility opening, will significantly affect the costs associated with storage of SNF, and the ultimate amounts received from the DOE to reimburse Generation for these costs. The NRC’s temporary storage rule (also referred to as the “waste confidence decision”) recognizes that licensees can safely store SNF at nuclear power plants for up to 60 years beyond the original and renewed licensed operating life of the plants.

Any regulatory action relating to the timing and availability of a repository for SNF could adversely affect Generation’s ability to decommission fully its nuclear units. Through May 15, 2014, in accordance with the NWPA and Generation’s contract with the DOE, Generation paid the DOE a fee per kWh of net nuclear generation for the cost of SNF disposal. This fee was discontinued effective May 16, 2014. Until such time as a new fee structure is in effect, Exelon and Generation will not accrue any further costs related to SNF disposal fees. Generation cannot predict what, if any, fee will be established in the future for SNF disposal. However, such a fee could be material to Generation's results of operations, cash flows ortheir consolidated financial ~~position. Generation currently estimates 2030 to be the earliest date when the DOE will begin accepting SNF, which could be delayed by further regulatory action.~~statements. See Note 2318 — Commitments and Contingencies of the Combined Notes to Consolidated Financial ~~Statements~~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.

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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 ~~SNF obligation.~~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.

~~Operational Factors~~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 ~~their~~the Registrants’ operations. As a result, employees,

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contractors, customers, and the general public are at some risk for serious injury, including loss of life. These risks include ~~nuclear accidents, dam failure,~~ gas explosions, pole strikes, and electric contact cases.

Natural disasters, war, acts and threats of terrorism, pandemic, and other significant events could negatively impact the Registrants' results of operations, ~~their~~ ability to raise capital and ~~their~~ future growth (All Registrants).

~~Generation’s fleet of power plants and the~~The Utility Registrants' distribution and transmission infrastructures could be affected by natural disasters ~~such as seismic activity, fires resulting from natural causes such as lightning,~~and extreme weather events, changes in temperature and precipitation patterns, changes to ground and surface water availability, sea level rise and other related phenomena. Severe weather or other natural disasters could be destructive, which could result in increased costs, including supply chain costs. An extreme weather event within the Utility Registrants’ service areas can also directly affect their capital assets, causing disruption in service to customers due to downed wires and poles or damage to other operating equipment.

Natural disasters and other significant events increase the risk to Generation that the NRC or other regulatory or legislative bodies could change the laws or regulations governing, among other things, operations, maintenance, licensed lives, decommissioning, SNF storage, insurance, emergency planning, security and environmental and radiological matters. In addition, natural disasters could affect the availability of a secure and economical supply of water in some locations, which is essential for Generation’s continued operation, particularly the cooling of generating units. Additionally, natural disasters and other events that have an adverse effect on the economy in general could adversely affect the Registrants’ results of operations, cash flows or financial positions and their ability to raise capital.

The impact that potential terrorist attacks could have on the industry and ~~on Exelon~~the Registrants is uncertain. ~~As owner-operators of infrastructure facilities, such as nuclear, fossil and hydroelectric generation facilities and electric and gas transmission and distribution facilities, the~~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 ~~cyber security~~cybersecurity of ~~Exelon’s~~the Registrants' facilities, which could adversely affect ~~Exelon’s~~the Registrants' ability to manage ~~its business~~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, which could adversely affect the Registrants’ results of operations, cash flows or financial positions and their ability to raise capital.~~chain. In addition, the implementation of security guidelines and measures has resulted in and is expected to continue to result in increased costs.

The Registrants could be significantly affected by the outbreak of a pandemic. Exelon has plans in place to respond to a pandemic. However, depending on the severity of a pandemic and the resulting impacts to workforce and other resource availability, the ability to operate Exelon's ~~generating and~~ transmission and distribution assets could be ~~affected, resulting in decreased service levels and increased costs.~~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.

~~Generation’s financial performance could be negatively affected by matters arising from its ownership and operation of nuclear facilities (Exelon and Generation).~~

~~Nuclear capacity factors~~

Capacity factors for generating units, particularly capacity factors for nuclear generating units, significantly affect Generation’s results of operations. Nuclear plant operations involve substantial fixed operating costs but produce electricity at low variable costs due to nuclear fuel costs typically being lower than fossil fuel costs. Consequently, to be successful, Generation must consistently operate its nuclear facilities at high capacity factors. Lower capacity factors increase Generation’s operating costs by requiring Generation to produce additional energy from primarily its fossil facilities or purchase additional energy in the spot or forward markets in order to satisfy Generation’s obligations to committed third-party sales, including the Utility Registrants. These sources generally have higher costs than Generation incurs to produce energy from its nuclear stations.

~~Nuclear refueling outages~~

In general, refueling outages are planned to occur once every 18 to 24 months. The total number of refueling outages, along with their duration, could have a significant impact on Generation’s results of operations. When refueling outages last longer than anticipated or Generation experiences unplanned outages, capacity factors decrease and Generation faces lower margins due to higher energy replacement costs and/or lower energy sales and higher operating and maintenance costs.

~~Nuclear fuel quality~~

The quality of nuclear fuel utilized by Generation could affect the efficiency and costs of Generation’s operations. Remediation actions could result in increased costs due to accelerated fuel amortization, increased outage costs and/or increased costs due to decreased generation capabilities.

~~Operational risk~~

Operations at any of Generation’s nuclear generation plants could degrade to the point where Generation has to shut down the plant or operate at less than full capacity. If this were to happen, identifying and correcting the causes could require significant time and expense. Generation could choose to close a plant rather than incur the expense of restarting it or returning the plant to full capacity. In either event, Generation could lose revenue and incur increased fuel and purchased power expense to meet supply commitments. For plants operated but not wholly owned by Generation, Generation could also incur liability to the co-owners. For nuclear plants not operated and not wholly owned by Generation, from which Generation receives a portion of the plants’ output, Generation’s results of operations are dependent on the operational performance of the operators and could be adversely affected by a significant event at those plants. Additionally, poor operating performance at nuclear plants not owned by Generation could result in increased regulation and reduced public support for nuclear-fueled energy, which could significantly affect Generation’s results of operations, cash flows or financial position. In addition, closure of generating plants owned by others, or extended interruptions of generating plants or failure of transmission lines, could affect transmission systems that could adversely affect the sale and delivery of electricity in markets served by Generation.

~~Nuclear major incident risk~~

Although the safety record of nuclear reactors generally has been very good, accidents and other unforeseen problems have occurred both in the United States and abroad. The consequences of a major incident could be severe and include loss of life and property damage. Any resulting liability from a nuclear plant major incident within the United States, owned or operated by Generation or owned by others, could exceed Generation’s resources, including insurance coverage. Uninsured losses and other expenses, to the extent not recovered from insurers or the nuclear industry, could be borne by Generation and could have a material adverse effect on Generation’s results of operations, cash flows or financial position. Additionally, an accident or other significant event at a nuclear plant within the United States or abroad, whether owned Generation or others, could result in increased regulation and reduced public support for nuclear-fueled energy and significantly adversely affect Generation’s results of operations, cash flows or financial position.

~~Nuclear insurance~~

As required by the Price-Anderson Act, Generation carries the maximum available amount of nuclear liability insurance, $450 million for each operating site. Claims exceeding that amount are covered through mandatory participation in a financial protection pool. In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay claims exceeding the $13.4 billion limit for a single incident.

Generation is a member of an industry mutual insurance company, NEIL, which provides property and business interruption insurance for Generation’s nuclear operations. In previous years, NEIL has made distributions to its members but Generation cannot predict the level of future distributions or if they will occur at all. See Note 23 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional discussion of nuclear insurance.

~~Decommissioning obligation and funding~~

NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in certain minimum amounts at the end of the life of the facility to decommission the facility. Generation is required to provide to the NRC a biennial report by unit (annually for units that have been retired and units that are within five years of retirement) addressing Generation’s ability to meet the NRC-estimated funding levels including scheduled contributions to and earnings on

~~the decommissioning trust funds. The NRC funding levels are based upon the assumption that decommissioning will commence after the end of the current licensed life of each unit.~~

Generation recognizes as a liability the present value of the estimated future costs to decommission its nuclear facilities. The estimated liability is based on assumptions in the approach and timing of decommissioning the nuclear facilities, estimation of decommissioning costs and Federal and state regulatory requirements. No assurance can be given that the costs of such decommissioning will not substantially exceed such liability, as facts, circumstances or our estimates may change, including changes in the approach and timing of decommissioning activities, changes in decommissioning costs, changes in Federal or state regulatory requirements on the decommissioning of such facilities, other changes in our estimates or Generation’s ability to effectively execute on its planned decommissioning activities.

The performance of capital markets could significantly affect the value of the trust funds. Currently, Generation is making contributions to certain trust funds of the former PECO units based on amounts being collected by PECO from its customers and remitted to Generation. While Generation, through PECO, has recourse to collect additional amounts from PECO customers (subject to certain limitations and thresholds), it has no recourse to collect additional amounts from utility customers for any of its other nuclear units if there is a shortfall of funds necessary for decommissioning. If circumstances changed such that Generation would be unable to continue to make contributions to the trust funds of the former PECO units based on amounts collected from PECO customers, or if Generation no longer had recourse to collect additional amounts from PECO customers if there was a shortfall of funds for decommissioning, the adequacy of the trust funds related to the former PECO units could be negatively affected and Exelon’s and Generation’s results of operations, cash flows or financial positions could be significantly affected. See Note 15 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information.

Forecasting trust fund investment earnings and costs to decommission nuclear generating stations requires significant judgment, and actual results could differ significantly from current estimates. Ultimately, if the investments held by Generation’s NDTs are not sufficient to fund the decommissioning of Generation’s nuclear units, Generation could be required to take steps, such as providing financial guarantees through letters of credit or parent company guarantees or making additional contributions to the trusts, which could be significant, to ensure that the trusts are adequately funded and that current and future NRC minimum funding requirements are met. As a result, Generation’s results of operations, cash flows or financial position could be significantly adversely affected. Additionally, if the pledged assets are not sufficient to fund the Zion Station decommissioning activities under the Asset Sale Agreement (ASA), Generation could have to seek remedies available under the ASA to reduce the risk of default by ZionSolutions and its parent. See Note 15 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information.

For nuclear units that are subject to regulatory agreements with either the ICC or the PAPUC, decommissioning-related activities are generally offset within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. The offset of decommissioning-related activities within the Consolidated Statements of Operations and Comprehensive Income results in an equal adjustment to the noncurrent payables to affiliates at Generation and an adjustment to the regulatory liabilities at Exelon. Likewise, ComEd and PECO have recorded an equal noncurrent affiliate receivable from Generation and a corresponding regulatory liability.

In the case of the nuclear units subject to the regulatory agreements with the ICC, if the funds held in the NDT funds for any former ComEd unit are expected to not exceed the total decommissioning obligation for that unit, the accounting to offset decommissioning-related activities in the Consolidated Statement of Operations and Comprehensive Income for that unit would be discontinued, the decommissioning-related activities would be recognized in the Consolidated Statements of Operations

and Comprehensive Income and the adverse impact to Exelon’s and Generation’s results of operations, cash flows or financial positions could be material. Additionally, any remaining balances in noncurrent payables to affiliates at Generation and ComEd’s noncurrent affiliate receivable from Generation and corresponding regulatory liability may need to be reversed and could have a material impact on Generation’s Consolidated Statements of Operations and Comprehensive Income.

In the case of the nuclear units subject to the regulatory agreements with the PAPUC, any changes to the PECO regulatory agreements could impact Exelon’s and Generation’s ability to offset decommissioning-related activities within the Consolidated Statement of Operations and Comprehensive Income, and the impact to Exelon’s and Generation’s results of operations, cash flows and financial positions could be material. Additionally, any remaining balances in noncurrent payables to affiliates at Generation and PECO’s noncurrent affiliate receivable from Generation and corresponding regulatory liability may need to be reversed and could have a material impact on Generation’s Consolidated Statement of Operations and Comprehensive Income.

~~Generation’s financial performance could be negatively affected by risks arising from its ownership and operation of hydroelectric facilities (Exelon and Generation).~~

FERC has the exclusive authority to license most non-Federal hydropower projects located on navigable waterways, Federal lands or connected to the interstate electric grid. The license for the Muddy Run Pumped Storage Project expires on December 1, 2055. The license for the Conowingo Hydroelectric Project expired on September 1, 2014. FERC issued an annual license, effective as of the expiration of the previous license. If FERC does not issue a license prior to the expiration of the annual license, the annual license renews automatically. Generation cannot predict whether it will receive all the regulatory approvals for the renewed licenses of its hydroelectric facilities. If FERC does not issue new operating licenses for Generation’s hydroelectric facilities or a station cannot be operated through the end of its operating license, Generation’s results of operations could be adversely affected by increased depreciation rates and accelerated future decommissioning costs, since depreciation rates and decommissioning cost estimates currently include assumptions that license renewal will be received. Generation could also lose revenue and incur increased fuel and purchased power expense to meet supply commitments. In addition, conditions could be imposed as part of the license renewal process that could adversely affect operations, could require a substantial increase in capital expenditures or could result in increased operating costs and significantly affect Generation’s results of operations, cash flows or financial position. Similar effects could result from a change in the Federal Power Act or the applicable regulations due to events at hydroelectric facilities owned by others, as well as those owned by Generation.

The Registrants’ businesses are capital intensive, and their assets could require significant expenditures to maintain and are subject to operational failure or be impacted by lack of availability of critical parts, which could result in potential liability (All Registrants).

The Utility Registrants’ businesses are capital intensive and require significant investments ~~by Generation in electric generating facilities and by the Utility Registrants~~ in transmission and distribution infrastructure projects. ~~These operational systems and infrastructure have been in service for many years.~~ 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’ respective results of operations, cash flows or~~Registrants' consolidated financial ~~positions~~statements could be ~~adversely~~negatively affected if they were unable to effectively manage their capital projects or raise the necessary ~~capital. Furthermore,~~capital, or if they are deemed liable for operational ~~failure of electric or gas systems, generation facilities or infrastructure could result in potential liability if such failure results in damage to property or injury to individuals.~~failure. See ITEM ~~1. BUSINESS~~7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Liquidity and Capital Resources for ~~further~~additional information regarding the Registrants’ potential future capital expenditures.

The Utility Registrants' operating costs, and customers’ and regulators’ opinions of the Utility Registrants are affected by their ability to maintain the availability and reliability of their delivery and operational systems (Exelon and the Utility Registrants).

Failures of the equipment or facilities, including information systems, used in the Utility Registrants' delivery systems could interrupt the electric transmission and electric and natural gas delivery, which could negatively impact related revenues, and increase maintenance and capital expenditures. Equipment or facilities failures can be due to a number of factors, including natural causes such as weather or information systems failure. Specifically, if the implementation of advanced metering infrastructure, 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, the Utility Registrants' results of operations, cash flows or financial positions could be negatively impacted. Furthermore, 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. If an employee or third party causes the operational systems to fail, either as a result of inadvertent error or by deliberately tampering with or manipulating the operational systems, the Utility Registrants' financial results could also 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.

The aforementioned failures or those of other utilities, including prolonged or repeated failures, could affect customer satisfaction and the level of regulatory oversight and the Utility Registrants' maintenance and capital expenditures. 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, and those damages could be material to ComEd’s results of operations, cash flows or financial position.

The Utility Registrants' respective ability to deliver electricity, their operating costs, and their capital expenditures could be negatively impacted by transmission congestion and failures of neighboring transmission systems ~~(Exelon and the Utility~~(All Registrants).

Demand for electricity within the Utility Registrants' service areas could stress available transmission capacity requiring alternative routing or curtailment of electricity ~~usage with consequent effects on operating costs, revenues and results of operations.~~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.

~~The electricity transmission facilities~~

Table of ~~the Utility Registrants are interconnected with the transmission facilities of neighboring utilities and are part of the interstate power transmission grid that is operated by PJM RTO. Although~~ Contents

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, there can be no assurance that~~utilities. However, service interruptions at other utilities ~~will not~~may cause interruptions in the Utility Registrants’ service areas. ~~If the Utility Registrants were to suffer such a service interruption, it could have a negative impact on their and Exelon’s results of operations, cash flows and financial positions.~~

The ~~Registrants are subject to physical security and cybersecurity risks (All Registrants).~~

The Registrants face physical security and cybersecurity risks as the owner-operators of generation, transmission and distribution facilities and as participants in commodities trading. Threat sources continue to seek to exploit potential vulnerabilities in the electric and natural gas utility industry associated with protection of sensitive and confidential information, grid infrastructure and other energy infrastructures, and such attacks and disruptions, both physical and cyber, are becoming increasingly sophisticated and dynamic. Continued implementation of advanced digital technologies increases the potentially unfavorable impacts of such attacks. A security breach of the physical assets or information systems of the Registrants, their competitors, vendors, business partners and interconnected entities in RTOs and ISOs, or regulators could impact the operation of the generation fleet and/or reliability of the transmission and distribution system or result in the theft or inappropriate release of certain types of information, including critical infrastructure information, sensitive customer, vendor and employee data, trading or other confidential data. The risk of these system-related events and security breaches occurring continues to intensify, and while the Registrants have been, and will likely continue to be, subjected to physical and cyber-attacks, to date none has directly experienced a material breach or disruption to its network or information systems or our service operations. However, as such attacks continue to increase in sophistication and frequency, the Registrants may be unable to prevent all such attacks in the future. If a significant breach were to occur, the reputation of Exelon or another Registrant and its customer supply activitiesRegistrants' performance could be ~~adversely~~negatively affected customer confidence in the Registrants or others in the industry could be diminished, or Exelon and its subsidiaries could be subject to legal claims, loss of revenues, increased costs, operations shutdown, etc., any of which could contribute to the loss of customers and have a negative impact on the business and/or results of operations, cash flows or financial positions. Moreover, the amount and scope of insurance maintained against losses resulting from any such events or security breaches may not be sufficient to cover losses or otherwise adequately compensate for any disruptions to business that could result. The Utility Registrants' deployment of smart meters throughout their service territories could increase the risk of damage from an intentional disruption of the system by third parties. In addition, new or updated security regulations or unforeseen threat sources could require changes in current measures taken by the Registrants or their business operations and could adversely affect their results of operations, cash flows or financial positions.

~~Failure~~if they fail to attract and retain an appropriately qualified workforce ~~could negatively impact the Registrants’ results of operations, cash flows or financial positions~~ (All Registrants).

Certain events, such as the separation transaction, an employee strike, loss of employees, loss of contract resources due to a major event, and an aging workforce without appropriate replacements, could lead to operating challenges and increased costs for the Registrants. The challenges include lack of resources, loss of knowledge and a lengthy time period associated with skill development. In this case, costs, including costs for contractors to replace employees, productivity costs, and safety costs, could arise. The Registrants are particularly affected due to the specialized knowledge required of the technical and support employees for their ~~generation,~~ transmission and distribution ~~operations. If the Registrants~~operations as well as areas where new technologies are ~~unable to successfully attract and retain an appropriately qualified workforce, their results of operations, cash flows or financial positions~~pertinent.

The Registrants’ performance could be negatively ~~impacted.~~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 ~~including initiatives mandated by regulators,~~ and new markets, ~~that~~which may not be successful ~~and acquisitions could not~~or achieve the intended financial results (All Registrants).

Generation could continue to pursue growth in its existing businesses and markets and further diversification across the competitive energy value chain. This could include investment opportunities in renewables, development of natural gas generation, nuclear advisory or operating services for third

parties, distributed generation, potential expansion of the existing wholesale gas businesses and entry into liquefied natural gas. Such initiatives could involve significant risks and uncertainties, including distraction of management from current operations, inadequate return on capital, and unidentified issues not discovered in the diligence performed prior to launching an initiative or entering a market. As these markets mature, there could be new market entrants or expansion by established competitors that increase competition for customers and resources. Additionally, it is possible that FERC, state public utility commissions or others could impose certain other restrictions on such transactions. All of these factors could result in higher costs or lower revenues than expected, resulting in lower than planned returns on investment.

The Utility Registrants face risks associated with their regulatory-mandated ~~Smart Grid~~initiatives, such as smart grids and ~~utility of the future initiatives~~ and ~~other non-regulatory mandated initiatives.~~broader beneficial electrification. These risks include, but are not limited to, cost recovery, regulatory concerns, cybersecurity, and obsolescence of technology. ~~Due to these risks, no assurance can be given that such~~Such initiatives ~~will be successful and will not have a material adverse effect on the Utility Registrants' results of operations, cash flows or financial positions.~~

~~The Registrants~~ may not ~~realize or achieve the anticipated cost savings through the cost management efforts which could impact the Registrants’ results of operations (All Registrants).~~

The Registrants’ future financial performance and level of profitability is dependent, in part, on various cost reduction initiatives. The Registrants may encounter challenges in executing these cost reduction initiatives and not achieve the intended cost savings.be successful.

Risks Related to the ~~PHI Merger~~Separation (Exelon)

The ~~merger~~separation may not achieve ~~its~~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 ~~could be unable to integrate the operations of PHI in the manner expected (Exelon and PHI).~~

~~Exelon and PHI entered into the merger agreement with the expectation that the merger will result in various benefits, including, among other things, cost savings and operating efficiencies. Achieving~~may not realize the anticipated benefits of the ~~merger is subject to a number of uncertainties, including whether the businesses of Exelon and PHI can be integrated in an efficient, effective and timely manner.~~

It is possible that the integration process could take longer than anticipated and could result in the loss of valuable employees, the disruption of Exelon’s businesses, processes and systems or inconsistencies in standards, controls, procedures, practices and policies, any of which could adversely affect the combined company’s ability to achieve the anticipated benefits of the merger as and when expected. Exelon could have difficulty addressing possible differences in corporate cultures and management philosophies.separation. Failure to achieve these anticipated benefits could result in increased costs and could adversely affect Exelon’s and PHI's future business, prospects, results of operations, cash flows or financial conditions.

~~The merger may not be accretive to earnings and could cause dilution to Exelon’s earnings per share, which could negatively affect the market price of Exelon’s common stock (Exelon).~~

The timing and amount of accretion expected could be significantly adversely affected by a number of uncertainties, including market conditions, risks related to Exelon’s businesses and whether the business of PHI is integrated in an efficient and effective manner. Exelon also could encounter additional transaction and integration-related costs, could fail to realize all of the benefits anticipated in the merger or be subject to other factors that affect preliminary estimates. Any of these factors could cause a decrease

~~in Exelon’s adjusted earnings per share or decrease or delay the expected accretive effect of the merger and contribute to a decrease in the price of Exelon’s common stock.~~



~~ITEM 1B.~~	~~UNRESOLVED STAFF COMMENTS~~

~~All Registrants~~

~~None.~~



~~ITEM 2.~~	~~PROPERTIES~~

~~Generation~~

~~The following table describes Generation’s interests in net electric generating capacity by station at December 31, 2017:~~

Station^(a)
Region Location
No. of
Units

Percent
Owned^(b)

Primary
Fuel Type

Primary
Dispatch
Type^(c)

Net Generation
Capacity (MW)^(d)

Braidwood Midwest Braidwood, IL 2
Uranium Base-load 2,381

Byron Midwest Byron, IL 2
Uranium Base-load 2,347

LaSalle Midwest Seneca, IL 2
Uranium Base-load 2,320

Dresden Midwest Morris, IL 2
Uranium Base-load 1,845

Quad Cities Midwest Cordova, IL 2
75
Uranium Base-load 1,403
^(f)
Clinton Midwest Clinton, IL 1
Uranium Base-load 1,069

Michigan Wind 2 Midwest Sanilac Co., MI 50
51
Wind Base-load 46
^(f)(h)
Beebe Midwest Gratiot Co., MI 34
51
Wind Base-load 42
^(f)(h)
Michigan Wind 1 Midwest Huron Co., MI 46
51
Wind Base-load 35
^(f)(h)
Harvest 2 Midwest Huron Co., MI 33
51
Wind Base-load 30
^(f)(h)
Harvest Midwest Huron Co., MI 32
51
Wind Base-load 27
^(f)(h)
Beebe 1B Midwest Gratiot Co., MI 21
51
Wind Base-load 26
^(f)(h)
Ewington Midwest Jackson Co., MN 10
99
Wind Base-load 20
^(f)
Marshall Midwest Lyon Co., MN 9
99
Wind Base-load 19
^(f)
City Solar Midwest Chicago, IL 1
Solar Base-load 9

AgriWind Midwest Bureau Co., IL 4
99
Wind Base-load 8
^(f)
Cisco Midwest Jackson Co., MN 4
99
Wind Base-load 8
^(f)
Solar Ohio Midwest Toledo, OH 2
Solar Base-load 4

Blue Breezes Midwest Faribault Co., MN 2
Wind Base-load 3

CP Windfarm Midwest Faribault Co., MN 2
51
Wind Base-load 2
^(f)(h)
Southeast Chicago Midwest Chicago, IL 8
Gas Peaking 296

Clinton Battery Storage Midwest Blanchester, OH 1
Energy Storage Peaking 10

Total Midwest 11,950

Limerick Mid-Atlantic Sanatoga, PA 2
Uranium Base-load 2,317

Peach Bottom Mid-Atlantic Delta, PA 2
50
Uranium Base-load 1,303
^(f)
Salem Mid-Atlantic
Lower Alloways
Creek Township, NJ
2
42.59
Uranium Base-load 1,007
^(f)
Calvert Cliffs Mid-Atlantic Lusby, MD 2
50.01
Uranium Base-load 888
^(f)(g)
Three Mile Island Mid-Atlantic Middletown, PA 1
Uranium Base-load 837
^(k)
Oyster Creek Mid-Atlantic Forked River, NJ 1
Uranium Base-load 625
^(e)
Conowingo Mid-Atlantic Darlington, MD 11
Hydroelectric Base-load 572

Criterion Mid-Atlantic Oakland, MD 28
51
Wind Base-load 36
^(f)(h)
Fair Wind Mid-Atlantic Garrett County, MD 12
Wind Base-load 30

Solar Maryland MC Mid-Atlantic Various, MD 17
Solar Base-load 29

Fourmile Mid-Atlantic Garrett County, MD 16
51
Wind Base-load 20
^(f)(h)
Solar New Jersey 1 Mid-Atlantic Various, NJ 5
Solar Base-load 18

Solar New Jersey 2 Mid-Atlantic Various, NJ 2
Solar Base-load 11

Station^(a)
Region Location
No. of
Units

Percent
Owned^(b)

Primary
Fuel Type

Primary
Dispatch
Type^(c)

Net Generation
Capacity (MW)^(d)

Solar Horizons Mid-Atlantic Emmitsburg, MD 1
51
Solar Base-load 8
^(f)(h)
Solar Maryland Mid-Atlantic Various, MD 11
Solar Base-load 8

Solar Maryland 2 Mid-Atlantic Various, MD 3
Solar Base-load 8

Solar Federal Mid-Atlantic Trenton, NJ 1
Solar Base-load 5

Solar New Jersey 3 Mid-Atlantic Middle Township, NJ 5
51
Solar Base-load 1
^(f)(h)
Solar DC Mid-Atlantic District of Columbia 1
Solar Base-load 1

Muddy Run Mid-Atlantic Drumore, PA 8
Hydroelectric Intermediate 1,070

Eddystone 3, 4 Mid-Atlantic Eddystone, PA 2
Oil/Gas Intermediate 760

Perryman Mid-Atlantic Aberdeen, MD 5
Oil/Gas Peaking 404

Croydon Mid-Atlantic West Bristol, PA 8
Oil Peaking 391

Handsome Lake Mid-Atlantic Kennerdell, PA 5
Gas Peaking 268

Notch Cliff Mid-Atlantic Baltimore, MD 8
Gas Peaking 117

Westport Mid-Atlantic Baltimore, MD 1
Gas Peaking 116

Richmond Mid-Atlantic Philadelphia, PA 2
Oil Peaking 98

Gould Street Mid-Atlantic Baltimore, MD 1
Gas Peaking 97

Philadelphia Road Mid-Atlantic Baltimore, MD 4
Oil Peaking 61

Eddystone Mid-Atlantic Eddystone, PA 4
Oil Peaking 60

Fairless Hills Mid-Atlantic Fairless Hills, PA 2
Landfill Gas Peaking 60

Delaware Mid-Atlantic Philadelphia, PA 4
Oil Peaking 56

Southwark Mid-Atlantic Philadelphia, PA 4
Oil Peaking 52

Falls Mid-Atlantic Morrisville, PA 3
Oil Peaking 51

Moser Mid-Atlantic Lower PottsgroveTwp., PA 3
Oil Peaking 51

Riverside Mid-Atlantic Baltimore, MD 2
Oil/Gas Peaking 39

Chester Mid-Atlantic Chester, PA 3
Oil Peaking 39

Schuylkill Mid-Atlantic Philadelphia, PA 2
Oil Peaking 30

Salem Mid-Atlantic
Lower Alloways
Creek Township, NJ
1
42.59
Oil Peaking 16
^(f)
Pennsbury Mid-Atlantic Morrisville, PA 2
Landfill Gas Peaking 6

Total Mid-Atlantic 11,566

Whitetail ERCOT Webb County, TX 57
51
Wind Base-load 46
^(f)(h)
Sendero ERCOT Jim Hogg and Zapata County, TX 39
51
Wind Base-load 40
^(f)(h)
Colorado Bend II ERCOT Wharton, TX 3
Gas Intermediate 1,088

Wolf Hollow II ERCOT Granbury, TX 3
Gas Intermediate 1,064

Wolf Hollow 1, 2, 3 ERCOT Granbury, TX 3
Gas Intermediate 705
^(l)
Mountain Creek 8 ERCOT Dallas, TX 1
Gas Intermediate 568
^(l)
Colorado Bend ERCOT Wharton, TX 6
Gas Intermediate 468
^(l)
Handley 3 ERCOT Fort Worth, TX 1
Gas Intermediate 395
^(l)
Handley 4, 5 ERCOT Fort Worth, TX 2
Gas Peaking 870
^(l)
Mountain Creek 6, 7 ERCOT Dallas, TX 2
Gas Peaking 240
^(l)
LaPorte ERCOT Laporte, TX 4
Gas Peaking 152
^(l)
Total ERCOT 5,636

Solar Massachusetts New England Various, MA 10
Solar Base-load 7

Holyoke Solar New England Various, MA 2
Solar Base-load 5

Station^(a)
Region Location
No. of
Units

Percent
Owned^(b)

Primary
Fuel Type

Primary
Dispatch
Type^(c)

Net Generation
Capacity (MW)^(d)

Solar Net Metering New England Uxbridge, MA 1
Solar Base-load 2

Solar Connecticut New England Various, CT 1
Solar Base-load 1

Mystic 8, 9 New England Charlestown, MA 6
Gas Intermediate 1,417

Mystic 7 New England Charlestown, MA 1
Oil/Gas Intermediate 575

Wyman New England Yarmouth, ME 1
5.9
Oil Intermediate 36
^(f)
West Medway New England West Medway, MA 3
Oil Peaking 124

Framingham New England Framingham, MA 3
Oil Peaking 30

Mystic Jet New England Charlestown, MA 1
Oil Peaking 9

Total New England 2,206

Nine Mile Point New York Scriba, NY 2
50.01
Uranium Base-load 838
^(f)(g)
FitzPatrick New York Scriba, NY 1
Uranium Base-load 842

Ginna New York Ontario, NY 1
50.01
Uranium Base-load 288
^(f)(g)
Solar New York New York Bethlehem, NY 1
Solar Base-load 3

Total New York 1,971

AVSR Other Lancaster, CA 1
Solar Base-load 242

Bluestem Other Beaver County, OK 60
51
Wind Base-load 101
^(f)(h)(i)
Exelon Wind 4 Other Gruver, TX 38
Wind Base-load 80

Shooting Star Other Kiowa County, KS 65
51
Wind Base-load 53
^(f)(h)
Albany Green Energy Other Albany, GA 1
99
Biomass Base-load 46
^(j)
Solar Arizona Other Various, AZ 127
Solar Base-load 46

Bluegrass Ridge Other King City, MO 27
51
Wind Base-load 29
^(f)(h)
California PV Energy 2 Other Various, CA 89
Solar Base-load 27

Conception Other Barnard, MO 24
51
Wind Base-load 26
^(f)(h)
Cow Branch Other Rock Port, MO 24
51
Wind Base-load 26
^(f)(h)
Solar Arizona 2 Other Various, AZ 25
Solar Base-load 23

California PV Energy Other Various, CA 53
Solar Base-load 21

Mountain Home Other Glenns Ferry, ID 20
51
Wind Base-load 21
^(f)(h)
High Mesa Other Elmore Co., ID 19
51
Wind Base-load 20
^(f)(h)
Echo 1 Other Echo, OR 21
50.49
Wind Base-load 17
^(f)(h)
Sacramento PV Energy Other Sacramento, CA 4
51
Solar Base-load 15
^(f)(h)
Cassia Other Buhl, ID 14
51
Wind Base-load 15
^(f)(h)
Wildcat Other Lovington, NM 13
51
Wind Base-load 14
^(f)(h)
Echo 2 Other Echo, OR 10
51
Wind Base-load 10
^(f)(h)
Exelon Wind 5 Other Texhoma, TX 8
Wind Base-load 10

Exelon Wind 6 Other Texhoma, TX 8
Wind Base-load 10

Exelon Wind 7 Other Sunray, TX 8
Wind Base-load 10

Exelon Wind 8 Other Sunray, TX 8
Wind Base-load 10

Exelon Wind 9 Other Sunray, TX 8
Wind Base-load 10

Exelon Wind 10 Other Dumas, TX 8
Wind Base-load 10

Station^(a)
Region Location
No. of
Units

Percent
Owned^(b)

Primary
Fuel Type

Primary
Dispatch
Type^(c)

Net Generation
Capacity (MW)^(d)

Exelon Wind 11 Other Dumas, TX 8
Wind Base-load 10

High Plains Other Panhandle, TX 8
99.5
Wind Base-load 10
^(f)
Tuana Springs Other Hagerman, ID 8
51
Wind Base-load 9
^(f)(h)
Solar Georgia Other Various, GA 10
Solar Base-load 8

Solar Georgia 2 Other Various, GA 6
Solar Base-load 8

Greensburg Other Greensburg, KS 10
51
Wind Base-load 7
^(f)(h)
Outback Solar Other Christmas Valley, OR 1
Solar Base-load 6

Echo 3 Other Echo, OR 6
50.49
Wind Base-load 5
^(f)(h)
Three Mile Canyon Other Boardman, OR 6
51
Wind Base-load 5
^(f)(h)
Loess Hills Other Rock Port, MO 4
Wind Base-load 5

Mohave Sunrise Solar Other Fort Mohave, AZ 1
Solar Base-load 5

Denver Airport Solar Other Denver, CO 1
51
Solar Base-load 2
^(f)(h)
Hillabee Other Alexander City, AL 3
Gas Intermediate 753

Grande Prairie Other Alberta, Canada 1
Gas Peaking 105

SEGS 4, 5, 6 Other Boron, CA 3
4.2-12.2
Solar Peaking 9
^(f)
Total Other 1,839

Total 35,168

~~__________~~


~~(a)~~	~~All nuclear stations are boiling water reactors except Braidwood, Byron, Calvert Cliffs, Ginna, Salem and Three Mile Island, which are pressurized water reactors.~~


~~(b)~~	~~100%, unless otherwise indicated.~~

~~(c)~~

Base-load units are plants that normally operate to take all or part of the minimum continuous load of a system and, consequently, produce electricity at an essentially constant rate. Intermediate units are plants that normally operate to take load of a system during the daytime higher load hours and, consequently, produce electricity by cycling on and off daily. Peaking units consist of lower-efficiency, quick response steam units, gas turbines and diesels normally used during the maximum load periods.


~~(d)~~	~~For nuclear stations, capacity reflects the annual mean rating. Fossil stations reflect a summer rating. Wind and solar facilities reflect name plate capacity.~~

~~(e)~~

Generation had previously agreed to permanently cease generation operations at Oyster Creek by the end of 2019. On February 2, 2018, Exelon announced that Generation will permanently cease generation operations at Oyster Creek at the end of its current operating cycle in October 2018. See Note 28 — Subsequent Events of the Combined Notes to Consolidated Financial Statements for additional information regarding the early retirement of Oyster Creek.


~~(f)~~	~~Net generation capacity is stated at proportionate ownership share.~~


~~(g)~~	~~Reflects Generation’s 50.01% interest in CENG, a joint venture with EDF. For Nine Mile Point, the co-owner owns 18% of Unit 2. Thus, Exelon’s ownership is 50.01% of 82% of Nine Mile Point Unit 2.~~


~~(h)~~	Reflects the sale of 49% of ExGen Renewables Partners to a third party on July 6, 2017. See Note 2 — Variable Interest Entities of the Combined Notes to Consolidated Financial Statements for additional information.


~~(i)~~	~~ExGen Renewables Partners owns 100% of the Class A membership interests and a tax equity investor owns 100% of the Class B membership interests of the entity that owns the Bluestem generating assets.~~


~~(j)~~	~~Generation directly owns a 50% interest in the Albany Green Energy station and an additional 49% through the consolidation of a Variable Interest Entity.~~


~~(k)~~	Generation has announced it will permanently cease generation operations at TMI on or about September 30, 2019. See Note 8 — Early Nuclear Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information regarding the early retirement of TMI.

~~(l)~~

As a result of the EGTP bankruptcy and deconsolidation on November 7, 2017, Generation deconsolidated EGTP's assets and liabilities from Generation's consolidated financial statements. As of December 31, 2017, these assets were still under Generation's ownership and included in the table. See Note 4 — Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information.

The net generation capability available for operation at any time may be less due to regulatory restrictions, transmission congestion, fuel restrictions, efficiency of cooling facilities, level of water supplies or generating units being temporarily out of service for inspection, maintenance, refueling, repairs or modifications required by regulatory authorities.

~~Generation maintains property insurance against loss or damage to its principal plants and properties by fire or other perils, subject to certain exceptions. For additional information regarding~~

nuclear insurance of generating facilities, see ITEM 1. BUSINESS — Exelon Generation Company, LLC. For its insured losses, Generation is self-insured to the extent that any losses are within the policy deductible or exceed the amount of insurance maintained. Any such lossesdo so could have a material adverse effect on ~~Generation’s consolidated~~Exelon's financial ~~condition or~~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

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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.~~operations and financial condition.

~~ComEd~~


ITEM 1B.			UNRESOLVED STAFF COMMENTS

~~ComEd’s~~All Registrants

None.

Table of Contents


ITEM 2.			PROPERTIES

The Utility Registrants

The Utility Registrants' electric substations and a portion of ~~its~~their transmission rights ~~of way~~ are located on property that ~~ComEd owns.~~they own. A significant portion of ~~its~~their electric transmission and distribution facilities isare located above or underneath highways, streets, other public places, or property that others own. ~~ComEd believes~~The Utility Registrants believe that ~~it has~~they have satisfactory rights to use those places or property in the form of permits, grants, easements, licenses, and franchise rights; however, ~~it has~~they have not necessarily undertaken to examine the underlying title to the land upon which the rights rest.

~~Transmission and Distribution~~

~~ComEd’s high voltage electric transmission lines owned and in service at December 31, 2017 were as follows:~~

Voltage (Volts) Circuit Miles
765,000 90
345,000 2,718
138,000 2,209

~~ComEd’s electric distribution system includes 35,383 circuit miles of overhead lines and 31,798 circuit miles of underground lines.~~

~~First Mortgage and Insurance~~

~~The principal properties of ComEd are subject to the lien of ComEd’s Mortgage dated July 1, 1923, as amended and supplemented, under which ComEd’s First Mortgage Bonds are issued.~~

ComEd maintains property insurance against loss or damage to its properties by fire or other perils, subject to certain exceptions. For its insured losses, ComEd is self-insured to the extent that any losses are within the policy deductible or exceed the amount of insurance maintained. Any such losses could have a material adverse effect on the consolidated financial condition or results of operations of ComEd.

~~PECO~~

PECO’s electric substations and a significant portion of its transmission lines are located on property that PECO owns. A significant portion of its electric transmission and distribution facilities is located above or underneath highways, streets, other public places or property that others own. PECO believes that it has satisfactory rights to use those places or property in the form of permits, grants, easements and licenses; however, it has not necessarily undertaken to examine the underlying title to the land upon which the rights rest.

~~Transmission and Distribution~~

~~PECO’s high voltage electric transmission lines owned and in service at December 31, 2017 were as follows:~~

Voltage (Volts) Circuit Miles
500,000 188(a)
230,000 548
138,000 135
69,000 181

~~__________~~


~~(a)~~	~~In addition, PECO has a 22.00% ownership interest in 127 miles of 500 kV lines located in Pennsylvania and a 42.55% ownership interest in 131 miles of 500 kV lines located in Delaware and New Jersey.~~

~~PECO’s electric distribution system includes 12,957 circuit miles of overhead lines and 9,322 circuit miles of underground lines.~~

~~Gas~~

~~The following table sets forth PECO’s natural gas pipeline miles at December 31, 2017:~~



	~~Pipeline Miles~~
~~Transmission~~	30
~~Distribution~~	~~6,889~~
~~Service piping~~	~~6,328~~
~~Total~~	~~13,247~~

PECO has an LNG facility located in West Conshohocken, Pennsylvania that has a storage capacity of 1,200 mmcf and a send-out capacity of 157 mmcf/day and a propane-air plant located in Chester, Pennsylvania, with a tank storage capacity of 105 mmcf and a peaking capability of 25 mmcf/day. In addition, PECO owns 31 natural gas city gate stations and direct pipeline customer delivery points at various locations throughout its gas service territory.

~~First Mortgage and Insurance~~

~~The principal properties of PECO are subject to the lien of PECO’s Mortgage dated May 1, 1923, as amended and supplemented, under which PECO’s first and refunding mortgage bonds are issued.~~

PECO maintains property insurance against loss or damage to its properties by fire or other perils, subject to certain exceptions. For its insured losses, PECO is self-insured to the extent that any losses are within the policy deductible or exceed the amount of insurance maintained. Any such losses could have a material adverse effect on the consolidated financial condition or results of operations of PECO.

~~BGE~~

BGE’s electric substations and a significant portion of its transmission lines are located on property that BGE owns. A significant portion of its electric transmission and distribution facilities is located above or underneath highways, streets, other public places or property that others own. BGE believes that it has satisfactory rights to use those places or property in the form of permits, grants, easements and

~~licenses; however, it has not necessarily undertaken to examine the underlying title to the land upon which the rights rest.~~

Transmission and Distribution

~~BGE’s~~The Utility Registrants’ high voltage electric transmission lines owned and in service at December 31, ~~2017~~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

Voltage (Volts) Circuit Miles
500,000 218
230,000 352
138,000 55
115,000 713
___________

~~BGE’s~~(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 ~~9,169~~the following number of circuit miles of overhead ~~lines~~ and ~~17,209 circuit miles of~~ underground ~~lines.~~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 ~~sets forth~~presents PECO’s, BGE’s, and DPL’s natural gas pipeline miles at December 31, ~~2017:~~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



	~~Pipeline Miles~~
~~Transmission~~	~~161~~
~~Distribution~~	~~7,306~~
~~Service piping~~	~~6,263~~
~~Total~~	~~13,730~~

___________

~~BGE~~(a) DPL has ~~an LNG facility~~a 10% undivided interest in approximately 8 miles of natural gas transmission mains located in ~~Baltimore, Maryland that has a storage capacity~~Delaware, which are used by DPL for its natural gas operations and by 90% owner for distribution of ~~1,056 mmcf~~natural gas to its electric generating facilities.

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The following table presents PECO’s, BGE’s, and ~~a send-out capacity of 332 mmcf/day~~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

BGE

LNG Facility

Baltimore, MD

1,056

332

BGE

Propane Air Plant

Baltimore, MD

550

DPL

LNG Facility

Wilmington, DE

250

PECO, BGE, and ~~a propane-air plant located in Baltimore, Maryland, with a storage capacity of 550 mmcf~~DPL also own 30, 30, and ~~a send-out capacity of 85 mmcf/day. In addition, BGE owns 12~~10 natural gas city gate stations and20 direct pipeline customer delivery points at various locations throughout ~~its~~their gas service ~~territory.~~territory, respectively.

~~Property~~First Mortgage and Insurance

~~BGE owns its~~The principal ~~headquarters building located in downtown Baltimore. BGE maintains~~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 ~~its~~their properties by fire or other perils, subject to certain exceptions. For ~~its~~their insured losses, ~~BGE is~~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 onin the consolidated financial condition or results of operations of ~~BGE.~~the Utility Registrants.

~~Pepco~~

Pepco’s electric substations and a significant portion of its transmission lines are located on property that Pepco owns. A significant portion of its electric transmission and distribution facilities is located above or underneath highways, streets, other public places or property that others own. Pepco believes that it has satisfactory rights to use those places or property in the form of permits, grants, easements and licenses; however, it has not necessarily undertaken to examine the underlying title to the land upon which the rights rest.

~~Transmission and Distribution~~

~~Pepco’s high voltage electric transmission lines owned and in service at December 31, 2017 were as follows:~~

Voltage (Volts) Circuit Miles
500,000 142
230,000 767
138,000 61
115,000 38

Pepco’s electric distribution system includes approximately 4,105 circuit miles of overhead lines and 6,844 circuit miles of underground lines. Pepco also operates a distribution system control center in Bethesda, Maryland. The computer equipment and systems contained in Pepco’s control center are financed through a sale and leaseback transaction.

~~First Mortgage and Insurance~~

~~The principal properties of Pepco are subject to the lien of Pepco’s mortgage dated July 1, 1935, as amended and supplemented, under which Pepco First Mortgage Bonds are issued.~~

Pepco maintains property insurance against loss or damage to its properties by fire or other perils, subject to certain exceptions. For its insured losses, Pepco is self-insured to the extent that any losses are within the policy deductible or exceed the amount of insurance maintained. Any such losses could have a material adverse effect on the consolidated financial condition or results of operations of Pepco.

~~DPL~~

DPL’s electric substations and a significant portion of its transmission lines are located on property that DPL owns. A significant portion of its electric transmission and distribution facilities is located above or underneath highways, streets, other public places or property that others own. DPL believes that it has satisfactory rights to use those places or property in the form of permits, grants, easements and licenses; however, it has not necessarily undertaken to examine the underlying title to the land upon which the rights rest.

~~Transmission and Distribution~~

~~DPL’s high voltage electric transmission lines owned and in service at December 31, 2017 were as follows:~~

Voltage (Volts) Circuit Miles
500,000 16
230,000 470
138,000 557
69,000 576

DPL’s electric distribution system includes approximately 6,028 circuit miles of overhead lines and 6,103 circuit miles of underground lines. DPL also owns and operates a distribution system control center in New Castle, Delaware.

~~Gas~~

~~The following table sets forth DPL’s natural gas pipeline miles at December 31, 2017:~~



	~~Pipeline Miles~~
~~Transmission~~ ^(a)	8
~~Distribution~~	~~2,061~~
~~Service piping~~	~~1,393~~
~~Total~~	~~3,462~~

~~___________~~


~~(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.

DPL owns a liquefied natural gas facility located in Wilmington, Delaware, with a storage capacity of approximately 3,045 mmcf and an emergency sendout capability of 36,000 Mcf per day. DPL owns 4 natural gas city gate stations at various locations in New Castle County, Delaware. These stations have a total primary delivery point contractual entitlement of 158,485 Mcf per day.

~~First Mortgage and Insurance~~

~~The principal properties of DPL are subject to the lien of DPL’s mortgage dated October 1, 1947, as amended and supplemented, under which DPL First Mortgage Bonds are issued.~~

DPL maintains property insurance against loss or damage to its properties by fire or other perils, subject to certain exceptions. For its insured losses, DPL is self-insured to the extent that any losses are within the policy deductible or exceed the amount of insurance maintained. Any such losses could have a material adverse effect on the consolidated financial condition or results of operations of DPL.

~~ACE~~

ACE’s electric substations and a significant portion of its transmission lines are located on property that ACE owns. A significant portion of its electric transmission and distribution facilities is located above or underneath highways, streets, other public places or property that others own. ACE believes that it has satisfactory rights to use those places or property in the form of permits, grants, easements and licenses; however, it has not necessarily undertaken to examine the underlying title to the land upon which the rights rest.

~~Transmission and Distribution~~

~~ACE’s high voltage electric transmission lines owned and in service at December 31, 2017 were as follows:~~

Voltage (Volts) Circuit Miles
500,000 281
230,000 237
138,000 268
69,000 652

ACE’s electric distribution system includes approximately 7,378 circuit miles of overhead lines and 2,900 circuit miles of underground lines. ACE also owns and operates a distribution system control center in Mays Landing, New Jersey.

~~First Mortgage and Insurance~~

~~The principal properties of ACE are subject to the lien of ACE’s mortgage dated January 15, 1937, as amended and supplemented, under which ACE First Mortgage Bonds are issued.~~

ACE maintains property insurance against loss or damage to its properties by fire or other perils, subject to certain exceptions. For its insured losses, ACE is self-insured to the extent that any losses are within the policy deductible or exceed the amount of insurance maintained. Any such losses could have a material adverse effect on the consolidated financial condition or results of operations of ACE.

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.



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 2318 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements. Such descriptions are incorporated herein by these references.



ITEM 4.			MINE SAFETY DISCLOSURES

~~All Registrants~~

Not Applicable ~~to the Registrants.~~

Table of Contents

PART II

(Dollars in millions, except per share data, unless otherwise noted)



ITEM 5.			MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Exelon

Exelon’s common stock is listed on the ~~New York Stock Exchange.~~Nasdaq (trading symbol: EXC). As of January 31, ~~2018,~~2023, there were ~~965,029,399~~994,126,931 shares of common stock outstanding and approximately ~~104,909~~80,780 record holders of common stock.

~~The following table presents the New York Stock Exchange—Composite Common Stock Prices and dividends by quarter on a per share basis:~~

2017 2016

Fourth
Quarter

Third
Quarter

Second
Quarter

First
Quarter

Fourth
Quarter

Third
Quarter

Second
Quarter

First
Quarter
High price $ 42.67
$ 38.78
$ 37.44
$ 37.19
$ 36.36
$ 37.70
$ 36.37
$ 35.95
Low price 37.55
35.37
33.30
34.47
29.82
32.86
33.18
26.26
Close 39.41
37.67
36.07
35.98
35.49
33.29
36.36
35.86
Dividends 0.328
0.328
0.328
0.328
0.318
0.318
0.318
0.310

Stock Performance Graph

The performance graph below illustrates a five-year comparison of cumulative total returns based on an initial investment of $100 in Exelon common stock, as compared with the S&P 500 Stock Index and the S&P Utility Index, for the period ~~2013~~2018 through ~~2017.~~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, ~~2012~~2017 in Exelon common stock, in the S&P 500 Stock Index, and in the S&P Utility Index; and

•All dividends are reinvested.

Table of Contents

Value of Investment at December 31,
2012 2013 2014 2015 2016 2017
Exelon Corporation $100 $65.11 $88.14 $66.01 $84.36 $132.16
S&P 500 $100 $144.74 $161.22 $160.05 $175.31 $182.82
S&P Utilities $100 $107.43 $133.52 $122.32 $137.24 $147.82

~~Generation~~

~~As of January 31, 2018, Exelon indirectly held the entire membership interest in Generation.~~


Value of Investment at December 31,
	2017	2018	2019	2020	2021	2022
Exelon Corporation	$100.00	$118.33	$123.39	$118.59	$167.70	$181.67
S&P 500	$100.00	$95.62	$125.72	$148.85	$191.58	$156.88
S&P Utilities	$100.00	$104.11	$131.54	$132.18	$155.53	$157.97

ComEd

As of January 31, ~~2018,~~2023, there were ~~127,021,256~~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. AtAs of January 31, ~~2018,~~2023, in addition to Exelon, there were ~~294~~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, ~~2018,~~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, ~~2018,~~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, ~~2018,~~2023, Exelon indirectly held the entire membership interest in PHI.

Pepco

As of January 31, ~~2018,~~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, ~~2018,~~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, ~~2018,~~2023, there were 8,546,017 outstanding shares of common stock, $3.00 par value, of ACE, all of which were indirectly held by Exelon.

All Registrants

Dividends

Under applicable Federal law, ~~Generation,~~ ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE can pay dividends only from retained, undistributed, or current earnings. A significant loss recorded at ~~Generation,~~ ComEd, PECO, BGE, PHI, Pepco, DPL, or ACE may limit the dividends that these companies can distribute to Exelon.

The Federal Power Act declares it to be unlawful for any officer or director of any public utility “to participate in the making or paying of any dividends of such public utility from any funds properly included in capital account.” What constitutes “funds properly included in capital account” is undefined in the Federal Power Act or the related regulations; however, FERC has consistently interpreted the provision to allow dividends to be paid as long as (1) the source of the dividends is clearly disclosed, (2) the dividend is not excessive and (3) there is no self-dealing on the part of corporate officials. While these restrictions may limit the absolute amount of dividends that a particular subsidiary may pay, Exelon does not believe these limitations are materially limiting because, under these limitations, the subsidiaries are allowed to pay dividends sufficient to meet Exelon’s actual cash needs.

Under Illinois law, ComEd may not pay any dividend on its stock unless, among other things, “[its] earnings and earned surplus are sufficient to declare and pay same after provision is made for reasonable and proper reserves,” or unless it has specific authorization from the ICC. ComEd has ~~also~~ 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.

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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 ~~certain dividend~~ restrictions established by the ~~MDPSC. First, in connection with the Constellation merger,~~MDPSC that prohibit BGE ~~was prohibited from paying a dividend on its common shares through the end of 2014. Second, BGE is prohibited~~ 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. ~~Finally, BGE must notify the MDPSC that it intends to declare a dividend on its common shares at least 30 days before~~No such ~~a dividend is paid and notify the MDPSC that BGE's equity ratio is at least 48% within five business days after dividend payment.~~event has occurred.

Pepco is subject to certain dividend restrictions ~~limits imposed by: (i) state corporate laws, which impose limitations~~established by settlements approved by the MDPSC and DCPSC that prohibit Pepco from paying a dividend on its common shares if (a) after the ~~funds that can~~dividend payment, Pepco's equity ratio would be ~~used~~below 48% as calculated pursuant to ~~pay dividends,~~the MDPSC's and ~~(ii)~~DCPSC's ratemaking precedents, or (b) Pepco’s senior unsecured credit rating is rated by one of the prior rights of holders of future preferred stock, if any, and existing and future mortgage bonds and other long-term debt issued by Pepco and any other restrictions imposed in connection with the incurrence of liabilities.three major credit rating agencies below investment grade. No such event has occurred.

DPL is subject to certain dividend restrictions ~~imposed by: (i) state~~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 ~~laws, which impose limitations on~~issuer or senior unsecured credit rating, or its equivalent, is rated by any of the ~~funds that can be used to pay dividends, and (ii)~~three major credit rating agencies below the ~~prior rights~~generally accepted definition of ~~holders of existing and future preferred stock, mortgage bonds and other long-term debt issued by DPL and any other restrictions imposed in connection with the incurrence of liabilities.~~investment grade. No such event has occurred.

ACE is subject to certain dividend restrictions ~~imposed by: (i) state~~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 ~~laws,~~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 ~~impose limitations on the funds that can be used~~requires ACE to ~~pay dividends~~notify and ~~the regulatory requirement that ACE~~ 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%; (ii) the prior rights of holders of existing and future preferred stock, mortgage bonds and other long-term debt issued by ACE and any other restrictions imposed in connection with the incurrence of liabilities; and (iii) certain provisions of the charter of ACE which impose restrictions on payment of common stock dividends for the benefit of preferred stockholders. Currently, the restriction in the ACE charter does not limit its ability to pay common stock dividends.. No such events have occurred.

Exelon’s Board of Directors approved an updated dividend policy ~~providing an increase~~for 2023. The 2023 quarterly dividend will be $0.36 per share.

As of ~~5% each year for the period covering 2018 through 2020, beginning with the March 2018 dividend.~~

At December 31, ~~2017,~~2022, Exelon had retained earnings of ~~$13,503~~$4,597 million, ~~including Generation’s undistributed earnings of $4,310 million, ComEd’s~~ComEd had retained earnings of ~~$1,132~~$2,030 million, ~~consisting of retained earnings appropriated for future dividends of $2,771 million, partially offset by $1,639 million of unappropriated accumulated deficits, PECO’s~~PECO had retained earnings of ~~$1,087~~$1,861 million, ~~BGE’s~~BGE had retained earnings of ~~$1,536~~$2,075 million, and ~~PHI's~~PHI had undistributed ~~earnings~~losses of ~~$(10)~~$352 million.

The following table sets forth Exelon’s quarterly cash dividends per share paid during ~~2017~~2022 and ~~2016:~~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

2017 2016
(per share)
4th
Quarter

3rd
Quarter

2nd
Quarter

1st
Quarter

4th
Quarter

3rd
Quarter

2nd
Quarter

1st
Quarter
Exelon $ 0.328
$ 0.328
$ 0.328
$ 0.328
$ 0.318
$ 0.318
$ 0.318
$ 0.310

Table of Contents

The following table sets forth ~~Generation's and~~ PHI's quarterly distributions and ComEd’s, PECO’s, BGE's, Pepco's, DPL's, and ACE's quarterly common dividend payments:


	2017								2016									2022				2021
(in millions)	4th Quarter		3rd Quarter		2nd Quarter		1st Quarter		4th Quarter		3rd Quarter		2nd Quarter		1st Quarter		(in millions)	4th Quarter	3rd Quarter	2nd Quarter	1st Quarter	4th Quarter	3rd Quarter	2nd Quarter	1st Quarter
Generation	$	165	$	164	$	166	$	164	$	755	$	56	$	56	$	55
ComEd	106		105		106		105		94		92		92		91		ComEd	144	145	145	144	127	127	126	127
PECO	72		72		72		72		69		69		70		69		PECO	100	99	100	100	85	85	84	85
BGE	50		49		50		49		45		44		45		45		BGE	74	75	75	76	73	73	72	74
PHI	44		136		62		69		99		50		16		108		PHI	125	230	293	102	98	191	333	81
Pepco	—		75		28		30		44		37		16		39		Pepco	63	100	258	42	47	98	95	28
DPL	30		28		24		30		15		1		—		38		DPL	48	39	15	41	41	43	23	40
ACE	15		31		12		10		39		13		—		11		ACE	17	90	19	19	8	51	215	14

First Quarter ~~2018~~2023 Dividend

On ~~January 30, 2018, the Exelon~~February 14, 2023, Exelon's Board of Directors declared a ~~first quarter 2018~~ regular quarterly dividend of ~~$0.3450~~$0.36 per share on Exelon’s common stock for the first quarter of 2023. The dividend is payable on Friday, March ~~9, 2018,~~10, 2023, to shareholders of record of Exelon ~~at the end~~as of ~~the day~~5 p.m. Eastern time on Monday, February ~~15, 2018.~~

27, 2023.

Table of Contents



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

~~Exelon~~

The selected financial data presented below has been derived from the audited consolidated financial statements of Exelon. This data is qualified in its entirety by reference to and should be read in conjunction with Exelon’s Consolidated Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.


~~(a)~~	~~Actual results may differ based on incremental future capital additions, actual units of production for nuclear fuel amortization, future revised ARO assumptions, etc.~~


~~(b)~~	~~Reflects incremental accelerated depreciation of plant assets, including any ARC.~~

On February 2, 2018, Exelon announced that Generation will permanently cease generation operations at Oyster Creek at the end of its current operating cycle in October 2018. In 2010, Generation announced that Oyster Creek would retire by the end of 2019 as part of an agreement with the State of New Jersey to avoid significant costs associated with the construction of cooling towers to meet the State’s then new environmental regulations. Since then, like other nuclear sites, Oyster Creek has continued to face rising operating costs amid a historically low wholesale power price environment. The decision to retire Oyster Creek in 2018 at the end of its current operating cycle involved consideration of several factors, including economic and operating efficiencies, and avoids a refueling outage scheduled for the fall of 2018 that would have required advanced purchasing of fuel fabrication and materials beginning in late February 2018.

Because of the decision to retire Oyster Creek in 2018, Exelon and Generation will recognize certain one-time charges in the first quarter of 2018 ranging from an estimated $25 million to $35 million (pre-tax) related to a materials and supplies inventory reserve adjustment, employee-related costs, and construction work-in-progress impairment, among other items. Estimated cash expenditures related to the one-time charges primarily for employee-related costs are expected to range from $5 million to $10 million.

In addition to these one-time charges, there will be financial impacts stemming from shortening the expected economic useful life of Oyster Creek primarily related to accelerated depreciation of plant assets (including any ARC), accelerated amortization of nuclear fuel, and additional ARO accretion expense associated with the changes in decommissioning timing and cost assumptions to reflect an earlier retirement date. The following table summarizes the estimated amount of expected incremental non-cash expense items expected to be incurred in 2018 because of the early retirement decision.



ITEM 1B.		~~Projected~~^(b)
~~Income statement expense (pre-tax)~~	~~2018~~
~~Depreciation and Amortization~~
~~Accelerated depreciation~~^(a)	~~$110 to $140~~
~~Accelerated nuclear fuel amortization~~	~~$40~~
~~Operating and Maintenance~~
~~Increased ARO accretion~~	~~Up to $5~~UNRESOLVED STAFF COMMENTS

~~__________~~All Registrants

None.

Table of Contents


~~(a)~~ITEM 2.			~~Includes the accelerated depreciation of plant assets including any ARC.~~PROPERTIES


~~(b)~~	~~Actual results may differ based on incremental future capital additions, actual units of production for nuclear fuel amortization, future revised ARO assumptions, etc.~~

~~EGTP Consent Agreement~~

The Utility Registrants

The Utility Registrants' electric substations and ~~Bankruptcy~~

~~On May 2, 2017, EGTP, an indirect subsidiary~~a portion of ~~Exelon~~their transmission rights are located on property that they own. A significant portion of their electric transmission and ~~Generation, entered into a consent agreement with its lenders~~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 permit EGTP to draw on its revolving credit facility and initiate an orderly sales process to sell the assets of its wholly owned subsidiaries. As a result, Exelon and Generation classified certain EGTP assets and liabilities as held for sale at their respective fair values less costs to sell and recorded a $460 million pre-tax impairment loss during 2017. On November 7, 2017, EGTP and all of its wholly owned subsidiaries filed voluntary petitions for relief under Chapter 11 of Title 11 of the United States Codeuse those places or property in the ~~United States Bankruptcy Court for~~form of permits, grants, easements, licenses, and franchise rights; however, they have not necessarily undertaken to examine the ~~District of Delaware. As a result, Exelon~~underlying title to the land upon which the rights rest.

Transmission and ~~Generation deconsolidated EGTP's assets~~Distribution

The Utility Registrants’ high voltage electric transmission lines owned and ~~liabilities from their consolidated financial statements~~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 ~~recorded a $213 million pre-tax gain.~~ACE have an ownership interest located in Delaware and New Jersey. See Note 48 — ~~Mergers, Acquisitions and Dispositions, Note 7 — Impairment of Long-Lived Assets and Intangibles and Note 13 — Debt and Credit Agreements~~Jointly Owned Electric Utility Plant of the Combined Notes to the Consolidated Financial Statements for additional ~~information regarding EGTP and the associated nonrecourse debt.~~information.

~~Acquisition of James A. FitzPatrick Nuclear Generating Station~~

On March 31, 2017, Generation acquired the 842 MW single-unit James A. FitzPatrick (FitzPatrick) nuclear generating station for a total purchase price of $289 million. In accounting for the acquisition as a business combination, Exelon and Generation recorded an after-tax bargain purchase gain of $233 million which is included within Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. See Note 4—Mergers, Acquisitions and Dispositions of the Combined Notes to the Consolidated Financial Statements for additional information regarding the Generation's acquisition of FitzPatrick and related costs.

~~Illinois Future Energy Jobs Act~~

On December 7, 2016, FEJA was signed into law by the Governor of Illinois. FEJA was effective on June 1, 2017, and includes, among other provisions, (1) a Zero Emission Standard (ZES) providing compensation for certain nuclear-powered generating facilities, (2) an extension of and certain adjustments to ComEd’sThe Utility Registrants' electric distribution ~~formula rate, (3) new cumulative persisting annual energy efficiency MWh savings goals~~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 ~~ComEd, (4) revisions to the Illinois RPS requirements, (5) provisions~~its natural gas operations and by 90% owner for ~~adjustments to or termination~~distribution of ~~FEJA programs if the average impact on ComEd’s customer rates~~

~~exceeds specified limits, (6) revisions to the existing net metering statute and (7) support for low income rooftop and community solar programs~~. FEJA establishes new or adjusts existing rate recovery mechanisms for ComEd to recover costs associated with the new or expanded energy efficiency and RPS requirements. Regulatory or legal challenges over the validity of FEJA are possible. See Note 3— Regulatory Matters of the Combined Notes to the Consolidated Financial Statements for additional information regarding FEJA. See Note 8 — Early Nuclear Plant Retirements of the Combined Notes to the Consolidated Financial Statements for additional information regarding the economic challenges facing Generation's Clinton and Quad Cities nuclear plants and the expected benefits of the ZES.

~~Illinois ZEC Procurement~~

On January 25, 2018, the ICC announced that Generation’s Clinton Unit 1, Quad Cities Unit 1 and Quad Cities Unit 2 nuclear plants were selected as the winning bidders through the IPA's ZEC procurement event. Generation executed the ZEC procurement contracts with Illinois utilities, including ComEd, effective January 26, 2018 and will begin recognizing revenue. Winning bidders will be entitled to compensation for the sale of ZECs retroactive to the June 1, 2017 effective date of FEJA. In the first quarter of 2018, Generation will recognize approximately $150 million of revenue and ComEd will record an obligation to Generation and corresponding reductionnatural gas to its ~~regulatory liability~~electric generating facilities.

Table of ~~approximately $100 million related to ZECs generated from June 1, 2017 through December 31, 2017.~~Contents

~~Dismissal~~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

BGE

LNG Facility

Baltimore, MD

1,056

332

BGE

Propane Air Plant

Baltimore, MD

550

DPL

LNG Facility

Wilmington, DE

250

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 ~~Litigation Challenging ZEC Programs~~

On July 14, 2017, the U.S. District Court for the Northern District of Illinois dismissed two lawsuits challenging the ZEC program contained in FEJA. On July 17, 2017, the plaintiffs appealed the court's decisions to the U.S. Court of Appeals for the Seventh Circuit. Briefs were fully submitted on December 12, 2017 and the Court heard oral argument on January 3, 2018. At the argument, the Court asked for supplemental briefing, which was filed on January 26, 2018.

Additionally, on July 25, 2017, the U.S. District Court for the Southern District of New York dismissed a lawsuit challenging the ZEC program contained in the New York CES. On August 24, 2017, the plaintiffs appealed the decision to the Second Circuit. ~~Briefing in the appeal was completed in December 2017, and oral argument is expected to take place in March 2018.~~

In addition, on November 30, 2016, a group of parties, including certain environmental groups and individuals, filed a Petition in New York State court seeking to invalidate the ZEC program. The Petition, which was amended on January 13, 2017, argued that the NYPSC did not have authority to establish the program and that it violated certain technical provisions of the State Administrative Procedures Act (SAPA) when adopting the ZEC program. On February 15, 2017, Generation and CENG filed a motion to dismiss the state court action. The NYPSC also filed a motion to dismiss the state court action. On March 24, 2017, the plaintiffs filed a memorandum of law opposing the motions to dismiss, and Generation and CENG filed a reply brief on April 28, 2017. Oral argument was held on June 19, 2017. On January 22, 2018, the court denied the motions to dismiss without commenting on the merits of the case. The case will now proceed to summary judgment upon filing of the full record.

The court decisions to date have upheld the ZEC programs which support Illinois's and New York's efforts to advance clean energy and preserve affordable and reliable energy resources for customers. See ~~Note 3— Regulatory Matters~~ ~~of the Combined Notes to the Consolidated Financial Statements for additional information regarding FEJA and the New York CES.~~

~~Merger Commitment Unrecognized Tax Benefits~~

Exelon established a liability for an uncertain tax position associated with the tax deductibility of certain merger commitments incurred by Exelon in connection with the acquisitions of Constellation in 2012 and PHI in 2016. In the first quarter 2017, as a part of its examination of Exelon’s return, the IRS

~~National Office issued guidance concurring with Exelon’s position that the merger commitments were deductible. As a result, Exelon, Generation, PHI, Pepco,~~ComEd, PECO, PEPCO, DPL, and ACE decreased their liability for unrecognized tax benefits by $146 million, $19 million, $59 million, $21 million, $16 million, and $22 million, respectively, as of December 31, 2017, resulting in a benefit to Income taxes on Exelon’s, Generation’s, PHI’s, Pepco’s, DPL’s and ACE’s Consolidated Statements of Operations and Comprehensive Income and corresponding decreases in their effective tax rates.

~~Combined-Cycle Gas Turbine Projects~~

In June 2017, Generation commenced commercial operations of two new combined-cycle gas turbines (CCGTs) at the Colorado Bend II and Wolf Hollow II Generating Stations in Texas. The two new CCGTs have added nearly 2,200 MWs of capacity to Generation’s fleet, enhancing Generation’s strategy to match generation to customer load. Generation invested approximately $1.5 billion over the past three years to complete the new plant construction, which utilizes new General Electric technology to make them among the cleanest, most efficient CCGTs in the nation.

~~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 position.

~~The following tables show the Utility Registrants’ completed and pending distribution rate case proceedings in 2017.~~

~~Completed Distribution Rate Case Proceedings~~

Company Jurisdiction
Approved Revenue Requirement Increase
(in millions)
Approved Return on Equity Completion Date Rate Effective Date
ComEd
Illinois (Electric)^(a)
$ 96
^(b)
8.4 %
^(c)
December 6, 2017 January 1, 2018
Pepco District of Columbia (Electric) $ 37
9.5 % July 25, 2017 August 15, 2017
Pepco Maryland (Electric) $ 32
9.5 % October 27, 2017 October 20, 2017
DPL Maryland (Electric) $ 38
9.6 % February 15, 2017 February 15, 2017
DPL Delaware (Electric) $ 31.5
9.7 % May 23, 2017 June 1, 2017
DPL Delaware (Natural Gas) $ 4.9
9.7 % June 6, 2017 July 1, 2017
ACE New Jersey (Electric) $ 43
9.6 % September 22, 2017 October 1, 2017

~~________~~

~~(a)~~

~~Pursuant to EIMA, ComEd’s electric distribution rates~~ are established through a performance-based formula through which ComEd is required to file an annual update on or before May 1, 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 for the year (annual reconciliation).


~~(b)~~	~~Reflects an increase of $78 million for the initial revenue requirement for 2017 and an increase of $18 million related to the annual reconciliation.~~

~~(c)~~

ComEd’s allowed ROE under its electric distribution formula rate is the annual average rate on 30-year treasury notes plus 580 basis points and is subject to reduction if ComEd does not deliver certain reliability and customer service benefits. The initial revenue requirement for 2017 reflects an allowed ROE of 8.40%, while the annual reconciliation reflects an allowed ROE of 8.34%, which is inclusive of a 6-basis-point performance penalty.

~~Pending Distribution Rate Case Proceedings~~

Company Jurisdiction
Requested Revenue Requirement Increase
(in millions)
Requested Return on Equity Filing Date Expected Completion Timing
Pepco Maryland (Electric) $ 11
^(a)
10.1 % January 2, 2018 (Updated February 5, 2018) Third quarter 2018
Pepco District of Columbia (Electric) $ 66
^(b)
10.1 % December 19, 2017 Fourth quarter 2018
DPL Maryland (Electric) $ 19
^(b)(c)
10.1 %
^(c)
July 14, 2017 (Updated on November 16, 2017) First quarter 2018
DPL Delaware (Electric) $ 31
^(b)
10.1 % August 17, 2017 (Updated on October 18, 2017) Third quarter 2018
DPL Delaware (Natural Gas) $ 11
^(b)
10.1 % August 17, 2017 (Updated on November 7, 2017) Fourth quarter 2018

~~________~~


~~(a)~~	On February 5, 2018, Pepco filed with the MDPSC an update to its current distribution rate case to reflect approximately $31 million in TCJA tax savings, thereby reducing the requested annual base rate increase to $11 million.


~~(b)~~	~~By mid-February, Pepco and DPL will update their current distribution rate cases to reflect the TCJA impacts.~~

~~(c)~~

On December 18, 2017, a settlement agreement was filed with the MDPSC wherein DPL will be granted a rate increase of $13 million, and a ROE of 9.5% solely for purposes of calculating AFUDC and regulatory asset carrying costs. On January 5, 2018, the MDPSC held a hearing on the settlement agreement. DPL expects a decision in the matter in the first quarter of 2018, but cannot predict whether the MDPSC will approve the settlement agreement as filed or how much of the requested increase will be approved.

~~Transmission Formula Rates~~

~~The following total increases/(decreases) were included in ComEd’s, BGE’s, Pepco's, DPL's and ACE's 2017 annual electric transmission formula rate filings:~~

2017
Annual Transmission Filings^(a)
ComEd BGE Pepco DPL ACE
Initial revenue requirement
increase
$ 44
$ 31
$ 5
$ 6
$ 20
Annual reconciliation increase (decrease) (33 ) 3
15
8
22
Dedicated facilities decrease^(b)
—
(8 ) —
—
—
Total revenue requirement
increase
$ 11
$ 26
$ 20
$ 14
$ 42

Allowed return on rate base^(c)
8.43 % 7.47 % 7.92 % 7.16 % 8.02 %
Allowed ROE^(d)
11.50 % 10.50 % 10.50 % 10.50 % 10.50 %

~~_________~~


~~(a)~~	~~All rates are effective June 2017.~~


~~(b)~~	~~BGE's transmission revenues include a FERC approved dedicated facilities charge to recover the costs of providing transmission service to specifically designated load by BGE.~~


~~(c)~~	~~Represents the weighted average debt and equity return on transmission rate bases.~~

~~(d)~~

As part of the FERC-approved settlement of ComEd’s 2007 transmission rate case, the rate of return on common equity is 11.50%, inclusive of a 50-basis-point incentive adder for being a member of a RTO, and the common equity component of the ratio used to calculate the weighted average debt and equity return for the transmission formula rate is currently capped at 55%. As part of the FERC-approved settlement of the ROE complaint against BGE, Pepco, DPL and ACE, the rate of return on common equity is 10.50%, inclusive of a 50-basis-point incentive adder for being a member of a RTO.

~~PECO Transmission Formula Rate.~~On May 1, 2017, PECO filed a request with FERC seeking approval to update its transmission rates and change the manner in which PECO’s transmission rate is determined from a fixed rate to a formula rate. The formula rate would be updated annually to ensure that under this rate customers pay the actual costs of providing transmission services. The formula rate filing includes a requested increase of $22 million to PECO’s annual transmission revenues and a requested rate of return on common equity of 11%, inclusive of a 50-basis-point adder for being a member of a regional transmission organization. PECO requested that the new transmission rate be effective as of July 2017. On June 27, 2017, FERC issued an Order accepting the filing and suspending the proposed rates until December 1, 2017, subject to ~~refund, and set~~ the ~~matter for hearing and settlement judge procedures. PECO cannot predict the final outcome~~lien of ~~the settlement or hearing proceedings, or the transmission formula FERC may approve.~~

their respective Mortgages under which their respective First Mortgage Bonds are issued. See Note 316 — ~~Regulatory Matters~~Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for ~~further details on these regulatory proceedings.~~additional information.

~~Westinghouse Electric Company LLC Bankruptcy~~

~~On March 29, 2017, Westinghouse Electric Company LLC (Westinghouse) and its affiliated debtors filed petitions for relief under Chapter 11~~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 ~~Bankruptcy Code in~~Utility Registrants.

Exelon

Security Measures

The Registrants have initiated and work to maintain security measures. On a continuing basis, the ~~U.S. Bankruptcy Court for~~Registrants evaluate enhanced security measures at certain critical locations, enhanced response and recovery plans, long-term design changes, and redundancy measures. Additionally, the Southern District of New York. In the petitions and supporting documents, Westinghouse makes clear that its requests for relief center on one business area that is losing money - the construction of nuclear power plants in Georgia and South Carolina. On January 4, 2018, Westinghouse announced its agreement to be acquired by Brookfield Business Partners. The deal, which requires bankruptcy court and regulatory approvals, is expected to close in in the third quarter of 2018. Brookfieldenergy industry has ~~informally indicated to Generation that it will assume all of Exelon's contracts~~strategic relationships with ~~Westinghouse. Generation is monitoring the bankruptcy and pending sale proceedings~~governmental authorities to ensure that ~~its rights~~emergency plans are ~~protected.~~

~~ExGen Renewables Holdings, LLC Transaction~~

~~On July 6, 2017, ExGen Renewables Holdings, LLC, a wholly owned subsidiary of Generation, completed~~in place and critical infrastructure vulnerabilities are addressed in order to maintain the sale of a 49% interest of ExGen Renewables Partners, LLC, a newly formed owner and operator of approximately 1,439 megawatts of Generation's operating wind and solar electric generating facilities. ExGen Renewables Holdings will be the managing member of ExGen Renewables Partners, LLC, and have day-to-day control and management over its renewable generation portfolio. The closingreliability of the ~~transaction was~~country’s energy systems.


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.


ITEM 4.			MINE SAFETY DISCLOSURES

Not Applicable

Table of Contents

PART II

(Dollars in millions, except per share data, unless otherwise noted)


ITEM 5.			MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Exelon

Exelon’s common stock is listed on the Nasdaq (trading symbol: EXC). As of January 31, 2023, there were 994,126,931 shares of common stock outstanding and approximately 80,780 record holders of common stock.

Stock Performance Graph

The performance graph below illustrates a five-year comparison of cumulative total returns based on an initial investment of $100 in Exelon common stock, compared with the S&P 500 Stock Index and the S&P Utility Index, for the period 2018 through 2022. Cumulative total returns account for the separation of Constellation, as spin-off dividend is assumed to be reinvested as received.

This performance chart assumes:

•$100 invested on December 31, 2017 in Exelon common stock, the S&P 500 Stock Index, and the S&P Utility Index; and

•All dividends are reinvested.

Table of Contents


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.

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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 ~~regulatory approvals, including~~dividend restrictions established by settlements approved by the ~~Federal Energy Regulatory Commission (FERC)~~MDPSC and the Public Utility Commission of Texas (PUCT) which were received during the second quarter of 2017. The sale price was $400 million plus immaterial working capital and other customary post-closing adjustments. The net proceeds, after approximately $100 million of income taxes, will be used to pay down debt and for general corporate purposes. Generation will continue to consolidate ExGen Renewables Partners, LLC and will recordDCPSC that prohibit Pepco from paying a ~~noncontrolling interest~~dividend on its ~~Consolidated Balance Sheet for~~common shares if (a) after the ~~investor's~~dividend payment, Pepco's equity ~~share~~ratio would be below 48% as ~~well as earnings attributable~~calculated pursuant to the ~~noncontrolling interest in~~MDPSC's and DCPSC's ratemaking precedents, or (b) Pepco’s senior unsecured credit rating is rated by one of the ~~Consolidated Statements of Operations and Comprehensive Income each period going forward.~~three major credit rating agencies below investment grade. No such event has occurred.

~~Hurricanes Harvey, Irma and Maria Impacts~~

~~Although Exelon subsidiaries provided substantial assistance~~DPL is subject to recovery efforts following Hurricanes Harvey and Irma, Hurricanes Harvey, Irma and Maria are not expected to have a material impact on the Registrants’ businesses or financial results given the limited operations in the areas affectedcertain dividend restrictions established by settlements approved by the ~~storms.~~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.

~~Exelon’s Strategy and Outlook for 2018 and Beyond~~

~~Exelon’s value proposition and competitive advantage come~~ACE is subject to certain dividend restrictions established by settlements approved by the NJBPU that prohibit ACE from paying a dividend on its ~~scope and its core strengths~~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 operational excellence and financial discipline. Exelon leverages its integrated business model to create value. Exelon’s regulated and competitive businesses feature a mix of attributes that, when combined, offer shareholders and customers a unique value proposition:

~~Exelon’s utilities provide a foundation for steadily growing earnings, which translates~~the three major credit rating agencies below investment grade. ACE is also subject to a ~~stable currency in our stock.~~

~~Generation’s competitive businesses provide free cash flow~~dividend restriction which requires ACE to ~~invest primarily in~~notify and obtain the ~~utilities and in long-term, contracted assets and to reduce debt.~~

~~Exelon believes its strategy provides a platform for optimal success in an energy industry experiencing fundamental and sweeping change.~~

Exelon’s utility strategy is to improve reliability and operations and enhance the customer experience, while ensuring ratemaking mechanisms provide the utilities fair financial returns. The Exelon utilities only invest in rate base where it provides a benefit to customers and the community by improving reliability and the service experience or otherwise meeting customer needs. The Exelon utilities make these investments at the lowest reasonable cost to customers. Exelon seeks to leverage its scale and expertise across the utilities platform through enhanced standardization and sharing of resources and best practices to achieve improved operational and financial results. Additionally, the Utility Registrants anticipate making significant future investments in smart meter technology, transmission projects, gas infrastructure, and electric system improvement projects, providing greater reliability and improved service for our customers and a stable return for the company.

Generation’s competitive businesses create value for customers by providing innovative energy solutions and reliable, clean and affordable energy. Generation’s electricity generation strategy is to pursue opportunities that provide stable revenues and generation to load matching to reduce earnings volatility. Generation leverages its energy generation portfolio to deliver energy to both wholesale and retail customers. Generation’s customer-facing activities foster development and delivery of other innovative energy-related products and services for its customers. Generation operates in well-developed energy markets and employs an integrated hedging strategy to manage commodity price volatility. Its generation fleet, including its nuclear plants which consistently operate at high capacity factors, also provide geographic and supply source diversity. These factors help Generation mitigate the current challenging conditions in competitive energy markets.

~~Exelon’s financial priorities are to maintain investment grade credit metrics at each~~prior approval of the Registrants, to maintain optimal capital structure and to return value to Exelon’s shareholders with an attractive dividend throughout the energy commodity market cycle and through stable earnings growth. NJBPU before dividends can be paid if its equity as a percent of its total capitalization, excluding securitization debt, falls below 30%. No such events have occurred.

Exelon’s Board of Directors approved an updated dividend policy ~~providing an increase~~for 2023. The 2023 quarterly dividend will be $0.36 per share.

As of ~~5% each year~~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

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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 ~~period covering 2018 through 2020, beginning with the~~first quarter of 2023. The dividend is payable on Friday, March ~~2018 dividend.~~10, 2023, to shareholders of record of Exelon as of 5 p.m. Eastern time on Monday, February 27, 2023.

~~Various market, financial, regulatory, legislative and operational factors could affect the Registrants' success~~

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ITEM 6.			[RESERVED]

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Item 7.			MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

(Dollars in ~~pursuing their strategies.~~ millions except per share data, unless otherwise noted)

Exelon

Executive Overview

Exelon ~~continues to assess infrastructure, operational, commercial, policy, and legal solutions to these issues. One key issue~~ is ~~ensuring the ability to properly value nuclear generation assets~~a utility services holding company engaged in the ~~market, solutions to which Exelon is actively pursuing in a variety of jurisdictions and venues. See ITEM 1A. RISK FACTORS for additional information regarding market and financial factors.~~

Continually optimizing the cost structure is a key component of Exelon’s financial strategy. In August 2015, Exelon announced a cost management program focused on cost savings of approximately $400 million at BSC and Generation, of which approximately 60% of run-rate savings was achieved by the

end of 2017 with the remainder to be fully realized in 2018. At least 75% of the savings are expected to be related to Generation, with the remaining amount related to the Utility Registrants. Additionally, in November 2017, Exelon announced a new commitment for an additional $250 million of cost savings, primarily at Generation, to be achieved by 2020. These actions are in response to the continuing economic challenges confronting all parts of Exelon’s business and industry, necessitating continued focus on cost management through enhanced efficiency and productivity.

~~Growth Opportunities~~

~~Management continually evaluates growth opportunities aligned with Exelon’s businesses, assets and markets, leveraging Exelon’s expertise in those areas and offering sustainable returns.~~

~~Regulated Energy Businesses.~~ The PHI merger provides an opportunity to accelerate Exelon’s regulated growth to provide stable cash flows, earnings accretion, and dividend support. Additionally, the Utility Registrants anticipate investing approximately $26 billion over the next five years in electric and natural gas infrastructure improvements and modernization projects, including smart meter and smart grid initiatives, storm hardening, advanced reliability technologies,energy distribution and transmission ~~projects, which is projected to result in an increase to current rate base~~businesses through ComEd, PECO, BGE, Pepco, DPL, and ACE.

Exelon has six reportable segments consisting of ~~approximately $15 billion by the end of 2022. The Utility Registrants invest in rate base where beneficial to customers~~ComEd, PECO, BGE, Pepco, DPL, and ~~the community by increasing reliability and the service experience or otherwise meeting customer needs. These investments are made at the lowest reasonable cost to customers.~~

ACE. See Note 31 — ~~Regulatory Matters~~Significant Accounting Policies and Note 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for additional information onregarding Exelon's principal subsidiaries and reportable segments.

Exelon’s consolidated financial information includes the ~~Smart Meter and Smart Grid Initiatives and infrastructure development and enhancement programs.~~

~~Competitive Energy Businesses.Generation continually assesses the optimal structure and composition~~results of its generation assets as well as explores wholesale and retail opportunities within the power and gas sectors. Generation’s long-term growth strategy is to ensure appropriate valuation of its generation assets, in part through public policy efforts, identify and capitalize on opportunities that provide generation to load matching as a means to provide stable earnings, and identify emerging technologies where strategic investments provide the option for significant future growth or influence in market development.

~~Liquidity Considerations~~

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, retire debt, pay dividends, fund pension and OPEB obligations and invest in new and existing ventures. A broad spectrum of financing alternatives beyond the core financing options can be used to meet its needs and fund growth including monetizing assets in the portfolio via project financing, asset sales, and the use of other financing structures (e.g., joint ventures, minority partners, etc.). The Registrants expect cash flows to be sufficient to meetseven separate operating ~~expenses, financing costs and capital expenditure requirements.~~

~~Exelon, Generation,~~subsidiary registrants, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE, ~~have unsecured syndicated revolving credit facilities~~which, along with ~~aggregate bank commitments~~Exelon, are collectively referred to as the Registrants. The following combined Management’s Discussion and Analysis of ~~$0.6 billion, $5.3 billion, $1.0 billion, $0.6 billion, $0.6 billion, $0.5 billion, $0.5 billion~~Financial Condition and ~~$0.4 billion, respectively. Generation also has bilateral credit facilities with aggregate maximum availability~~Results of ~~$0.5 billion. See Liquidity~~Operations is separately filed by Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL, and ~~Capital Resources — Credit Matters — Exelon Credit Facilities below.~~

ACE. However, none of the Registrants makes any representation as to information related solely to any of the other Registrants. For ~~further detail regarding~~discussion of the Utility Registrants' ~~liquidity for~~year ended December 31, 2021 compared to the year ended December 31, ~~2017, see Liquidity and Capital Resources discussion below.~~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.

~~Project Financing~~

~~Generation utilizes individual project financings as a means~~COVID-19. The Registrants have taken steps to ~~finance~~mitigate the construction of various generating asset projects. Project financing is based upon a nonrecourse financial structure, in which project debt and equity used to finance the project are paid back from the cash generatedpotential risks posed by the ~~newly constructed asset once operational. Borrowings under these agreements are secured~~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 ~~the assets and equity of each respective project. The lenders do not have recourse against Exelon or Generation~~taking extra precautions for employees who work in the event of a default. If a specific project financing entity does not maintain compliance with its specific debt financing covenants, there could be a requirement to accelerate repayment of the associated debt or other project-related borrowings earlier than the stated maturity dates. In these instances, if such repayment was not satisfied, or restructured, the lenders or security holders would generallyfield and in our facilities. The Registrants have ~~rights to foreclose against the project-specific assets~~implemented work from home policies where appropriate, and related collateral. The potential requirement to satisfy its associated debt or other borrowings earlier than otherwise anticipated could lead to impairments due to a higher likelihood of disposing of the respective project-specific assets significantly before the end of their useful lives. See Note 13 — Debt and Credit Agreements of the Combined Notes to the Consolidated Financial Statements for additional informationimposed travel limitations on ~~nonrecourse debt.~~

~~Other Key Business Drivers and Management Strategies~~

~~Utility Rates and Rate Proceedings~~employees.

The ~~Utility~~ Registrants ~~file rate cases~~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 ~~their regulatory commissions seeking increases or decreases~~a remote workforce and keep them running to ~~their electric transmission and distribution, and gas distribution rates~~ensure uninterrupted service 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~~our customers.

There were no changes in internal control over financial ~~positions. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for further details on these regulatory proceedings.~~

~~Power Markets~~

~~Price of Fuels~~

The use of new technologies to recover natural gas from shale deposits is increasing natural gas supply and reserves, which places downward pressure on natural gas prices and, therefore, on wholesale and retail power prices, which results in a reduction in Exelon’s revenues. Forward natural gas prices have declined significantly over the last several years; in part reflecting an increase in supply due to strong natural gas production (due to shale gas development).

~~Capacity Market Changes in PJM~~

In the wake of the January 2014 Polar Vortex that blanketed much of the Eastern and Midwestern United States, it became clear that while a major outage event was narrowly avoided, resources in PJM were not providing the level of reliability expected by customers. As a result, on December 12, 2014, PJM filed at FERC a proposal to make significant changes to its current capacity market construct, the Reliability Pricing Model (RPM). PJM’s proposed changes generally sought to improve resource performance and reliability largely by limiting the excuses for non-performance and by increasing the penalties for performance failures. The proposal permits suppliers to include in capacity market offers additional costs and risk so they can meet these higher performance requirements. While offers are expected to put upward pressure on capacity clearing prices, operational improvements madereporting as a result of ~~PJM’s proposal~~COVID-19 that materially affected, or are ~~expected~~reasonably likely to ~~improve reliability,~~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 ~~reduce energy production costs~~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 ~~more efficient operations and~~COVID-19 impacts on office use. See Note 12 — Asset Impairments for additional information related to ~~reduce~~this impairment assessment. None of the ~~need for out of market energy payments to suppliers. Generation participated actively~~other Registrants recorded material impairment charges in ~~PJM’s stakeholder process through which PJM developed the proposal and also actively participated in the FERC proceeding including filing comments. On June 9,~~

~~2015, FERC approved PJM's filing largely~~2022 as ~~proposed by PJM, including transitional auction rules for delivery years 2016/2017 through 2017/2018. As~~ a result of this and several related orders, PJM hosted its 2018/2019 Base Residual Auction (results posted on August 21, 2015) and its transitional auction for delivery year 2016/2017 (results posted on August 31, 2015) and its transitional auction for delivery years 2017/2018 (results posted on September 9, 2015). On May 10, 2016, FERC largely denied rehearing, and a number of parties appealed to the U.S. Court of Appeals for the DC Circuit for review of the decision. On June 20, 2017, the DC Circuit denied all the appeals.

~~MISO Capacity Market Results~~

~~On April 14, 2015, the MISO released the results of its capacity auction covering the June 2015 through May 2016 delivery year. As~~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 auction, capacity prices for the zone 4 region in downstate Illinois increased to $150 per MW per day beginning in June 2015, an increase from the prior pricing of $16.75 per MW per day that was in effect from June 2014 to May 2015. Generation had an offer that was selected in the auction. However, due to Generation's ratable hedging strategy, the results of the capacity auction have not had a material impact on Exelon's and Generation's consolidated results of operations and cash flows.

Additionally, in late May and June 2015, separate complaints were filed at the FERC by each of the State of Illinois, the Southwest Electric Cooperative, Public Citizens, Inc., and the Illinois Industrial Energy Consumers challenging the results of this MISO capacity auction for the 2015/2016 delivery in MISO delivery zone 4.impacts. The complaints allege generally that 1) the results of the capacity auction for zone 4 are not just and reasonable, 2) the results should be suspended, set for hearing and replaced with a new just and reasonable rate, 3) a refund date should be established and that 4) certain alleged behavior by one of the market participants other than Exelon or Generation, be investigated.

On October 1, 2015, FERC announced that it was conducting a non-public investigation (that does not involve Exelon or Generation) into whether market manipulation or other potential violations occurred related to the auction. On December 31, 2015, FERC issued a decision that certain of the rules governing the establishment of capacity prices in downstate Illinois are “not just and reasonable” on a prospective basis. FERC ordered that certain rules be changed prior to the April 2016 auction which set capacity prices for the 2016/2017 planning year. In response to this order, MISO filed certain rule changes with FERC. On March 18, 2016, FERC largely denied rehearing of its December 31, 2015 order. FERC continues to conduct its non-public investigation to determine if the April 2015 auction results were manipulated and, if so, whether refunds are appropriate. FERC did establish May 28, 2015, the day the first complaint was filed, as the date from which refunds (if ordered) would be calculated, and it also made clear that the findings in the December 31, 2015 order do not prejudge the investigation or related proceedings. GenerationRegistrants cannot predict the ~~impact the FERC order may ultimately have on future auction results, capacity pricing or decisions related to the potential early retirement~~full extent of ~~the Clinton nuclear plant, however, such impacts could be material to Generation's future results of operations and cash flows~~. ~~See Note 8 - Early Nuclear Plant Retirements of the Combined Notes to the Consolidated Financial Statements for additional information on~~ the impacts of COVID-19, which will depend on, among other things, the ~~MISO announcement.~~

~~Complaints at FERC Seeking to Mitigate Illinois~~rate, and ~~New York Programs Providing ZECs~~

PJM and NYISO capacity markets include a Minimum Offer Price Rule (MOPR) that is intended to preclude buyers from exercising buyer market power. If a resource is subjected to a MOPR, its offer is adjusted to remove the revenues it receives through a federal, state or other government-provided financial support program - resulting in a higher offer that may not clear the capacity market. Currently, the MOPRs in PJM and NYISO apply only to certain new resources. Exelon has generally opposed policies that require subsidies or give preferential treatment to generation providers or technologies that do not provide superior reliability or environmental benefits, or that would threaten the reliability and valuepublic perceptions of the ~~integrated electricity grid. Thus, Exelon has supported a MOPR as a means~~effectiveness, of ~~minimizing the detrimental impact certain subsidized resources could have on capacity markets (such as the New~~vaccinations and rate of resumption of business activity.

Jersey (LCAPP) and Maryland (CfD) programs). However, in Exelon’s view, MOPRs should not be applied to resources that receive compensation for providing superior reliability or environmental benefits.

On January 9, 2017, the Electric Power Supply Association (EPSA) filed two requests with FERC: one seeking to amend a prior complaint against PJM and another seeking expedited action on a pending NYISO compliance filing in an existing proceeding. Both filings allege that the relevant MOPR should be expanded to also apply to existing resources receiving ZEC compensation under the New York CES and Illinois ZES programs. The EPSA parties have filed motions to expedite both proceedings. Exelon has filed protests at FERC in response to each filing, arguing generally that ZEC payments provide compensation for an environmental attribute that is distinct from the energy and capacity sold in the FERC-jurisdictional markets, and therefore, are no different than other renewable support programs like the PTC and RPS that have generally not been subject to a MOPR. However, if successful, for Generation's facilities in NYISO and PJM expected to receive ZEC compensation (Quad Cities, Ginna, Nine Mile Point and FitzPatrick), an expanded MOPR could require exclusion

Table of ZEC compensation when bidding into future capacity auctions such that these facilities would have an increased risk of not clearing in those auctions and thus no longer receiving capacity revenues during the respective ZEC programs. Any such mitigation of these generating resources could have a material effect on Exelon’s and Generation’s future cash flows and results of operations. On August 30, 2017, EPSA filed motions to lodge the district court decisions dismissing the complaints and urging FERC to act expeditiously on its requests to expand the MOPR. On September 14, 2017, Exelon filed a response in each docket noting that it does not oppose the motions to lodge but arguing that the requests to expedite a decision on the requests to expand the MOPR have no merit. The timing of FERC’s decision with respect to both proceedings is currently unknown and the outcome of these matters is currently uncertain.Contents

~~DOE Notice of Proposed Rulemaking~~

On August 23, 2017, the DOE staff released its report on the reliability of the electric grid. One aspect of the wide-ranging report is the DOE’s recognition that the electricity markets do not currently value the resiliency provided by baseload generation, such as nuclear plants. On September 28, 2017, the DOE issued a Notice of Proposed Rulemaking (NOPR) that would entitle certain eligible resilient generating units (i.e., those located in organized markets, with a 90-day supply of fuel on site, not already subject to state cost of service regulation and satisfying certain other requirements) to recover fully allocated costs and earn a fair return on equity on their investment. The DOE's NOPR recommended that the FERC take comments for 45 days after publication in the Federal Register and issue a final order 60 days after such publication. On January 8, 2018, the FERC issued an order terminating the rulemaking docket that was initiated to address the proposed rule in the DOE NOPR, concluding the proposed rule did not sufficiently demonstrate there is a resiliency issue and that it proposed a remedy that did not appear to be just, reasonable and nondiscriminatory as required under the Federal Power Act. At the same time, the FERC initiated a new proceeding to consider resiliency challenges to the bulk power system and evaluate whether additional FERC action to address resiliency would be appropriate. The FERC directed each RTO and ISO to respond within 60 days to 24 specific questions about how they assess and mitigate threats to resiliency. Interested parties may submit reply comments within 30 days after the due date of the RTO/ISO responses. Exelon has been and will continue to be an active participant in these proceedings, but cannot predict the final outcome or its potential financial impact, if any, on Exelon or Generation.

~~Energy Demand~~

Modest economic growth partially offset by energy efficiency initiatives is resulting in flat to declining load growth in electricity for the utilities. There is decrease in projected load for electricity for ComEd, PECO, BGE, and DPL, and an increase in projected load for electricity for Pepco and ACE. ComEd, PECO, BGE, Pepco, DPL, and ACE are projecting load volumes to increase (decrease) by (0.5)%, (0.5)%, (0.6)%, 1.5%, (1.5)% and 1.5%, respectively, in 2018 compared to 2017.

~~Retail Competition~~

Generation’s retail operations compete for customers in a competitive environment, which affect the margins that Generation can earn and the volumes that it is able to serve. The market experienced high price volatility in the first quarter of 2014 which contributed to bankruptcies and consolidations within the industry during the year. However, forward natural gas and power prices are expected to remain low and thus we expect retail competitors to stay aggressive in their pursuit of market share, and that wholesale generators (including Generation) will continue to use their retail operations to hedge generation output.

~~Strategic Policy Alignment~~

As part of its strategic business planning process, Exelon routinely reviews its hedging policy, dividend policy, operating and capital costs, capital spending plans, strength of its balance sheet and credit metrics, and sufficiency of its liquidity position, by performing various stress tests with differing variables, such as commodity price movements, increases in margin-related transactions, changes in hedging practices, and the impacts of hypothetical credit downgrades.

Exelon's Board of Directors declared first, second, third and fourth quarter 2017 dividends of $0.3275 per share each on Exelon's common stock, and the first quarter 2018 dividends declared was $0.3450 per share. The dividends for the first, second, third and fourth quarter 2017 were paid on March 10, 2017, June 9, 2017, September 8, 2017 and December 8, 2017, respectively. The first quarter 2018 dividend is payable on March 9, 2018.

~~Exelon’s Board of Directors approved an updated dividend policy providing an increase of 5% each year for the period covering 2018 through 2020, beginning with the March 2018 dividend.~~

~~Hedging Strategy~~

Exelon’s policy to hedge commodity risk on a ratable basis over three-year periods is intended to reduce the financial impact of market price volatility. Generation is exposed to commodity price risk associated with the unhedged portion of its electricity portfolio. Generation enters into non-derivative and derivative contracts, including financially-settled swaps, futures contracts and swap options, and physical options and physical forward contracts, all with credit-approved counterparties, to hedge this anticipated exposure. Generation has hedges in place that significantly mitigate this risk for 2018 and 2019. However, Generation is exposed to relatively greater commodity price risk in the subsequent years with respect to which a larger portion of its electricity portfolio is currently unhedged. As of December 31, 2017, the percentage of expected generation hedged is 85%-~~88%, 55%~~-~~58% and 26%~~-29% for 2018, 2019, and 2020 respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation. Expected generation is the volume of energy that best represents our commodity position in energy markets from owned or contracted generating facilities based upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products, and options. Equivalent sales represent all hedging products, such as wholesale and retail sales of power, options and swaps. Generation has been and will continue to be proactive in using hedging strategies to mitigate commodity price risk in subsequent years as well.

Generation procures oil and natural gas through long-term and short-term contracts and spot-market purchases. Nuclear fuel is obtained predominantly through long-term uranium concentrate supply contracts, contracted conversion services, contracted enrichment services, or a combination thereof, and contracted fuel fabrication services. The supply markets for uranium concentrates and certain nuclear fuel services, coal, oil and natural gas are subject to price fluctuations and availability restrictions. Supply market conditions may make Generation’s procurement contracts subject to credit risk related to the potential non-performance of counterparties to deliver the contracted commodity or service at the

contracted prices. Approximately 59% of Generation’s uranium concentrate requirements from 2018 through 2022 are supplied by three producers. In the event of non-performance by these or other suppliers, Generation believes that replacement uranium concentrate can be obtained, although at prices that may be unfavorable when compared to the prices under the current supply agreements. Non-performance by these counterparties could have a material adverse impact on Exelon’s and Generation’s results of operations, cash flows and financial positions.

~~The Utility Registrants mitigate commodity price risk through regulatory mechanisms that allow them to recover procurement costs from retail customers.~~

~~Environmental Legislative and Regulatory Developments~~

Exelon was actively involved in the Obama Administration’s development and implementation of environmental regulations for the electric industry, in pursuit of its business strategy to provide reliable, clean, affordable and innovative energy products. These efforts have most frequently involved air, water and waste controls for fossil-fueled electric generating units, as set forth in the discussion below. These regulations have had a disproportionate adverse impact on coal-fired power plants, requiring significant expenditures of capital and variable operating and maintenance expense, and have resulted in the retirement of older, marginal facilities. Due to its low emission generation portfolio, Generation has not been significantly affected by these regulations, representing a competitive advantage relative to electric generators that are more reliant on fossil fuel plants.

Through the issuance of a series of Executive Orders (EO), President Trump has initiated review of a number of EPA and other regulations issued during the Obama Administration, with the expectation that the Administration will seek repeal or significant revision of these rules. Under these EOs, each executive agency is required to evaluate existing regulations and make recommendations regarding repeal, replacement, or modification. The Administration’s actions are intended to result in less stringent compliance requirements under air, water, and waste regulations. The exact nature, extent, and timing of the regulatory changes are unknown, as well as the ultimate impact on Exelon’s and its subsidiaries results of operations and cash flows.

In particular, the Administration has targeted existing EPA regulations for repeal, including notably the Clean Power Plan, as well as revoking many Executive Orders, reports, and guidance issued by the Obama Administration on the topic of climate change or the regulation of greenhouse gases. The Executive Order also disbanded the Interagency Working Group that developed the social cost of carbon used in rulemakings, and withdrew all technical support documents supporting the calculation. Other regulations that have been specifically identified for review are the Clean Water Act rule relating to jurisdictional waters of the U.S., the Steam Electric Effluent Guidelines relating to waste water discharges from coal-fired power plants, and the 2015 National Ambient Air Quality Standard (NAAQS) for ozone. The review of final rules could extend over several years as formal notice and comment rulemaking process proceeds.

~~Air Quality~~

~~Mercury and Air Toxics Standard Rule (MATS).~~ On December 16, 2011, the EPA signed a final rule to reduce emissions of toxic air pollutants from power plants and signed revisions to the NSPS for electric generating units. The final rule, known as MATS, requires coal-fired electric generation plants to achieve high removal rates of mercury, acid gases and other metals, and to make capital investments in pollution control equipment and incur higher operating expenses. The initial compliance deadline to meet the new standards was April 16, 2015; however, facilities may have been granted an additional one or two-year extension in limited cases. Numerous entities challenged MATS in the D.C. Circuit Court, and Exelon intervened in support of the rule. In April 2014, the D.C. Circuit Court issued an opinion upholding MATS in its entirety. On appeal, the U.S. Supreme Court decided in June 2015 that the EPA unreasonably refused to consider costs in determining whether it is appropriate and necessary to regulate

hazardous air pollutants emitted by electric utilities. The U.S. Supreme Court, however, did not vacate the rule; rather, it was remanded to the D.C. Circuit Court to take further action consistent with the U.S. Supreme Court’s opinion on this single issue. On April 27, 2017, the D.C. Circuit granted EPA’s motion to hold the litigation in abeyance, pending EPA’s review of the MATS rule pursuant to President Trump’s EO discussed above. Following EPA’s review and determination of its course of action for the MATS rule, the parties will have 30 days to file motions on future proceedings. Notwithstanding the Court’s order to hold the litigation in abeyance, ~~the MATS rule remains in effect. Exelon will continue to participate in the remanded proceedings before the D.C. Circuit Court as an intervenor in support of the rule.~~

~~Clean Power Plan~~. On April 28, 2017, the D.C. Circuit Court issued orders in separate litigation related to the EPA’s actions under the Clean Power Plan (CPP) to amend Clean Air Act Section 111(d) regulation of existing fossil-fired electric generating units and Section 111(b) regulation of new fossil-fired electric generating units. In both cases, the Court has determined to hold the litigation in abeyance pending a determination whether the rule should be remanded to the EPA. On October 10, 2017, EPA issued a proposed rule to repeal the CPP in its entirety, based on a proposed change in the Agency’s legal interpretation of Clean Air Act Section 111(d) regarding actions that the Agency can consider when establishing the Best System of Emission Reduction (“BSER”) for existing power plants. Under the proposed interpretation, the Agency exceeded its authority under the Clean Air Act by regulating beyond individual sources of GHG emissions. The EPA has also indicated its intent to issue an advance notice of proposed rulemaking to solicit information on systems of emission reduction that are in accord with the Agency’s proposed revised legal interpretation; namely, only by regulating emission reductions that can be implemented at and to individual sources.

~~2015 Ozone National Ambient Air Quality Standards (NAAQS).~~ On April 11, 2017, the D.C. Circuit ordered that the consolidated 2015 ozone NAAQS litigation be held in abeyance pending EPA’s further review of the 2015 Rule. EPA did not meet the October 1, 2017 deadline to promulgate initial designations for areas in attainment or non-attainment of the standard. A number of states and environmental organizations have notified the EPA of their intent to file suit to compel EPA to issue the designations.

~~Climate Change.~~ Exelon supports comprehensive climate change legislation or regulation, including a cap-and-trade program for GHG emissions, which balances the need to protect consumers, business and the economy with the urgent need to reduce national GHG emissions. In the absence of Federal legislation, the EPA is moving forward with the regulation of GHG emissions under the Clean Air Act. In addition, there have been recent developments in the international regulation of GHG emissions pursuant to the United Nations Framework Convention on Climate Change (“UNFCCC” or “Convention”). See ITEM 1.~~BUSINESS, "Global Climate Change" for further discussion.~~

Water Quality

~~Section 316(b) requires that~~Under the ~~cooling~~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 ~~intake structures at electric power plants reflect the best technology available to minimize adverse environmental impacts,~~into waterways and ~~is implemented through state-level NPDES permit programs. All of Generation’s power generation facilities with cooling water systems~~ are therefore subject to these regulations and operate under NPDES permits.

Under Clean Water Act Section 404 and state laws and regulations, the ~~regulations. Facilities without closed-cycle recirculating systems (e.g., cooling towers) are potentially most affected by recent changes~~Registrants may be required to obtain permits for projects involving dredge or fill activities in waters of the ~~regulations. For Generation, those~~United States.

Where Registrants’ facilities are ~~Calvert Cliffs, Clinton, Dresden, Eddystone, Fairless Hills, FitzPatrick, Ginna, Gould Street, Mountain Creek, Handley, Mystic 7, Nine Mile Point Unit 1, Peach Bottom, Quad Cities, and Salem.See ITEM 1. BUSINESS, "Water Quality"~~required to secure a federal license or permit for ~~further discussion.~~activities that may result in a discharge to covered waters, they may be required to obtain a state water quality certification under Clean Water Act section 401.

Solid and Hazardous Waste and Environmental Remediation

~~In October 2015,~~CERCLA provides for response and removal actions coordinated by the ~~first federal regulation~~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 ~~coal combustion residuals (CCR) from power plants became effective.~~ solid and hazardous wastes and cleanup of sites where such activities were conducted.

The ~~rule classifies CCR as non-hazardous waste under RCRA.~~ Registrants’ operations have in the past, and may in the future, require substantial expenditures in order to comply with these Federal and state environmental laws. Under these laws, the ~~regulation, CCR will continue to be regulated by most states subject to coordination with the~~

federal regulations. Generation has previously recorded accruals consistent with state regulation for its owned coal ash sites, and as such, the regulation is not expected to impact Exelon’s and Generation’s financial results. Generation does not have sufficient information to reasonably assess the potential likelihood or magnitude of any remediation requirements thatRegistrants may be ~~asserted under~~liable for the ~~new federal regulations for coal ash disposal sites~~costs of remediating environmental contamination of property now or formerly owned by ~~Generation.~~ ~~For these reasons, Generation is unable~~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 ~~predict whether~~proceedings initiated by the EPA, state agencies, and/or other responsible parties under CERCLA and RCRA or similar state laws with respect to ~~what extent it~~a number of sites or may ~~ultimately~~undertake to investigate and remediate sites for which they may be ~~held responsible~~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

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expended in 2023 for compliance with environmental remediation related to contamination at former MGP sites and other ~~costs relating~~gas purification sites is estimated to ~~formerly owned coal ash disposal sites under~~be approximately $52 million which consists primarily of $44 million at ComEd.

As of December 31, 2022, the ~~new regulations.~~Registrants have established appropriate contingent liabilities for environmental remediation requirements. In addition, the Registrants may be required to make significant additional expenditures not presently determinable for other environmental remediation costs.

See Note 233 — 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.

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Information about our Executive Officers as of February 14, 2023

Exelon

Name

Age

Position

Period

Butler, Calvin G. Jr.

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

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

Executive Vice President, Compliance, Audit and Risk, Exelon

2020 - Present

Chief Compliance Officer, Citadel LLC

2017 - 2020

Littleton, Gayle E.

Executive Vice President, General Counsel, Exelon

2020 - Present

Partner, Jenner & Block LLP

2015 - 2020

Quiniones, Gil

Chief Executive Officer, ComEd

2021 - Present

President and Chief Executive Officer, New York Power Authority

2011 - 2021

Innocenzo, Michael A.

President and Chief Executive Officer, PECO

2018 - Present

Khouzami, Carim V.

President, BGE

2021 - Present

Chief Executive Officer, BGE

2019 - Present

Senior Vice President & COO, Exelon Utilities

2018 - 2019

Anthony, J. Tyler

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.

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

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ComEd

Name

Age

Position

Period

Quiniones, Gil

Chief Executive Officer, ComEd

2021 - Present

President and Chief Executive Officer, New York Power Authority

2011 - 2021

Donnelly, Terence R.

President and Chief Operating Officer, ComEd

2018 - Present

Graham, Elisabeth J.

Senior Vice President, Chief Financial Officer & Treasurer, ComEd

2022 - Present

Treasurer, Exelon

2018 - 2022

Rippie, E. Glenn

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

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

Senior Vice President, Governmental, Regulatory and External Affairs, ComEd

2022 - Present

Vice President, External Affairs, Nicor Gas

2013 - 2022

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PECO

Name

Age

Position

Period

Innocenzo, Michael A.

President and Chief Executive Officer, PECO

2018 - Present

Levine, Nicole

Senior Vice President and Chief Operations Officer, PECO

2022 - Present

Vice President, Electrical Operations, PECO

2018 - 2022

Humphrey, Marissa

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.

Senior Vice President, Governmental, Regulatory and External Affairs, PECO

2016 - Present

Williamson, Olufunmilayo

Senior Vice President, Customer Operations, PECO

2021 - Present

Senior Vice President, Chief Commercial Risk Officer, Exelon

2017 - 2020

Gay, Anthony

Vice President and General Counsel, PECO

2019 - Present

Vice President, Governmental and External Affairs, PECO

2016 - 2019

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BGE

Name

Age

Position

Period

Khouzami, Carim V.

President, BGE

2021 - Present

Chief Executive Officer, BGE

2019 - Present

Senior Vice President & COO, Exelon Utilities

2018 - 2019

Dickens, Derrick

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.

Senior Vice President, Chief Financial Officer and Treasurer, BGE

2016 - Present

Núñez, Alexander G.

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

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

Vice President and General Counsel, BGE

2021 - Present

Associate General Counsel, BGE

2019 - 2021

Assistant General Counsel, Exelon

2017 - 2019

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PHI, Pepco, DPL, and ACE

Name

Age

Position

Period

Anthony, J. Tyler

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

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.

Senior Vice President, Chief Financial Officer and Treasurer, PHI, Pepco, DPL, and ACE

2018 - Present

Oddoye, Rodney

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

Vice President and General Counsel, PHI, Pepco, DPL, and ACE

2021 - Present

Associate General Counsel, Exelon

2017 - 2021

Bell-Izzard, Morlon

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


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,

•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.

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Risks related to operational factors primarily include:

•the ability of the Utility Registrants to maintain the reliability, resiliency, and safety of their energy delivery systems, which could affect their ability to deliver energy to their customers and affect their operating costs, and

•physical and cyber security risks for the Utility Registrants as the owner-operators of transmission and distribution facilities.

Risks related to the separation primarilyinclude:

•challenges to achieving the benefits of separation and

•performance by Exelon and Constellation under the transaction agreements, including indemnification responsibilities.

There may be further ~~detail~~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.

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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.

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.

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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).

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.

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

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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.

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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 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.

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The Registrants could be negatively affected by federal and state RPS and/or energy conservation legislation, along with energy conservation by customers (All Registrants).

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 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

Table of ~~environmental regulation.~~Contents

~~Employees~~statements. See Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements.

~~In January 2017,~~If ComEd violates its Deferred Prosecution Agreement announced on July 17, 2020, it could have an ~~election~~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 ~~held at BGE which resulted~~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 ~~union representation~~connection with the matters identified therein for ~~approximately 1,394 employees. BGE~~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 ~~IBEW Local 410 are negotiating an initial agreement~~(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 ~~some modifications to wages, hours~~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).

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The Utility Registrants' operating costs are affected by their ability to maintain the availability and reliability of their delivery and operational systems (All Registrants).

The Registrants are subject to physical security and cybersecurity risks (All Registrants).

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.

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,

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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.

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.

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.

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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).

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.

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sufficient to protect Exelon against the full amount of such liabilities, and Constellation may not be able to fully satisfy its indemnification obligations.


ITEM 1B.			UNRESOLVED STAFF COMMENTS

All Registrants

None.

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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.

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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

BGE

LNG Facility

Baltimore, MD

1,056

332

BGE

Propane Air Plant

Baltimore, MD

550

DPL

LNG Facility

Wilmington, DE

250

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


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.


ITEM 4.			MINE SAFETY DISCLOSURES

Not Applicable

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PART II

(Dollars in millions, except per share data, unless otherwise noted)


ITEM 5.			MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Exelon

Stock Performance Graph

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.

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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

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

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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

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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.			[RESERVED]

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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.

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Financial Results of Operations

GAAP Results of Operations. The following table sets forth Exelon's GAAP consolidated Net income attributable to common shareholders from continuing operations and the Utility Registrants' Net income for the year ended December 31, 2022 compared to the same period in 2021. For additional information regarding the financial results for the years ended December 31, 2022 and 2021 see the discussions of Results of Operations by Registrant.


	2022	2021	Favorable (Unfavorable) Variance
Exelon	2,054	1,616	$	438
ComEd	917	742	175
PECO	576	504	72
BGE	380	408	(28)
PHI	608	561	47
Pepco	305	296	9
DPL	169	128	41
ACE	148	146	2
Other(a)	(427)	(599)	172

__________

(a)Primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities, and other financing and investing activities.

The separation of Constellation Energy Corporation, including Generation and its subsidiaries, meets the criteria for discontinued operations and as such, Generation's results of operations are presented as discontinued operations and have been excluded from Exelon's continuing operations for all periods presented. See Note 1 — Significant Accounting Policies and Note 2 — Discontinued Operations for additional information.

Accounting rules require that certain BSC costs previously allocated to Generation be presented as part of Exelon’s continuing operations as these costs do not qualify as expenses of the discontinued operations. Such costs are included in Other in the table above and were $28 million and $429 million on a pre-tax basis, for the years ended December 31, 2022 and 2021, respectively.

Year Ended December 31, 2022 Compared to Year Ended December 31, 2021. Net income attributable to common shareholders from continuing operationsincreased by $438 million and diluted earnings per average common share from continuing operations increased to $2.08 in 2022 from $1.65 in 2021 primarily due to:

•Higher electric distribution earnings and energy efficiency earnings from higher rate base and higher allowed ROE due to an increase in treasury rates at ComEd;

•The favorable impacts of rate increases at PECO, BGE, and PHI;

•Favorable impacts of decreased storm costs at PECO and BGE; and

•Lower BSC costs presented in Exelon’s continuing operations, which were previously allocated to Generation but do not qualify as expenses of the discontinued operation per the accounting rules.

The increases were partially offset by:

•An income tax expense recorded in connection with the separation primarily due to the long-term marginal state income tax rate change, the recognition of valuation allowances against the net deferred tax assets positions for certain standalone state filing jurisdictions, and nondeductible transaction costs partially offset by a one-time impact associated with a state tax benefit;

•An adjustment at PECO to exclude one-time non-cash impacts associated with the remeasurement of deferred income taxes as a result of the reduction in Pennsylvania corporate income tax rate;

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•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.

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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.

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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.

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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

10.50

Second quarter of 2024

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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 ~~employment. No~~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

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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

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 ~~been finalized~~become effective. Accordingly, the 1992 Franchise Agreement remains in effect at this time. In April 2021, the City invited interested parties to ~~date~~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 ~~management~~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 ~~such negotiations. In April 2017, Exelon Nuclear Security successfully ratified~~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 ~~CBA~~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 ~~SPFPA Local 238 at Quad Cities~~$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 anaddress 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

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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 ~~years. In June 2017,~~different Regional Clean Hydrogen Hub opportunities, covering all five states that Exelon ~~Nuclear Security successfully ratified its CBA with~~operates in plus Washington D.C., that have submitted concept papers to the ~~UGSOA Local 12 at Limerick~~Department of Energy. All three opportunities have received letters of encouragement from Department of Energy to ~~an extension~~submit applications due in April 2023. The program will create networks of ~~three years.~~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 discusses these policies, estimates and assumptions with its Accounting and Disclosure Governance Committee on a regular basis and provides periodic updates on management decisions to the Audit Committee of the Exelon Board of Directors. 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 ~~discussion of~~information on the application of these accounting policies can be found in the Combined Notes to Consolidated Financial Statements.

~~Nuclear Decommissioning Asset Retirement Obligations (Exelon and Generation)~~

Generation’s ARO associated with decommissioning its nuclear units was $9.7 billion at December 31, 2017. The authoritative guidance requires that Generation estimate its obligation for the future decommissioning of its nuclear generating plants. To estimate that liability, Generation uses an internally-developed, probability-weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple decommissioning outcome scenarios.

As a result of recent nuclear plant retirements in the industry, nuclear operators and third-party service providers are obtaining more information about costs associated with decommissioning activities. At the same time, regulators are gaining more information about decommissioning activities which could result in changes to existing decommissioning requirements. In addition, as more nuclear plants are retired, it is possible that technological advances will be identified that could create efficiencies and lead to a reduction in decommissioning costs. The availability of decommissioning trust funds could impact the timing of the decommissioning activities. Additionally, certain factors such as changes in regulatory requirements during plant operations or the profitability of a nuclear plant could impact the timing of plant retirements. These factors could result in material changes to Generation’s current estimates as more information becomes available and could change the timing of plant retirements and the probability assigned to the decommissioning outcome scenarios.

The nuclear decommissioning obligation is adjusted on a regular basis due to the passage of time and revisions to the key assumptions for the expected timing and/or estimated amounts of the future undiscounted cash flows required to decommission the nuclear plants, based upon the following methodologies and significant estimates and assumptions:

~~Decommissioning Cost Studies~~

Generation uses unit-by-unit decommissioning cost studies to provide a marketplace assessment of the expected costs (in current year dollars) and timing of decommissioning activities, which are validated by comparison to current decommissioning projects within the industry and other estimates. Decommissioning cost studies are updated, on a rotational basis, for each of Generation’s nuclear units at least every five years, unless circumstances warrant more frequent updates (such as a change in assumed operating life for a nuclear plant). As part of the annual cost study update process, Generation evaluates newly assumed costs or substantive changes in previously assumed costs to determine if the cost estimate impacts are sufficiently material to warrant application of the updated estimates to the AROs across the nuclear fleet outside of the normal five-year rotating cost study update cycle.

~~Cost Escalation Factors~~

Generation uses cost escalation factors to escalate the decommissioning costs from the decommissioning cost studies discussed above through the assumed decommissioning period for each of the units. Cost escalation studies, updated on an annual basis, are used to determine escalation factors, and are based on inflation indices for labor, equipment and materials, energy, LLRW disposal and other costs. All of the nuclear AROs are adjusted each year for the updated cost escalation factors.

~~Probabilistic Cash Flow Models~~

Generation’s probabilistic cash flow models include the assignment of probabilities to various scenarios for decommissioning cost levels, decommissioning approaches, and timing of plant shutdown on a unit-by-unit basis. Probabilities assigned to cost levels include an assessment of the likelihood of costs 20% higher (high-cost scenario) or 15% lower (low-cost scenario) than the base cost scenario. Probabilities are also assigned to four different decommissioning approaches.

DECON - a method of decommissioning shortly after the cessation of operation in which the equipment, structures, and portions of a facility and site containing radioactive contaminants are removed and safely buried in a LLRW landfill or decontaminated to a level that permits property to be released for unrestricted use. Spent fuel is transferred to dry cask storage as soon as possible until DOE acceptance for disposal.


2.	Delayed DECON - similar to the DECON scenario but with a delay to allow for spent fuel to be removed from the site prior to onset of decommissioning activities. Spent fuel is retained in existing location (either wet or dry storage) until DOE acceptance for disposal.


3.	Shortened SAFSTOR - similar to the DECON scenario but with generally a 30-year delay prior to onset of decommissioning activities. Spent fuel is transferred to dry cask storage as soon as possible until DOE acceptance for disposal.


4.	SAFSTOR - a method of decommissioning in which the nuclear facility is placed and maintained in such condition that the nuclear facility can be safely stored and subsequently decontaminated to levels that permit release for unrestricted use generally within 60 years after cessation of operations. Spent fuel is transferred to dry cask storage as soon as possible until DOE acceptance for disposal.

The actual decommissioning approach selected once a nuclear facility is shutdown will be determined by Generation at the time of shutdown and may be influenced by multiple factors including the funding status of the nuclear decommissioning trust fund at the time of shutdown.

The assumed plant shutdown timing scenarios include the following four alternatives: (1) the probability of operating through the original 40-year nuclear license term, (2) the probability of operating through an extended 60-year nuclear license term (regardless of whether such 20-year license extension has been received for each unit), (3) the probability of a second, 20-year license renewal for some nuclear units, and (4) the probability of early plant retirement for certain sites due to changing market conditions and regulatory environments. The successful operation of nuclear plants in the U.S. beyond the initial 40-year license terms has prompted the NRC to consider regulatory and technical requirements for potential plant operations for an 80-year nuclear operating term. As power market and regulatory environment developments occur, Generation evaluates and incorporates, as necessary, the impacts of such developments into its nuclear ARO assumptions and estimates.

Generation’s probabilistic cash flow models also include an assessment of the timing of DOE acceptance of SNF for disposal. Generation currently assumes DOE will begin accepting SNF in 2030. The SNF acceptance date assumption is based on management’s estimates of the amount of time required for DOE to select a site location and develop the necessary infrastructure for long-term SNF storage. For more information regarding the estimated date that DOE will begin accepting SNF, see Note 23 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements.

~~License Renewals~~

Except for its Clinton unit, Generation has successfully obtained initial 20-year operating license renewal extensions (i.e., extending the total license term to 60 years) for all of its operating nuclear units (including the two Salem units co-owned by Generation, but operated by PSEG). Generation intends to apply for an initial license renewal for the Clinton unit. Clinton depreciation provisions are based on 2027 which is the last year of the Illinois Zero Emissions Standard. No prior Generation initial license extension application has been denied. Generation intends to apply for a second 20-year renewal for the Peach Bottom Units 2 and 3.

~~Discount Rates~~

The probability-weighted estimated future cash flows for the various assumed scenarios are discounted using credit-adjusted, risk-free rates (CARFR) applicable to the various businesses in which each of the nuclear units originally operated. The authoritative guidance required Generation to establish an ARO at fair value at the time of the initial adoption. Subsequent to the initial adoption, the ARO is adjusted for changes to estimated costs, timing of future cash flows and modifications to decommissioning assumptions, as described above. The ARO is not required or permitted to be re-measured for changes in the CARFR that occur in isolation. Increases in the ARO as a result of upward revisions in estimated undiscounted cash flows are considered new obligations and are measured using a current CARFR as the increase creates a new cost layer within the ARO. Any decrease in the estimated undiscounted future cash flows relating to the ARO are treated as a modification of an existing ARO cost layer and, therefore, is measured using the average historical CARFR rates used in creating the initial ARO cost layers. If Generation’s future nominal cash flows associated with the ARO were to be discounted at current prevailing CARFR, the obligation would increase from approximately $9.7 billion to approximately $10.3 billion.

To illustrate the significant impact that changes in the CARFR, when combined with changes in projected amounts and expected timing of cash flows, can have on the valuation of the ARO: i) had Generation used the 2016 CARFR rather than the 2017 CARFR in performing its annual 2017 ARO update, Generation would have increased the ARO by an additional $10 million; and ii) if the CARFR

used in performing the annual 2017 ARO update are increased by 50 basis points or decreased by 50 basis points, the ARO would have decreased by $170 million and increased by $30 million, respectively, as compared to the actual decrease of $69 million.

~~ARO Sensitivities~~

Changes in the assumptions underlying the ARO could materially affect the decommissioning obligation. The impact to the ARO of a change in any one of these assumptions is highly dependent on how the other assumptions may correspondingly change.

~~The following table illustrates the effects of changing certain ARO assumptions while holding all other assumptions constant (dollars in millions):~~

Change in ARO Assumption Increase (Decrease) to ARO at
December 31, 2017
Cost escalation studies
Uniform increase in escalation rates of 50 basis points $ 1,690
Probabilistic cash flow models
Increase the estimated costs to decommission the nuclear plants by 10 percent 700
Increase the likelihood of the DECON scenario by 10 percentage points and decrease the likelihood of the SAFSTOR scenario by 10 percentage points 500
Shorten each unit's probability weighted operating life assumption by 10%^(a)
660
Extend the estimated date for DOE acceptance of SNF to 2035 130

~~__________~~


~~(a)~~	~~Timing sensitivity does not include any sites for which an early plant retirement has been announced.~~

For more information regarding accounting for nuclear decommissioning obligations, see Note 1 — Significant Accounting Policies, Note 8 — Early Nuclear Plant Retirements and Note 15 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements.

Goodwill (Exelon, ~~Generation,~~ ComEd, ~~PHI~~ and ~~DPL)~~PHI)

As of December 31, ~~2017,~~2022, Exelon’s ~~$6.7~~$6.6 billion carrying amount of goodwill ~~primarily~~ consists of $2.6 billion at ComEd ~~relating to the acquisition of ComEd in 2000 as part of the formation of Exelon~~ and $4 billion at PHI pursuant to Exelon's acquisition of PHI in the first quarter of 2016. DPL has $8 million of goodwill as of December 31, 2017, related to its 1995 acquisition of the Conowingo Power Company. Generation also has goodwill of $47 million as of December 31, 2017. Under the provisions of the authoritative guidance for goodwill, thesePHI. 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. ~~Under the authoritative guidance, a~~A reporting unit is an operating segment or one level below an operating segment (known as a component) and is the level at which goodwill is ~~tested~~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 and reporting unit. PHI’s operating segments and reporting units are Pepco, DPL, and ACE. See Note 255 — Segment Information of the Combined Notes to Consolidated Financial Statements 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~~Exelon's and ~~ACE operating segments are also considered reporting units for goodwill impairment testing purposes. Exelon’s and~~ ComEd’s ~~$2.6 billion of~~ goodwill has been assigned entirely to the ComEd reporting ~~unit, while Exelon’s~~unit. Exelon's and PHI’s ~~$4 billion of~~ goodwill has been assigned to the Pepco, DPL, and ACE reporting units in the amounts of ~~$1.7~~$2.1 billion, ~~$1.1~~$1.4 billion, and ~~$1.2~~$0.5 billion, respectively. ~~DPL's $8 million~~See Note 12 — Intangible Assets of ~~goodwill is assigned entirely~~the Combined Notes to ~~the DPL reporting unit.~~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. ~~In performing a~~As part of the qualitative ~~assessment, entities should assess,~~assessments, Exelon, ComEd, and PHI evaluate, among other things, ~~macroeconomic~~management's best estimate of projected operating and capital cash flows for their businesses, outcomes of recent regulatory proceedings, changes in certain market conditions, ~~industry~~including the discount rate and ~~market considerations including regulatory~~regulated utility peer EBITDA multiples, and ~~political developments, overall financial performance, cost factors, and entity-specific conditions and events. If an entity determines, on~~ the basis of qualitative factors, that the fair value of the reporting unit is more likely than not greater than the carrying amount, no further testing is required. If an entity bypasses the qualitative assessment, or performs the qualitative assessment but determines that it is more likely than not that its fair value is less than its carrying amount, apassing margin from their last quantitative ~~two-step, fair value-based test is~~assessments performed.

Exelon’s, ComEd’s and PHI’s accounting policy is to perform a quantitative test of goodwill at least once every three years, or more frequently if events occur or circumstances change that would more likely than not reduce the fair value of the reporting unit below its carrying amount. The first step in the quantitative test compares the fair value of the reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, the second step is performed. The second step requires an allocation of fair value to the individual assets and liabilities using purchase price allocation authoritative guidance in order to determine the implied fair value of goodwill. If the implied fair value of goodwill is less than the carrying amount, an impairment loss is recorded as a reduction to goodwill and a charge to operating expense. In January 2017, the FASB issued a new standard, effective January 1, 2020 with early adoption permitted, that simplifies the accounting for goodwill impairment by removing the second step of the test and, instead, measuring goodwill impairment at the amount by which a reporting unit's carrying value exceeds its fair value (currently the first step in the test). Exelon, Generation, ComEd, PHI and DPL have not determined whether to early adopt this standard.

Application of the goodwill impairment ~~test~~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,

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performance and transactions, and projected operating and capital cash flows for ComEd’s, Pepco's, DPL's, and ACE's businesses and the fair value of debt. ~~In applying the second step (if needed), management must estimate the fair value of specific assets and liabilities of the reporting unit.~~

For their 2017 annual goodwill impairment assessments, Exelon, ComEd, PHI and DPL each qualitatively determined that it was more likely than not that the fair value of their respective reporting unit exceeded their respective carrying value. Therefore, ComEd, PHI and DPL did not perform quantitative assessments. As part of their qualitative assessments, ComEd, PHI and DPL evaluated, 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 as of November 1, 2016.

ComEd, PHI and DPL performed quantitative tests as of November 1, 2016, for their 2016 annual goodwill impairment assessments. The first step of the tests comparing the estimated fair values of the ComEd, Pepco, DPL and ACE reporting units to their carrying values, including goodwill, indicated no impairments of goodwill; therefore, no second steps were required.

While the 2022 annual assessments indicated no impairments, certain assumptions used ~~to estimate reporting unit fair values~~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, ~~PHI’s~~ or ~~DPL’s~~PHI’s goodwill, which could be material. Based on the results of the annual goodwill tests performed as of November 1, 2016, the estimated fair values of the ComEd, Pepco, DPL and ACE reporting units would have needed to decrease by more than 30%, 10%, 10% and 10%, respectively, for Exelon, ComEd and PHI to have failed the first step of their respective impairment tests. For the $8 million of goodwill recorded at DPL related to DPL’s 1995 acquisition of the Conowingo Power Company, the fair value of the DPL reporting unit would have needed to decrease by more than 50% for DPL to fail the first step of the impairment test.

See Note 1 — Significant Accounting Policies and Note 1012 — Intangible Assets ~~and Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.~~

~~Purchase Accounting (Exelon, Generation and PHI)~~

In January 2017, the FASB issued a new standard, effective January 1, 2018 with early adoption permitted, that clarifies the definition of a business with the objective of addressing whether acquisitions/dispositions should be accounted for as acquisitions/dispositions of assets or as acquisitions/dispositions of businesses. The Registrants did not early adopt this new standard. See Note 1-Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for further information.

In accordance with authoritative guidance, the assets acquired and liabilities assumed in an acquired business are recorded at their estimated fair values on the date of acquisition. The difference between the purchase price amount and the net fair value of assets acquired and liabilities assumed is recognized as goodwill on the balance sheet if the purchase price exceeds the estimated net fair value or as a bargain purchase gain on the income statement if the purchase price is less than the estimated net fair value. Determining the fair value of assets acquired and liabilities assumed requires management’s judgment, often utilizes independent valuation experts and involves the use of significant estimates and assumptions with respect to the timing and amounts of future cash inflows and outflows, discount rates, market prices and asset lives, among other items. The judgments made in the determination of the estimated fair value assigned to the assets acquired and liabilities assumed, as well as the estimated useful life of each asset and the duration of each liability, could significantly impact the financial statements in periods after acquisition, such as through depreciation and amortization expense. Authoritative guidance provides that the allocation of the purchase price may be modified up to one year after the

~~acquisition date as more information is obtained about the fair value of assets acquired and liabilities assumed. See Note 4 — Mergers, Acquisitions and Dispositions~~ of the Combined Notes to Consolidated Financial Statements for additional information.

Unamortized Energy Contract ~~Assets and~~ Liabilities (Exelon ~~Generation~~ and PHI)

Unamortized energy contract ~~assets and~~ liabilities represent the remaining unamortized balances of non-derivative ~~energy~~electricity contracts that ~~Generation has acquired and the electricity contracts~~ Exelon ~~has~~ acquired as part of the PHI ~~acquisition.~~merger. The initial amount recorded represents the difference between the fair value of the contracts at the time of ~~acquisition. At PHI, offsetting~~acquisition and the contract value based on the terms of each contract. Offsetting regulatory assets ~~or liabilities~~ were also ~~recorded.~~recorded for those energy contract costs that are probable of recovery through customer rates. The unamortized energy contract ~~assets and~~ liabilities and ~~any~~the corresponding regulatory assets, ~~or liabilities,~~ respectively, are amortized over the life of the contract in relation to the expected realization of the underlying cash flows.Amortization of the unamortized energy contract ~~assets and~~ liabilities isare recorded through purchased power and fuel ~~expense or operating revenues, depending on the nature of the underlying contract. Refer to~~expense. See Note 3 — Regulatory Matters ~~Note 4 — Mergers, Acquisitions and Dispositions~~ and Note 1012 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for ~~further discussion.~~

~~Impairment of Long-lived Assets (All Registrants)~~

All Registrants regularly monitor and evaluate their long-lived assets and asset groups, excluding goodwill, for impairment when circumstances indicate the carrying value of those assets may not be recoverable. Indicators of potential impairment may include a deteriorating business climate, including declines in energy prices, condition of the asset, an asset remaining idle for more than a short period of time, specific regulatory disallowance, advances in technology or plans to dispose of a long-lived asset significantly before the end of its useful life, among others.

The review of long-lived assets and asset groups for impairment utilizes significant assumptions about operating strategies and estimates of future cash flows, which require assessments of current and projected market conditions. For the generation business, forecasting future cash flows requires assumptions regarding forecasted commodity prices for the sale of power and purchases of fuel and the expected operations of assets. A variation in the assumptions used could lead to a different conclusion regarding the recoverability of an asset or asset group and, thus, could have a significant impact on the consolidated financial statements. An impairment evaluation is based on an undiscounted cash flow analysis at the lowest level at which cash flows of the long-lived assets or asset groups are largely independent of the cash flows of other assets and liabilities. For the generation business, the lowest level of independent cash flows is determined by the evaluation of several factors, including the geographic dispatch of the generation units and the hedging strategies related to those units as well as the associated intangible assets or liabilities recorded on the balance sheet. The cash flows from the generating units are generally evaluated at a regional portfolio level with cash flows generated from the customer supply and risk management activities, including cash flows from related intangible assets and liabilities on the balance sheet. In certain cases, generating assets may be evaluated on an individual basis where those assets are contracted on a long-term basis with a third party and operations are independent of other generating assets (typically contracted renewables).

On a quarterly basis, Generation assesses its long-lived assets or asset groups for indicators of impairment. If indicators are present for a long-lived asset or asset group, a comparison of the undiscounted expected future cash flows to the carrying value is performed. When the undiscounted cash flow analysis indicates the carrying value of a long-lived asset or asset group is not recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset or asset group over its fair value. The fair value of the long-lived asset or asset group is dependent upon a market participant’s view of the exit price of the assets. This includes significant assumptions of the estimated future cash flows generated by the assets and market discount rates.

Events and circumstances often do not occur as expected and there will usually be differences between prospective financial information and actual results, and those differences may be material. The determination of fair value is driven by both internal assumptions that include significant unobservable inputs (Level 3) such as revenue and generation forecasts, projected capital, and maintenance expenditures and discount rates, as well as information from various public, financial and industry sources.

Generation evaluates its equity method investments and other investments in debt and equity securities to determine whether or not they are impaired based on whether the investment has experienced a decline in value that is not temporary in nature. Beginning January 1, 2018, the authoritative guidance eliminates the available-for-sale and cost method classifications for equity securities and requires that all equity investments (other than those accounted for using the equity method of accounting) be measured and recorded at fair value with any changes in fair value recorded through earnings. Investments in equity securities without readily determinable fair values must be qualitatively assessed for impairment each reporting period and fair value determined if any significant impairment indicators exist. If the fair value is less than the carrying value, the impairment is recorded through earnings immediately in the period in which it is identified without regard to whether the decline in value is temporary in nature. The new authoritative guidance does not impact the classification or measurement of investments in debt securities. See Note 1-Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for furtheradditional information.

~~See Note 7 — Impairment of Long-Lived Assets and Intangibles of the Combined Notes to Consolidated Financial Statements for a discussion of asset impairment evaluations made by Exelon.~~

Depreciable Lives of Property, Plant, and Equipment (All Registrants)

The Registrants have significant investments in ~~electric generation assets and~~ electric and natural gas transmission and distribution assets. These assets are generally depreciated on a straight-line basis, using the group, ~~composite~~ or ~~unitary~~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 ~~generally completed every five years, or more frequently if~~conducted periodically and as required by a rate regulator or ~~if an event,~~ regulatory action, or ~~change~~changes in retirement patterns indicate an update is necessary.

~~For the Utility Registrants, depreciation~~Depreciation studies generally serve as the basis for amounts allowed in customer rates for recovery of depreciation costs. Generally, the ~~Utility~~ Registrants adjust their depreciation rates for financial reporting purposes concurrent with adjustments to depreciation rates reflected in customer rates, unless the depreciation rates reflected in customer rates do not align with management’s judgment as to an appropriate estimated useful life or have not been updated on a timely basis. Depreciation expense and customer rates for ComEd, BGE, Pepco, DPL, and ACE ~~includes~~include an ~~estimated cost~~estimate of the future costs of dismantling and removing plant from service upon retirement. ~~Actual incurred~~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 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. Estimates for such removal costs are also evaluated in the periodic depreciation studies.

At Generation, along with depreciation study results, management considers expected future energy market conditions and generation plant operating costs and capital investment requirements in determining the estimated service lives of its generating facilities. See Note 8 — Early Nuclear Plant

~~Retirements of the Combined Notes to the Consolidated Financial Statements for additional information on expected and potential early nuclear plant retirements.~~

~~Generation completed a depreciation rate study during the first quarter of 2015, which resulted in revised depreciation rates effective January 1, 2015.~~

ComEd is required to file an electric distribution depreciation rate study at least every five years with the ICC. ComEd completed an electric distribution and transmission depreciation study and filed the updated depreciation rates with both the ICC and FERC in January 2014, resulting in new depreciation rates effective first quarter 2014.

PECO is required to file electric distribution and gas depreciation rate studies at least every five years with the PAPUC. In March 2015, PECO filed a depreciation rate study with the PAPUC for both its electric distribution and gas assets, resulting in new depreciation rates for electric transmission assets effective January 1, 2015, for gas distribution assets effective July 1, 2015, and for electric distribution assets effective January 1, 2016.

The MDPSC does not mandate the frequency or timing of BGE’s electric distribution or gas depreciation studies. In July 2014, BGE filed revised depreciation rates with the MDPSC for both its electric distribution and gas assets, which became effective December 15, 2014. In addition, BGE’s electric transmission depreciation rates were updated effective April 1, 2015.

The MDPSC does not mandate the frequency or timing of Pepco's electric distribution depreciation studies, while the DCPSC directs Pepco as to when it should file an electric distribution depreciation study. In 2016 and 2013, Pepco filed revised electric distribution depreciation rates with the MDPSC and DCPSC, respectively, with the new rates effective November 15, 2016 and April 16, 2014, respectively. On December 19, 2017, Pepco filed an electric distribution rate application which included revised depreciation rates. Pepco expects a decision in the fourth quarter of 2018.

Neither the DPSC nor the MDPSC mandates the frequency or timing of DPL's electric distribution or gas depreciation studies. On July 20, 2016, DPL filed revised electric depreciation rates with the MDPSC as part of the electric distribution base rate filing, resulting in new depreciation rates effective on April 20, 2017. On May 17, 2016, DPL filed revised electric and natural gas depreciation rates with the DPSC as part of the electric and natural gas base rate case filing, resulting in new electric depreciation rates effective June 1, 2017 and new gas depreciation rates effective July 1, 2017.

The NJBPU does not mandate the frequency or timing of ACE's electric distribution depreciation studies. In 2012, ACE filed revised electric distribution depreciation rates with the NJBPU, with the new rates effective July 1, 2013. ACE expects to perform an electric distribution depreciation study in 2018.

While FERC does not mandate the frequency or timing of electric transmission depreciation studies, the Utility Registrants and Generation perform studies on all assets every 5 years. Pepco, DPL and ACE last performed transmission depreciation studies in 1988, 1990, and 2003, respectively, but are adopting Exelon's practice and are currently evaluating the timing of the next study.

Changes in estimated useful lives ~~of electric generation assets and~~ of electric and natural gas transmission and distribution assets could have a significant impact on the Registrants’ future results of operations. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for information regarding depreciation and estimated service lives of the property, plant, and equipment of the Registrants.

~~Defined Benefit Pension and Other Postretirement Employee~~Retirement Benefits (All Registrants)

Exelon sponsors defined benefit pension plans and ~~other postretirement employee benefit~~OPEB plans for substantially all current employees. ~~See Note 16 — Retirement Benefits of the Combined Notes to~~

~~Consolidated Financial Statements for additional information regarding the accounting for the defined benefit pension plans and other postretirement benefit plans.~~

The measurement of the plan obligations and costs of providing benefits involves various factors, including the development of valuation assumptions and inputs and accounting policy elections. When developing the required assumptions, Exelon considers historical information as well as future expectations. The measurement of benefit obligations and costs is affected by several assumptions including the discount rate, ~~applied to benefit obligations,~~ the long-term expected rate of return on plan assets, the anticipated rate of increase of health care costs, ~~Exelon’s expected level of~~Exelon's contributions, to the ~~plans, the incidence of participant mortality, the expected remaining service period of plan participants, the level of compensation and~~ rate of

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compensation increases, ~~employee age, length of service,~~ and the long-term expected investment rate credited to employees of certain plans, among others. The assumptions are updated annually and upon any interim remeasurement of the plan obligations. Exelon amortizes actuarial gains or losses in excess of a corridor of 10% of the greater of the projected benefit obligation or the market-related value (MRV) of plan assets over the expected average remaining service period of plan participants. Pension and other postretirement benefit costs attributed to the operating companies are labor costs and are ultimately allocated to projects within the operating companies, some of which are capitalized.

Pension and ~~other postretirement benefit~~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. See Note 16 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for information on fair value measurements of pension and other postretirement plan assets, including valuation techniques and classification under the fair value hierarchy in accordance with authoritative guidance.

Expected Rate of Return on Plan ~~Assets~~

Assets. In determining the EROA, Exelon considers historical economic indicators (including inflation and GDP growth) that impact asset returns, as well as expectation regarding future long-term capital market performance, weighted by Exelon’s target asset class allocations. Exelon calculates the amount of expected return on pension and ~~other postretirement benefit~~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 ~~other postretirement benefit~~OPEB plan assets and certain pension plan assets, Exelon uses fair value to calculate the MRV. ~~See Note 16 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for further information regarding Exelon’s EROA assumptions.~~

Discount ~~Rate~~

~~At December 31, 2017 and 2016, the~~Rate. The discount rates ~~were~~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 ~~other postretirement benefit~~OPEB obligations. The spot rates are used to discount the estimated future benefit distribution amounts under the pension and ~~other postretirement benefit~~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. ~~See Note 16 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for further information regarding Exelon’s discount rate assumptions.~~

~~Health Care Cost Trend Rate~~

Assumed health care cost trend rates impact the costs reported for Exelon’s other postretirement benefit plans for participant populations with plan designs that do not have a cap on cost growth. Authoritative guidance requires that annual health care cost estimates be developed using past and present health care cost trends (both for Exelon and across the broader economy), as well as expectations of health care cost escalation, changes in health care utilization and delivery patterns, technological advances and changes in the health status of plan participants. Therefore, the trend rate assumption is subject to significant uncertainty. Exelon assumes an ultimate health care cost trend rate of 5.00% has been reached in 2017 for its other postretirement benefit plans.

~~Mortality~~

Mortality. The mortality assumption is composed of a base table that represents the current expectation of life expectancy of the population adjusted by an improvement scale that attempts to anticipate future improvements in life expectancy. Exelon’s mortality assumption ~~is supported by an actuarial experience study of Exelon's plan participants and~~ utilizes the ~~IRS's RP-2000~~SOA 2019 base table (Pri-2012) and ~~the Scale BB 2-Dimensional~~MP-2021 improvement scale ~~with long-term improvements of 0.75%.~~adjusted to use Proxy SSA ultimate improvement rates.

Sensitivity to Changes in Key ~~Assumptions~~

Assumptions. The following tables illustrate the effects of changing certain of the actuarial assumptions discussed above, while holding all other assumptions ~~constant (dollars in millions):~~constant:

Actual Assumption
Actuarial Assumption Pension OPEB
Change in
Assumption
Pension OPEB Total
Change in 2017 cost:
Discount rate ^(a)
4.04% 4.04% 0.5% $ (72 ) $ (16 ) $ (88 )
4.04% 4.04% (0.5)% 89
19
108
EROA 7.00% 6.58% 0.5% (85 ) (12 ) (97 )
7.00% 6.58% (0.5)% 85
12
97
Health care cost trend rate NA 5.00% 1.00% N/A
9
9
NA 5.00% (1.00)% N/A
(8 ) (8 )
Change in benefit obligation at December 31, 2017:
Discount rate ^(a)
3.62% 3.61% 0.5% (1,183 ) (252 ) (1,435 )
3.62% 3.61% (0.5)% 1,371
291
1,662
Health care cost trend rate NA 5.00% 1.00% N/A
125
125
NA 5.00% (1.00)% N/A
(113 ) (113 )


	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 other postretirement benefit cost and obligation as the rate moves closer to 0%. Therefore, the discount rate sensitivities above cannot necessarily be extrapolated for larger increases or decreases in the discount rate. Additionally, Exelon utilizes a liability-driven investment strategy for its pension asset portfolio. The sensitivities shown above do not reflect the offsetting impact that changes in discount rates may have on pension asset returns.

(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.

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Regulatory Accounting ~~(Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE)~~(All Registrants)

~~Exelon and the Utility Registrants account for~~For their regulated electric and gas operations, ~~in accordance with~~ the ~~authoritative guidance, which requires Exelon and the Utility~~ Registrants to reflect the effects of cost-based rate regulation in their financial ~~statements. This authoritative guidance~~statements, which is

~~applicable to~~ 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. ~~As of December 31, 2017, Exelon and the Utility Registrants have concluded that the operations of each such Registrant meet the criteria to apply the authoritative guidance.~~ If it is concluded in a future period that a separable portion of operations no longer meets the criteria ~~of this authoritative guidance, Exelon and~~discussed above, the ~~Utility~~ Registrants would be required to eliminate any associated regulatory assets and liabilities and the impact, which could be material, would be recognized in the Consolidated Statements of Operations and Comprehensive ~~Income and~~Income.

The following table illustrates gains (losses) to be included in net income that could be material. At December 31, 2017, the gain (loss) could have been as much as $1.1 billion, $5.3 billion, $280 million, $592 million, $(1.1) billion, $(59) million, $321 million and $(8) million (before taxes) as a result offrom 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 ~~Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively. Further, Exelon would record a~~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 ~~$3.8~~$1.9 billion, ~~$2.4 billion, $544~~$347 million,~~$177~~ $492 million, ~~$407~~$279 million, ~~$202~~$113 million, and ~~$92~~$59 million related to ~~Exelon's,~~ ComEd's, BGE's, PHI's, Pepco's, DPL's, and ACE's respective portions of the deferred costs associated with Exelon's pension and ~~other postretirement benefit plans that are recorded as regulatory assets on Exelon's Consolidated Balance Sheets.~~OPEB plans. Exelon also has a net regulatory liability of ~~$(31)~~$115 million (before taxes) related to PECO’s portion of the deferred costs associated with Exelon’s ~~other postretirement benefit~~OPEB plans that would result in an increase in OCI if reversed.

See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information regarding regulatory matters, including the regulatory assets and liabilities ~~tables~~ of ~~Exelon and~~ the ~~Utility~~ Registrants.

For each regulatory jurisdiction in which they conduct business, ~~Exelon and~~ the ~~Utility~~ Registrants assess whether the regulatory assets and liabilities continue to meet the criteria for probable future recovery or ~~settlement~~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. ~~Furthermore, each Registrant makes other judgments related to~~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 ~~statement impact of their regulatory environments, such as the types of adjustments to rate base that will~~statements could be ~~acceptable to regulatory bodies, if any, for which costs will be recoverable through rates.~~ 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 ComEd, PECO, BGE, Pepco, DPL and ACE. Additionally, estimates are made in accordance with the authoritative guidance for contingencies as to the amount of revenues billed under certain regulatory orders that may ultimately be refunded to customers upon finalization of applicable regulatory or judicial processes. These assessments are based, to the extent possible, on past relevant experience with regulatory bodies in each Registrant's jurisdictions, known circumstances specific to a particular matter and hearings held with the applicable regulatory body. If the assessments and estimates made by Exelon and the Utility Registrants for regulatory assets and regulatory liabilities are ultimately different than actual regulatory outcomes, the impact on their results of operations, cash flows and financial positions could be material.Registrants.

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.

~~Accounting for~~ Derivative Financial Instruments (All Registrants)

The Registrants use derivative instruments to manage commodity price risk ~~foreign currency exchange risk~~ and interest rate risk related to ongoing business operations. ~~The Registrants’ derivative activities are in accordance with Exelon’s Risk Management Policy (RMP).~~ See Note 1215 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional ~~information regarding the Registrants’ derivative instruments.~~information.

~~The Registrants account for derivative financial instruments under the applicable authoritative guidance.~~ Determining whether a contract qualifies as a derivative requires that management exercise significant judgment, including assessing market liquidity as well as determining whether a contract has one or more ~~underlyings~~underlying and one or more notional quantities. Changes in management’s assessment of contracts and the liquidity of their markets, and changes in authoritative guidance, could result in previously excluded contracts becoming in scope to new authoritative guidance. Generation has determined that contracts to purchase uranium, contracts to purchase and sell capacity in certain ISO’s, certain emission products, ZECs and RECs do not meet the definition of a derivative as they do not provide for net settlement and the uranium, certain capacity, emission and ZEC and REC markets are not sufficiently liquid to conclude that physical forward contracts are readily convertible to cash. If these markets become sufficiently liquid, then Generation would be required to account for these contracts as derivative instruments. In this case, if market prices differ from the underlying prices of the contracts, Generation would be required to record mark-to-market gains or losses, which could have a material impact to Exelon’s and Generation’s results of operations and financial positions.

~~Under current authoritative guidance, all~~All derivatives are recognized on the balance sheet at their fair value, except for certain derivatives that qualify for, and are elected under, ~~the normal purchases and normal sales exception. Further,~~NPNS. For derivatives that qualify and are designated ~~for hedge accounting are classified~~ as ~~either fair value or~~ cash flow ~~hedges. For fair value~~ hedges, changes in fair ~~values for both the derivative~~value each period are initially recorded in AOCI and ~~the underlying hedged exposure are~~ recognized in earnings ~~immediately. For cash flow hedges, the portion of the derivative gain or loss that is effective in offsetting the change in~~when the hedged ~~cash flows~~transaction

Table of the underlying exposure is deferred in AOCI and reclassified into earnings when the underlying transaction occurs. Gains and losses from the ineffective portion of any hedge are recognized in earnings immediately. The Registrants rarely elect hedge accounting for commodity transactions. Economic commodity hedges are recorded at fair value throughContents

affects earnings. ~~In addition, for commodity~~For derivatives ~~executed for proprietary trading purposes, changes in the fair value of the derivatives are recognized in earnings immediately. For~~intended to serve as economic hedges, ~~that~~which are not designated for hedge accounting, ~~for the Utility Registrants,~~ changes in ~~the~~ fair value each period are ~~generally~~recognized in earnings on the Consolidated Statement of Operations and Comprehensive Income or are recorded ~~with~~as a ~~corresponding offsetting~~ regulatory asset or liability ~~given likelihood of recovering~~when there is an ability to recover or return the associated costs ~~through customer rates.~~or benefits in accordance with regulatory requirements.

~~Normal Purchases and Normal Sales Exception~~

As part of Generation’s energy marketing business, Generation enters into contracts to buy and sell energy to meet the requirements of its customers. These contracts include short-term and long-term commitments to purchase and sell energy and energy-related products in the retail and wholesale markets with the intent and ability to deliver or take delivery. While some of these contractsNPNS. Contracts that are ~~considered derivative financial instruments under the authoritative guidance, certain of these qualifying transactions have been~~ designated ~~by Generation~~ as ~~normal purchases and normal sales transactions, which~~NPNS are ~~thus~~ not required to be recorded at fair value, but rather on an accrual basis of accounting. Determining whether a contract qualifies for ~~the normal purchases and normal sales exception~~NPNS requires judgment on whether the contract will physically deliver and requires that management ensure compliance with all of the associated qualification and documentation requirements. ~~Revenues~~For all NPNS derivative instruments, accounts payable is recorded when derivatives settle and ~~expenses on contracts that qualify~~expense is recognized in earnings as ~~normal purchases and normal sales are recognized when~~ the underlying physical ~~transaction~~commodity is ~~completed.~~consumed. Contracts that qualify for ~~the normal purchases and normal sales exception~~

NPNS are those for which physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable period, ~~of time~~ and the contract is not financially settled on a net basis. The contracts that ComEd has entered into with suppliers as part of ComEd’s energy procurement process, PECO’s full requirement contracts under the PAPUC-approved DSP program, most of PECO’s natural gas supply agreements, all of BGE’s full requirement contracts and natural gas supply agreements that are derivatives, and certain Pepco, DPL, and ACE full requirement contracts qualify for and are accounted for under ~~the normal purchases and normal sales exception.~~NPNS.

Commodity ~~Contracts~~

Identification of a commodity contract as an economic hedge requires Generation to determine that the contract is in accordance with the RMP. Generation reassesses its economic hedges on a regular basis to determine if they continue to be within the guidelines of the RMP.

~~As a part of the authoritative guidance, the~~Contracts. The Registrants make estimates and assumptions concerning future commodity prices, ~~load requirements,~~ interest rates, and the timing of future transactions and their probable cash flows ~~the fair value of contracts and the expected changes in the fair value~~ in deciding whether ~~or not~~ to enter ~~into~~ derivative transactions, and in determining the initial accounting treatment for derivative transactions. ~~Under the authoritative guidance for fair value measurements, the~~The Registrants categorize these derivatives under a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value.

Derivative contracts ~~are~~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 ~~derivatives’~~derivative pricing is verified using indicative price quotations available through brokers or over-the-counter, ~~on-line~~online exchanges. The price quotations reflect the average of the bid-ask mid-point from markets that the Registrants believe provide the most liquid market for the commodity. The price quotations are reviewed and corroborated to ensure the prices are observable and representative of an orderly transaction between market participants. The Registrant’s derivatives are traded predominately at liquid trading points. The remaining derivative contracts are valued using models that consider inputs such as contract terms, including maturity, and market parameters, and assumptions of the future prices of energy, interest rates, volatility, credit worthiness and credit spread. For derivatives that trade in liquid markets, ~~such as generic forwards, swaps and options,~~ the model inputs are generally observable. Such instruments are categorized in Level 2.

For derivatives that trade in less liquid markets with limited pricing information, the model inputs generally would include both observable and unobservable inputs and are categorized in Level 3.

The Registrants consider nonperformance risk, including credit risk in the valuation of derivative contracts, ~~including~~and both historical and current market data in ~~its~~the assessment of nonperformance ~~risk, including credit~~ risk. The impacts of nonperformance and credit risk to date have generally not been material to the Registrants’ financial statements.

Interest Rate ~~and Foreign Exchange~~ Derivative ~~Instruments~~

~~The Registrants may utilize fixed-to-floating~~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 ~~typically designated as fair value hedges,~~directly correlated to achieve the targeted level of variable-rate debt as a percent of total debt. Additionally, the Registrants may use forward-starting interest rate swaps and treasury rate locks to lock in interest-rate levels and floating to fixed swaps for project financing. In addition, Generation enters into interest rate derivative contracts to economically hedge risk associated with the interest rate component of commodity positions. The characterization of the interest rate derivative contracts between the economic hedge and proprietary trading activity is driven by the corresponding characterization of the underlying

commodity position that gives rise to the interest rate exposure. Generation does not utilize interest rate derivatives with the objective of benefiting from shifts or changes in market interest rates. To manage foreign exchange rate exposure associated with international energy purchases in currencies other thanyields on U.S. ~~dollars, Generation utilizes foreign currency derivatives, which are typically designated as economic hedges.~~Treasury bonds under ComEd's distribution formula rate. The fair value of the ~~agreements~~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 ~~inputs~~data and valuations of similar instruments, the interest rate derivatives are primarily categorized in Level 2 in the fair value hierarchy. ~~Certain exchange based interest rate derivatives that are valued using unadjusted quoted prices in active markets are categorized in Level 1 in the fair value hierarchy.~~

See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK and Note 1117 — Fair Value of Financial Assets and Liabilities and Note 1215 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding the Registrants’ derivative instruments.

~~Taxation~~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. ~~In accordance with applicable authoritative guidance, the~~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. 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. 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

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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 ~~evaluate for~~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, such as historical operating loss or tax credit carryforward expiration.~~assets. Based on the combined assessment, the Registrants record valuation allowances for deferred tax assets when ~~they conclude~~ 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. The Registrants have recorded the provisional income tax amounts as of December 31, 2017 for changes pursuant to the TCJA related to depreciation for which the impacts could not be finalized upon issuance of the Registrants' financial statements, but for which reasonable estimates could be determined. In accordance with SAB 118, additional remeasurement may occur based on technical corrections or other forms of guidance issued, which may result in material changes to previously finalized provisions. While the Registrants believe the resulting tax balances as of December 31, 2017 and 2016 are appropriately accounted for in accordance with the applicable authoritative guidance, the ultimate outcome of tax matters could result in favorable or unfavorable adjustments that could be material to their consolidated financial statements. See Note 1413 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional ~~information regarding taxes.~~

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 onin the Registrants' consolidated financial statements.

Environmental ~~Costs~~

Costs. Environmental investigation and remediation liabilities are based upon estimates with respect to the number of sites for which the Registrants will be responsible, the scope and cost of work to be performed at each site, the portion of costs that will be shared with other parties, the timing of the remediation work, ~~and changes in technology,~~ regulations, and the requirements of local governmental authorities. ~~Periodic~~Annual studies and/or reviews are conducted at ~~the Utility Registrants~~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 onin the Registrants’ ~~results of operations, cash flows and~~consolidated financial ~~positions.~~statements. See Note 2318 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for ~~further~~additional information.

Other, Including Personal Injury ~~Claims~~

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 onto the Registrants’ ~~results of operations, cash flows and~~consolidated financial ~~positions.~~statements.

~~Revenue Recognition~~Revenues (All Registrants)

Sources of Revenue and Determination of Accounting ~~Treatment~~

Treatment. The Registrants earn revenues from ~~various business activities including: the sale of energy and energy-related products, such as natural gas, capacity, and other commodities in non-regulated markets (wholesale and retail)~~;the sale and delivery of ~~electricity~~power and natural gas in regulated ~~markets; and the provision of other energy-related non-regulated products and services.~~

markets. The accounting treatment for revenue recognition is based on the nature of the underlying transaction and applicable authoritative guidance. The Registrants primarily ~~use accrual, mark-to-market,~~apply the Revenue from Contracts with Customers, and Alternative Revenue Program ~~(ARP)~~ accounting guidance to recognize revenues as discussed in more detail below. ~~Beginning on January 1, 2018, the Registrants will begin applying the~~

Revenue from Contracts with ~~Customers guidance to recognize revenue. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional information.~~

~~Accrual Accounting~~

~~Under accrual accounting, the~~Customers. The Registrants recognize revenues in the period in which the performance obligations within contracts with customers are satisfied, which generally occurs when ~~services~~power and natural gas are ~~rendered or energy is~~physically delivered to ~~customers. The~~the customer. Transactions of the Registrants within the scope of Revenue from Contracts with Customers generally use accrual accounting to recognize revenues for sales of electricity, natural gas and other commodities as part of their physical delivery activities. The Registrants enter into these sales transactions using a variety of instruments,

~~including non-derivative agreements, derivatives that qualify for and are designated as normal purchases and normal sales (NPNS) of commodities that will be physically delivered,~~include sales to utility customers under regulated service ~~tariffs and spot-market sales, including settlements with independent system operators.~~tariffs.

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The determination of ~~Generation's~~the Registrants' power and ~~the Utility Registrants' energy~~natural gas sales to individual customers is based on systematic readings of customer meters, generally ~~on a monthly basis.~~monthly. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated, and corresponding unbilled revenue is recorded. The measurement of unbilled revenue is affected by the following factors: daily customer usage measured by ~~energy~~generation or gas throughput volume, customer usage by class, losses of energy during delivery to customers and applicable customer rates. Increases or decreases in volumes delivered to the ~~utilities'~~Registrant’s customers and favorable or unfavorable rate mix due to changes in usage patterns in ~~customers~~customer classes in the period could be significant to the calculation of unbilled revenue. In addition, ~~unbilled~~ revenues may fluctuate monthly as a result of customers electing to use an ~~alternate~~alternative supplier, since unbilled commodity ~~receivables~~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,~~revenue; however, total operating revenues would remain materially unchanged. See Note 51 — ~~Accounts Receivable~~Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional ~~information on unbilled revenue.~~information.

~~Mark-to-Market Accounting~~

The Registrants record revenues and expenses using the mark-to-market method of accounting for transactions that meet the definition of a derivative for which they are not permitted, or have not elected, the NPNS exception. These mark-to-market transactions primarily relate to commodity price risk management activities. Mark-to-market revenues and expenses include: inception gains or losses on new transactions where the fair value is observable and realized; and unrealized gains and losses from changes in the fair value of open contracts.

Alternative Revenue Program ~~Accounting~~

Accounting. Certain of the ~~Utility Registrants'~~Registrants’ ratemaking mechanisms qualify as ARPs if they ~~meet certain criteria. At each balance sheet date,~~(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 ~~Utility Registrants with such mechanisms, including ComEd's electric distribution~~price of utility service) that are objectively determinable and ~~energy efficiency formulas,~~probable of recovery, and ~~ComEd's, PECO's, BGE's, Pepco's, DPL's, and ACE's FERC transmission formula rates, record ARP~~(iii) allow for the collection of those additional revenues ~~for any differences between~~within 24 months following the ~~prior year revenue requirement in effect in rates and their best estimate~~end of the ~~current year~~period in which they were recognized. For mechanisms that meet these criteria, which include the Registrants’ formula rate mechanisms and revenue requirement that is probable of approval by the ICC or FERC. Estimates of the current year revenue requirement are based on actual and/or forecasted costs and investment in rate base for the period and the rates of return on common equity and associated regulatory capital structure allowed under the applicable tariff. ComEd, BGE, Pepco, and DPL also have decoupling mechanisms, ~~which qualify as ARPs. The Utility~~the Registrants ~~recognize~~adjust revenue and record an offsetting regulatory asset or liability once the condition or event allowing ~~for~~additional billing or refund has occurred. The ARP revenues presented in the ~~automatic adjustment~~Registrants’ Consolidated Statements of ~~future rates occurs.~~

~~The Utility Registrants’ ARP revenues~~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 ~~further~~additional information.

Allowance for ~~Uncollectible~~Credit Losses on Customer Accounts Receivable (All Registrants)

The allowance for uncollectible accounts reflects the Registrants’ best estimates of losses on the accounts receivable balances. For Generation, the allowance is based on accounts receivable aging historical experience and other currently available information. ComEd, PECO, BGE, Pepco, DPL and ACE,Registrants estimate the allowance for ~~uncollectible accounts~~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.~~history and represent expected, future customer behavior. Loss rates applied to the accounts receivable balances are based on a historical average of charge-offs as a percentage of accounts receivable in each risk segment. The ~~Utility~~ Registrants' customer accounts are generally considered delinquent if the amount billed is not received by the time the next bill is issued, which normally occurs on a monthly basis. ~~Utility~~The Registrants' customer accounts are written off consistent with approved regulatory requirements. ~~Utility~~The Registrants' allowances for ~~uncollectible accounts~~credit losses will continue to be affected by changes in volume, prices, and economic conditions as well as changes in ICC, PAPUC, MDPSC, DCPSC, ~~DPSC~~DEPSC, and NJBPU regulations. ~~See Note 5 — Accounts Receivable~~

Table of ~~the Combined Notes to Consolidated Financial Statements for additional information regarding accounts receivable.~~Contents

ComEd

Results of Operations by ~~Business Segment~~

The comparisons of operating results and other statistical information for the years ended December 31, 2017, 2016 and 2015 set forth below include intercompany transactions, which are eliminated in Exelon’s consolidated financial statements.

~~Net Income (Loss) Attributable to Common Shareholders by~~ Registrant

For the Years Ended December 31, Favorable (unfavorable) 2017 vs. 2016 variance For the Year Ended December 31, 2015 Favorable (unfavorable) 2016 vs. 2015 variance
2017 2016
Exelon $ 3,770
$ 1,134
$ 2,636
$ 2,269
$ (1,135 )
Generation 2,694
496
2,198
1,372
(876 )
ComEd 567
378
189
426
(48 )
PECO 434
438
(4 ) 378
60
BGE 307
286
21
275
11
Pepco 205
42
163
187
(145 )
DPL 121
(9 ) 130
76
(85 )
ACE 77
(42 ) 119
40
(82 )

Successor Predecessor
For the Year Ended December 31, 2017 March 24, 2016 to December 31, 2016 January 1, 2016 to March 23, 2016 For the Year Ended December 31, 2015
PHI $ 362
$ (61 ) $ 19
$ 327

Results of Operations—~~Generation~~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

2017 2016 Favorable (unfavorable) 2017 vs. 2016 variance 2015 Favorable (unfavorable) 2016 vs. 2015 variance
Operating revenues $ 18,466
$ 17,751
$ 715
$ 19,135
$ (1,384 )
Purchased power and fuel expense 9,690
8,830
(860 ) 10,021
1,191
Revenues net of purchased power
and fuel expense^(a)
8,776

8,921
(145 )
9,114

(193 )
Other operating expenses

Operating and maintenance 6,291
5,641
(650 ) 5,308
(333 )
Depreciation and amortization 1,457
1,879
422
1,054
(825 )
Taxes other than income 555
506
(49 ) 489
(17 )
Total other operating expenses 8,303

8,026
(277 )
6,851

(1,175 )
Gain (Loss) on sales of assets 2
(59 ) 61
12
(71 )
Bargain purchase gain 233
—
233
—
—
Gain on deconsolidation of business 213
—
213
—
—
Operating income 921

836

85

2,275

(1,439 )
Other income and (deductions)
Interest expense (440 ) (364 ) (76 ) (365 ) 1
Other, net 948
401
547
(60 ) 461
Total other income and (deductions) 508

37

471

(425 )
462
Income before income taxes 1,429

873

556

1,850

(977 )
Income taxes (1,375 ) 290
1,665
502
212
Equity in losses of unconsolidated affiliates (33 ) (25 ) (8 ) (8 ) (17 )
Net income 2,771

558

2,213

1,340

(782 )
Net income (loss) attributable to noncontrolling interests 77
62
15
(32 ) 94
Net income attributable to membership interest $ 2,694

$ 496

$ 2,198

$ 1,372

$ (876 )

~~__________~~

~~(a)~~

Generation evaluates its operating performance using the measure of revenues net of purchased power and fuel expense. Generation believes that revenues net of purchased power and fuel expense is a useful measurement because it provides information that can be used to evaluate its operational performance. Revenues net of purchased power and fuel expense 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.

~~Net Income Attributable to Membership Interest~~

Year Ended December 31, ~~2017~~2022 Compared to Year Ended December 31, ~~2016.Generation's~~ 2021.Net income ~~attributable to membership interest~~ increased ~~compared to the same period in 2016,~~by $175 million primarily due to ~~lower Depreciation~~increases in electric distribution and ~~amortization, a Bargain purchase gain in 2017, a Gain on deconsolidation of business in 2017,~~energy efficiency formula rate earnings (reflecting higher Other income and decreased Income taxes, partially offset by lower Revenues net of purchased power and fuel expense and higher Operating and maintenance expense. The decrease in Depreciation and amortization expense is primarilyallowed ROE due to lower accelerated depreciation and amortization as a result of the 2017 decision to early retire the TMI nuclear facility compared to the previous decision in 2016 to early retire Clinton and Quad Cities nuclear facilities. The Bargain purchase gain is due to the acquisition of the FitzPatrick nuclear facility. The Gain on deconsolidation of business in 2017 is due to the deconsolidation of EGTP's net liabilities, which included the previously impaired assets and related debt, as a result of the November 2017 bankruptcy filing. Thean increase in ~~Other income is primarily due to higher realized NDT fund gains. The decrease in Income taxes primarily relates to the one-time non-cash impacts associated with the Tax Cuts~~U.S. Treasury rates and ~~Jobs Act. The decrease in Revenues net of purchased power and fuel expense primarily reflects lower realized energy prices,~~ the impacts of lower load volumes delivered due to mild weather in the third quarter 2017, the conclusion of the Ginna Reliability Support Services Agreement and the impact of declining natural gas prices on Generation’s natural gas portfolio, partially offset by the impact of the New York CES, higher capacity prices, the addition of two combined-cycle gas turbines in Texas and lower nuclear fuel prices. The increase in Operating and maintenance expense is primarily related to the impairment of EGTP in 2017.rate base).

~~Year Ended December 31, 2016 Compared to Year Ended December 31, 2015.~~Generation's Net income attributable to membership interest decreased compared to the same period in 2015, primarily due to lower Revenues net of purchased power and fuel expense, higher Operating and maintenance expense, higher Depreciation and amortization expense, and Losses on sales of assets in 2016, partially offset by increased Other income and decreased Income tax expense. The decrease in Revenues net of purchased power and fuel expense primarily relates to lower mark-to-market results in 2016 compared to 2015 and lower realized energy prices, partially offset by the Ginna Reliability Support Services Agreement and a decrease in outage days at higher capacity units despite an increase in overall outage days. The increase in Operating and maintenance expense is primarily related to the impairment of Upstream assets and certain wind projects, and increased costs related to the implementation of the cost management program. The increase in Depreciation and amortization expense is primarily related to accelerated depreciation and amortization expense related to the previous decision to early retire the Clinton and Quad Cities nuclear generating facilities, increased nuclear decommissioning amortization and increased depreciation expense due to ongoing capital expenditures. The increase in Losses on sales of assets is primarily due to Generation's strategic decision to narrow the scope and scale of its growth and development activities. The increase in Other income is primarily due to the change in realized and unrealized gains and losses on NDT funds.

~~Revenues Net of Purchased Power and Fuel Expense~~

The basis for Generation’s reportable segments is the integrated management of its electricity business that is located in different geographic regions, and largely representative of the footprints of ISO/RTO and/or NERC regions, which utilize multiple supply sources to provide electricity through various distribution channels (wholesale and retail). Generation's hedging strategies and risk metrics are also aligned with these same geographic regions. Descriptions of each of Generation’s six reportable segments are as follows:

~~Mid-Atlantic~~ ~~represents operations in the eastern half of PJM, which includes New Jersey, Maryland, Virginia, West Virginia, Delaware, the District of Columbia and parts of Pennsylvania and North Carolina.~~

~~Midwest~~ represents operations in the western half of PJM, which includes portions of Illinois, Pennsylvania, Indiana, Ohio, Michigan, Kentucky and Tennessee, and the United States footprint of MISO excluding MISO’s Southern Region, which covers all or most of North Dakota, South Dakota, Nebraska, Minnesota, Iowa, Wisconsin, the remaining parts of Illinois, Indiana, Michigan and Ohio not covered by PJM, and parts of Montana, Missouri and Kentucky.

~~New England~~ ~~represents the operations within ISO-NE covering the states of Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island and Vermont.~~

~~New York~~ ~~represents operations within ISO-NY, which covers the state of New York in its entirety.~~

~~ERCOT~~ ~~represents operations within Electric Reliability Council of Texas, covering most of the state of Texas.~~

~~Other Power Regions~~:

~~South~~ represents operations in the FRCC, MISO’s Southern Region, and the remaining portions of the SERC not included within MISO or PJM, which includes all or most of Florida, Arkansas, Louisiana, Mississippi, Alabama, Georgia, Tennessee, North Carolina, South Carolina and parts of Missouri, Kentucky and Texas. Generation’s South region also includes operations in the SPP, covering Kansas, Oklahoma, most of Nebraska and parts of New Mexico, Texas, Louisiana, Missouri, Mississippi and Arkansas.

~~West~~ represents operations in the WECC, which includes California ISO, and covers the states of California, Oregon, Washington, Arizona, Nevada, Utah, Idaho, Colorado, and parts of New Mexico, Wyoming and South Dakota.

~~Canada~~ ~~represents operations across the entire country of Canada and includes the AESO, OIESO and the Canadian portion of MISO.~~

The following business activities are not allocated to a region, and are reported under Other: natural gas, as well as other miscellaneous business activities that are not significant to Generation's overall operating revenues or results of operations. Further, the following activities are not allocated to a region, and are reported in Other: amortization of certain intangible assets relating to commodity contracts recorded at fair value from mergers and acquisitions; accelerated nuclear fuel amortization associated with nuclear decommissioning; and other miscellaneous revenues.

Generation evaluates the operating performance of electric business activities using the measure of Revenue net of purchased power and fuel expense, which is a non-GAAP measurement. Generation’s operating revenues include all sales to third parties and affiliated sales to the Utility Registrants. Purchased power costs include all costs associated with the procurement and supply of electricity including capacity, energy and ancillary services. Fuel expense includes the fuel costs for owned generation and fuel costs associated with tolling agreements.

~~For the years ended December 31, 2017 compared to 2016 and December 31, 2016 compared to 2015, Generation’s Revenue net of purchased power and fuel expense by region were as follows:~~

2017 vs. 2016 2016 vs. 2015
2017 2016 Variance % Change 2015 Variance % Change
Mid-Atlantic^(a)
$ 3,214
$ 3,317
$ (103 ) (3.1 )% $ 3,571
$ (254 ) (7.1 )%
Midwest^(b)
2,820
2,971
(151 ) (5.1 )% 2,892
79
2.7 %
New England 514
438
76
17.4 % 461
(23 ) (5.0 )%
New York^(d)
976
742
234
31.5 % 634
108
17.0 %
ERCOT 332
281
51
18.1 % 293
(12 ) (4.1 )%
Other Power Regions 305
336
(31 ) (9.2 )% 250
86
34.4 %
Total electric revenues net of purchased power and fuel expense 8,161

8,085

76
0.9 % 8,101

(16 ) (0.2 )%
Proprietary Trading 18
15
3
n.m.
1
14
n.m.
Mark-to-market gains (losses) (175 ) (41 ) (134 ) 326.8 % 257
(298 ) (116.0 )%
Other^(c)
772
862
(90 ) (10.4 )% 755
107
14.2 %
Total revenue net of purchased power and fuel expense $ 8,776

$ 8,921

$ (145 ) (1.6 )% $ 9,114

$ (193 ) (2.1 )%

~~_________~~


~~(a)~~	Results of transactions with PECO and BGE are included in the Mid-Atlantic region. Results of transactions with Pepco, DPL, and ACE are included in the Mid-Atlantic region beginning on March 24, 2016, the day after the PHI merger was completed.


~~(b)~~	~~Results of transactions with ComEd are included in the Midwest region.~~

~~(c)~~

Other represents activities not allocated to a region. See text above for a description of included activities. Includes amortization of intangible assets related to commodity contracts recorded at fair value of a $54 million decrease to RNF, an $57 million decrease to RNF, and an $8 million increase to RNF for the years ended December 31, 2017, 2016, and 2015, respectively, and accelerated nuclear fuel amortization associated with announced early plant retirements, as discussed in Note 8 - Early Nuclear Plant Retirements of the Combined Notes to Consolidated Financial Statements, of $12 million and $60 million for the years ended December 31, 2017 and 2016, respectively.


~~(d)~~	~~Includes the ownership of the FitzPatrick nuclear facility from March 31, 2017.~~

~~Generation’s supply sources by region are summarized below:~~

2017 vs. 2016 2016 vs. 2015
Supply Source (GWh) 2017 2016 Variance % Change 2015 Variance % Change
Nuclear Generation^(a)

Mid-Atlantic 64,466
63,447
1,019
1.6 % 63,283
164
0.3 %
Midwest 93,344
94,668
(1,324 ) (1.4 )% 93,422
1,246
1.3 %
New York^(c)
25,033
18,684
6,349
34.0 % 18,769
(85 ) (0.5 )%
Total Nuclear Generation 182,843
176,799
6,044
3.4 % 175,474
1,325
0.8 %
Fossil and Renewables

Mid-Atlantic 2,789
2,731
58
2.1 % 2,774
(43 ) (1.6 )%
Midwest 1,482
1,488
(6 ) (0.4 )% 1,547
(59 ) (3.8 )%
New England 7,179
6,968
211
3.0 % 2,983
3,985
133.6 %
New York 3
3
—
— % 3
—
— %
ERCOT 12,072
6,785
5,287
77.9 % 5,763
1,022
17.7 %
Other Power Regions 6,869
8,179
(1,310 ) (16.0 )% 7,848
331
4.2 %
Total Fossil and Renewables 30,394

26,154
4,240
16.2 % 20,918

5,236
25.0 %
Purchased Power

Mid-Atlantic
9,801
16,874
(7,073 ) (41.9 )% 8,160
8,714
106.8 %
Midwest 1,373
2,255
(882 ) (39.1 )% 2,325
(70 ) (3.0 )%
New England 18,517
16,632
1,885
11.3 % 24,309
(7,677 ) (31.6 )%
New York 28
—
28
— % —
—
— %
ERCOT 7,346
10,637
(3,291 ) (30.9 )% 10,070
567
5.6 %
Other Power Regions 14,530
13,589
941
6.9 % 18,773
(5,184 ) (27.6 )%
Total Purchased Power 51,595
59,987

(8,392 ) (14.0 )% 63,637
(3,650 ) (5.7 )%
Total Supply/Sales by Region

Mid-Atlantic^(b)
77,056
83,052
(5,996 ) (7.2 )% 74,217
8,835
11.9 %
Midwest^(b)
96,199
98,411
(2,212 ) (2.2 )% 97,294
1,117
1.1 %
New England 25,696
23,600
2,096
8.9 % 27,292
(3,692 ) (13.5 )%
New York 25,064
18,687
6,377
34.1 % 18,772
(85 ) (0.5 )%
ERCOT 19,418
17,422
1,996
11.5 % 15,833
1,589
10.0 %
Other Power Regions 21,399
21,768
(369 ) (1.7 )% 26,621
(4,853 ) (18.2 )%
Total Supply/Sales by Region 264,832

262,940

1,892
0.7 % 260,029

2,911
1.1 %

~~__________~~


~~(a)~~	Includes the proportionate share of output where Generation has an undivided ownership interest in jointly-owned generating plants and includes the total output of plants that are fully consolidated (e.g. CENG).


~~(b)~~	Includes affiliate sales to PECO and BGE in the Mid-Atlantic region and affiliate sales to ComEd in the Midwest region. As a result of the PHI Merger, includes affiliate sales to Pepco, DPL and ACE in the Mid-Atlantic region beginning on March 24, 2016.


~~(c)~~	~~Includes the ownership of the FitzPatrick nuclear facility from March 31, 2017.~~

~~Mid-Atlantic~~

~~Year Ended December 31, 2017 Compared to Year Ended December 31, 2016~~. The $103 million decrease in revenues net of purchased power and fuel expense in the Mid-Atlantic primarily reflects lower load volumes, lower realized energy prices and decreased capacity prices, partially offset by the absence of oil inventory write-downs in 2017 and decreased nuclear outage days.

~~Year Ended December 31, 2016 Compared to Year Ended December 31, 2015~~. The $254 million decrease in revenues net of purchased power and fuel expense in the Mid-Atlantic was primarily due to lower realized energy prices, decreased capacity prices and higher oil inventory write-downs in 2016, partially offset by increased load volumes served.

~~Midwest~~

~~Year Ended December 31, 2017 Compared to Year Ended December 31, 2016~~. The $151 million decrease in revenues net of purchased power and fuel expense in the Midwest primarily reflects lower realized energy prices and increased nuclear outage days, partially offset by decreased fuel prices.

~~Year Ended December 31, 2016 Compared to Year Ended December 31, 2015~~. ~~The $79 million increase in revenues net of purchased power and fuel expense in the Midwest was primarily due to decreased nuclear outage days and decreased nuclear fuel prices.~~

~~New England~~

~~Year Ended December 31, 2017 Compared to Year Ended December 31, 2016~~. ~~The $76 million increase in revenues net of purchased power and fuel expense in New England was driven by increased capacity prices, partially offset by lower realized energy prices.~~

~~Year Ended December 31, 2016 Compared to Year Ended December 31, 2015~~. The $23 million decrease in revenues net of purchased power and fuel expense in New England was primarily due to lower realized energy prices and higher oil inventory write-downs in 2016, partially offset by increased capacity prices.

~~New York~~

~~Year Ended December 31, 2017 Compared to Year Ended December 31, 2016.~~The $234 million increase in revenues net of purchased power and fuel expense in New York was primarily due to the impact of the New York CES and the acquisition of Fitzpatrick, partially offset by the conclusion of the Ginna Reliability Support Service Agreement and lower realized energy prices.

~~Year Ended December 31, 2016 Compared to Year Ended December 31, 2015~~. The $108 million increase in revenues net of purchased power and fuel expense in New York was primarily due to the impact of the Ginna Reliability Support Service Agreement, partially offset by lower realized energy prices.

~~ERCOT~~

~~Year Ended December 31, 2017 Compared to Year Ended December 31, 2016.~~The $51 million increase in revenues net of purchased power and fuel expense in ERCOT was primarily due to the addition of two combined-cycle gas turbines in Texas, partially offset by lower realized energy prices.

~~Year Ended December 31, 2016 Compared to Year Ended December 31, 2015.~~ ~~The $12 million decrease in revenues net of purchased power and fuel expense in ERCOT was primarily due to lower realized energy prices, partially offset by increased output from renewable assets.~~

~~Other Power Regions~~

~~Year Ended December 31, 2017 Compared to Year Ended December 31, 2016.The $31 million decrease in revenues net of purchased power and fuel expense in Other Power Regions was primarily due to lower realized energy prices.~~

~~Year Ended December 31, 2016 Compared to Year Ended December 31, 2015.~~ ~~The $86 million increase in revenues net of purchased power and fuel expense in Other Power Regions was primarily due to higher realized energy prices.~~

~~Proprietary Trading~~

~~Year Ended December 31, 2017 Compared to Year Ended December 31, 2016.The $3 million increase in revenues net of purchased power and fuel expense in Proprietary trading was primarily due to congestion activity.~~

~~Year Ended December 31, 2016 Compared to Year Ended December 31, 2015.The $14 million increase in revenues net of purchased power and fuel expense in Proprietary trading was primarily due to congestion activity.~~

~~Mark-to-market~~

Generation is exposed to market risks associated with changes in commodity prices and executes economic hedges to mitigate exposure to these fluctuations. See Note 11 — Fair Value of Financial Assets and Liabilities and Note 12 — Derivative Financial Instruments of the Combined Notes to the Consolidated Financial Statements for information on gains and losses associated with mark-to-market derivatives.

~~Year Ended December 31, 2017 Compared to Year Ended December 31, 2016~~. ~~Mark-to-market losses on economic hedging activities were $175 million in 2017 compared to losses of $41 million in 2016.~~

~~Year Ended December 31, 2016 Compared to Year Ended December 31, 2015~~. ~~Mark-to-market losses on economic hedging activities were $41 million in 2016 compared to gains of $257 million in 2015.~~

~~Other~~

~~Year Ended December 31, 2017 Compared to Year Ended December 31, 2016.~~The $90 million decrease in other revenue net of purchased power and fuel was primarily due to the impacts of declining natural gas prices on Generation's natural gas portfolio and the decline in revenues related to the distributed generation business, partially offset by a decrease in accelerated nuclear fuel amortization associated with announced early plant retirements as discussed in Note 8 — Early Nuclear Plant Retirements of the Combined Notes to the Financial Statements.

~~Year Ended December 31, 2016 Compared to Year Ended December 31, 2015.~~The $107 million increase in other revenue net of purchased power and fuel was primarily due to revenue related to the inclusion of Pepco Energy Services results in 2016 and revenue related to energy efficiency projects, partially offset by the amortization of energy contracts recorded at fair value associated with prior acquisitions, and accelerated nuclear fuel amortization associated with the initial early retirement decision for Clinton and Quad Cities as discussed in Note 8 — Early Nuclear Plant Retirements of the Combined Notes to the Financial Statements.

~~Nuclear Fleet Capacity Factor~~

The following table presents nuclear fleet operating data for 2017, as compared to 2016 and 2015, for the Generation-operated plants. The nuclear fleet capacity factor presented in the table is defined as the ratio of the actual output of a plant over a period of time to its output if the plant had operated at full average annual mean capacity for that time period. Generation considers capacity factor to be a useful measure to analyze the nuclear fleet performance between periods. Generation has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, these measures are not a presentation defined under GAAP and may not be comparable to other companies’ presentations or be more useful than the GAAP information provided elsewhere in this report.

2017 2016 2015
Nuclear fleet capacity factor^(a)
94.1 % 94.6 % 93.7 %
Refueling outage days^(a)
293
245
290
Non-refueling outage days^(a)
53
63
82

~~__________~~


~~(a)~~	~~Excludes Salem, which is operated by PSEG Nuclear, LLC. Reflects ownership percentage of stations operated by Exelon. Includes the ownership of the FitzPatrick nuclear facility from March 31, 2017.~~

~~Year Ended December 31, 2017 Compared to Year Ended December 31, 2016~~. ~~The nuclear fleet capacity factor, which excludes Salem, decreased in 2017 compared to 2016 primarily due to increased refueling outage days, partially offset by fewer non-refueling outage days.~~

~~Year Ended December 31, 2016 Compared to Year Ended December 31, 2015~~. ~~The nuclear fleet capacity factor, which excludes Salem, increased in 2016 compared to 2015 primarily due to fewer refueling and non-refueling outage days.~~

~~Operating and Maintenance Expense~~

The changes in ~~operating and maintenance expense for 2017 compared to 2016,~~Operating revenues consisted of the following:



			~~Increase~~ ~~(Decrease)~~^(a) 2022 vs. 2021
~~Impairment and related charges of certain generating assets~~^(b)			$	~~307~~	Increase (Decrease)
~~Merger and integration costs~~Distribution			13$
~~ARO update~~^(c)	84
~~Pension and non-pension postretirement benefits expense~~	10
~~Corporate allocations~~	23
~~Plant retirements and divestitures~~^(d)	~~127~~
~~Accretion expense~~^(e)	35
~~Nuclear refueling outage costs, including the co-owned Salem plant~~^(f)	~~104~~
~~Merger commitments~~^(g)	~~(53~~		)
~~Labor, other benefits, contracting and materials~~^(h)	52
~~Cost management program~~	(2		)
~~Curtailment of Generation growth and development activities~~^(j)	~~(24~~		)
~~Vacation policy change~~⁽ⁱ⁾	~~(40~~		)
~~Allowance for uncollectible accounts~~	33
~~Change in Environmental Remediation Liabilities~~	44
~~Other~~	~~(63~~		)
~~Increase in operating and maintenance expense~~	$	~~650~~

~~__________~~

310
~~(a)~~Transmission			~~The 2017 financial results include Generation's acquisition of the FitzPatrick nuclear generating station from March 31, 2017.~~

65
~~(b)~~Energy efficiency			~~Primarily reflects charges to earnings related to impairments as a result of the EGTP assets in 2017 and impairment of Upstream assets and certain wind projects in 2016.~~

65
~~(c)~~Other			~~Primarily reflects the non-cash benefit pursuant to the annual update of the Generation nuclear decommissioning obligation related to the non-regulatory units in 2017 compared to 2016.~~12

			452
~~(d)~~Regulatory required programs			Primarily represents the announcement of the early retirement of Generation's TMI nuclear facility in 2017 compared to the previous decision to early retire Generation's Clinton and Quad Cities nuclear facilities in 2016.

(1,097)
~~(e)~~ Total decrease			~~Reflects the impact of increased accretion expenses primarily due to the acquisition of FitzPatrick on March 31, 2017.~~$

(645)
~~(f)~~	~~Primarily reflects an increase in the number of nuclear outage days during 2017 compared to 2016.~~


~~(g)~~	~~Primarily represents costs incurred as part of the settlement orders approving the PHI acquisition during 2016.~~


~~(h)~~	~~Reflects increased salaries, wages and contracting costs primarily related to the acquisition of the FitzPatrick nuclear facility beginning on March 31, 2017.~~


~~(i)~~	~~Represents the reversal of previously accrued vacation expenses as a result of a change in Exelon's vacation vesting policy.~~


~~(j)~~	Reflects the one-time recognition for a loss on sale of assets and asset impairment charges pursuant to Generation’s strategic decision in the fourth quarter of 2016 to narrow the scope and scale of its growth and development activities.

~~The changes in operating and maintenance expense for 2016 compared to 2015, consisted of the following:~~

Increase
(Decrease)
Impairment and related charges of certain generating assets ^(a)
$ 161
Merger and integration costs 27
Midwest Generation bankruptcy charges 10
ARO update^(b)
(79 )
Pension and non-pension postretirement benefits expense^(c)
(42 )
Corporate allocations^(d)
(12 )
Plant retirements and divestitures^(e)
(50 )
Accretion expense (21 )
Nuclear refueling outage costs, including the co-owned Salem plant^(f)
(61 )
Merger commitments 53
Labor, other benefits, contracting and materials^(g)
185
Cost management program^(h)
43
Curtailment of Generation growth and development activities⁽ⁱ⁾
24
Other 95
Increase in operating and maintenance expense $ 333

~~__________~~


~~(a)~~	~~Reflects increased impairments in 2016 compared to 2015, primarily related to the impairments of certain Upstream assets and wind generating assets in 2016.~~


~~(b)~~	~~Reflects a non-cash benefit pursuant to the annual update of the Generation nuclear decommissioning obligation related to the non-regulatory units.~~


~~(c)~~	~~Reflects the favorable impact of higher pension and OPEB discount rates.~~


~~(d)~~	~~Reflects a decreased share of corporate allocated costs.~~


~~(e)~~	~~Reflects the impact of the Generation's previous decision to early retire the Clinton and Quad Cities nuclear facilities.~~


~~(f)~~	~~Reflects the favorable impacts of decreased nuclear outages in 2016.~~


~~(g)~~	Reflects an increase of labor, other benefits, contracting and materials costs primarily due to increased contracting costs related to energy efficiency projects and the inclusion of Pepco Energy Services results in 2016. Also includes cost of sales of our other business activities that are not allocated to a region.


~~(h)~~	~~Represents the 2016 severance expense and reorganization costs related to a cost management program.~~


~~(i)~~	Reflects the one-time recognition for asset impairment charges pursuant to Generation's strategic decision in the fourth quarter of 2016 to narrow the scope and scale of its growth and development activities.

~~Depreciation and Amortization~~

~~Year Ended December 31, 2017 Compared to Year Ended December 31, 2016~~. Depreciation and amortization expense decreased primarily due to accelerated depreciation and increased nuclear decommissioning amortization related to the previous decision to early retire the Clinton and Quad Cities nuclear facilities in 2016 compared to the decision to early retire the Three Mile Island nuclear facility in 2017.

~~Year Ended December 31, 2016 Compared to Year Ended December 31, 2015~~. Depreciation and amortization expense increased primarily due to accelerated depreciation and increased nuclear decommissioning amortization related to the previous decision to early retire the Clinton and Quad Cities nuclear facilities in 2016, and increased depreciation expense due to ongoing capital expenditures.

~~Taxes Other Than Income~~

~~Year Ended December 31, 2017 Compared to Year Ended December 31, 2016~~. ~~The increase in taxes other than income was primarily due to increased real estate taxes and sales and use taxes.~~

~~Year Ended December 31, 2016 Compared to Year Ended December 31, 2015~~. ~~The increase in taxes other than income was primarily due to an increase in gross receipts tax.~~

~~Gain (Loss) on Sales of Assets~~

~~Year Ended December 31, 2017 Compared to Year Ended December 31, 2016~~. The increase in gain (loss) on sales of assets is primarily due to certain Generation projects and contracts being terminated or renegotiated in 2016, partially offset by a gain associated with Generation’s sale of the retired New Boston generating site in 2016.

~~Year Ended December 31, 2016 Compared to Year Ended December 31, 2015~~. The decrease in gain (loss) on sales of assets is primarily related to the one-time recognition for a loss on sale of assets pursuant to Generation's strategic decision in the fourth quarter of 2016 to narrow the scope and scale of its growth and development activities, partially offset by a gain associated with Generation's sale of the retired New Boston generating site in 2016.

~~Bargain Purchase Gain~~

~~Year Ended December 31, 2017 Compared to Year Ended December 31, 2016~~. The increase in the Bargain purchase gain is related to the result of the gain associated with the FitzPatrick acquisition. Refer to Note 4 — Mergers, Acquisitions and Dispositions of the Combined Notes to the Consolidated Financial Statements for additional information.

~~Gain on Deconsolidation of Business~~

~~Year Ended December 31, 2017 Compared to Year Ended December 31, 2016~~. The increase in the Gain on deconsolidation of business is related to the deconsolidation of EGTP's net liabilities, which included the previously impaired assets and related debt, as a result of the November 2017 bankruptcy filing. Refer to Note 4 — Mergers, Acquisitions and Dispositions of the Combined Notes to the Consolidated Financial Statements for additional information.

~~Interest Expense~~

~~The changes in interest expense for 2017 compared to 2016 and 2016 compared to 2015 consisted of the following:~~

Increase (Decrease) 2017 vs. 2016 Increase (Decrease) 2016 vs. 2015
Interest expense on long-term debt $ —
$ 8
Interest expense on interest rate swaps (2 ) 1
Interest expense on tax settlements 12
16
Other interest expense 66
(26 )
(Decrease) increase in interest expense, net $ 76
$ (1 )

~~Other, Net~~

~~Year Ended December 31, 2017 Compared to Year Ended December 31, 2016~~. The increase in Other, net primarily reflects the net increase in realized and unrealized gains related to the NDT fund investments of Generation’s Non-Regulatory Agreement Units as described in the table below. Other, net also reflects $209 million and $80 million for the years ended December 31, 2017 and 2016, respectively, related to the contractual elimination of income tax expense associated with the NDT fund investments of the Regulatory Agreement Units. Refer to Note 15 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information regarding NDT fund investments.

~~Year Ended December 31, 2016 Compared to Year Ended December 31, 2015~~. The increase in Other, net primarily reflects the net increase in realized and unrealized gains related to the NDT fund investments of Generation’s Non-Regulatory Agreement Units as described in the table below. Other, net also reflects $80 million and $(22) million for the years ended December 31, 2016 and 2015, respectively, related to the contractual elimination of income tax expense associated with the NDT fund investments of the Regulatory Agreement Units. Refer to Note 15 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information regarding NDT fund investments.

~~The following table provides unrealized and realized gains (losses) on the NDT funds of the Non-Regulatory Agreement Units recognized in Other, net for 2017, 2016 and 2015:~~

2017 2016 2015
Net unrealized gains (losses) on decommissioning trust funds $ 521
$ 194
$ (197 )
Net realized gains on sale of decommissioning trust funds 95
35
66

~~Effective Income Tax Rate~~

Generation’s effective income tax rates for the years ended December 31, 2017, 2016 and 2015 were (96.2)%, 33.2% and 27.1%, respectively. See Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for further discussion of the change in the effective income tax rate.

~~Results of Operations—ComEd~~

2017 2016 Favorable (unfavorable) 2017 vs. 2016 variance 2015 Favorable (unfavorable) 2016 vs. 2015 variance
Operating revenues $ 5,536
$ 5,254
$ 282
$ 4,905
$ 349
Purchased power expense 1,641
1,458
(183 ) 1,319
(139 )
Revenues net of purchased power expense^(a)(b)
3,895
3,796
99
3,586
210
Other operating expenses
Operating and maintenance 1,427
1,530
103
1,567
37
Depreciation and amortization 850
775
(75 ) 707
(68 )
Taxes other than income 296
293
(3 ) 296
3
Total other operating expenses 2,573
2,598
25
2,570
(28 )
Gain on sales of assets 1
7
(6 ) 1
6
Operating income 1,323
1,205
118
1,017
188
Other income and (deductions)
Interest expense, net (361 ) (461 ) 100
(332 ) (129 )
Other, net 22
(65 ) 87
21
(86 )
Total other income and (deductions) (339 ) (526 ) 187
(311 ) (215 )
Income before income taxes 984
679
305
706
(27 )
Income taxes 417
301
(116 ) 280
(21 )
Net income $ 567
$ 378
$ 189
$ 426
$ (48 )

~~__________~~

~~(a)~~

ComEd evaluates its operating performance using the measure of Revenue net of purchased power expense. ComEd believes that Revenue net of purchased power expense is a useful measurement because it provides information that can be used to evaluate its operational performance. In general, ComEd only earns margin based on the delivery and transmission of electricity. ComEd has included its discussion of Revenue net of purchased power expense below as a complement to the financial information provided in accordance with GAAP. However, Revenue net of purchased power expense 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.


~~(b)~~	For regulatory recovery mechanisms, including ComEd’s electric distribution and transmission formula rates, and riders, revenues increase and decrease i) as fully recoverable costs fluctuate (with no impact on net earnings), and ii) pursuant to changes in rate base, capital structure and ROE (which impact net earnings).

~~Net Income~~

~~Year Ended December 31, 2017 Compared to Year Ended December 31, 2016.~~ComEd’s Net income for the year ended December 31, 2017 was higher than the same period in 2016 primarily due to the recognition of the penalty and the after-tax interest due on the asserted penalty related to the Tax Court's decision on Exelon's like-kind exchange tax position in 2016 and increased electric distribution and transmission formula rate earnings (reflecting the impacts of increased capital investment and higher allowed electric distribution ROE). The higher Net income was partially offset by the impact of weather conditions in 2016. See Revenue Decoupling discussion below for additional information on the impact of weather.

~~Year Ended December 31, 2016 Compared to Year Ended December 31, 2015.~~ComEd’s Net income for the year ended December 31, 2016 was lower than the same period in 2015 primarily due to the recognition of the penalty and the after-tax interest due on the asserted penalty related to the Tax Court's decision on Exelon's like-kind exchange tax position, partially offset by increased electric

~~distribution and transmission formula rate earnings (reflecting the impacts of increased capital investment, partially offset by lower allowed electric distribution ROE) and favorable weather.~~

~~Revenues Net of Purchased Power Expense~~

There are certain drivers of Operating revenues that are fully offset by their impact on Purchased power expense, such as commodity, REC and ZEC procurement costs and participation in customer choice programs. ComEd is permitted to recover electricity, REC and ZEC procurement costs from retail customers without mark-up. Therefore, fluctuations in these costs have no impact on Revenue net of purchased power expense. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on ComEd’s electricity procurement process.

All ComEd customers have the choice to purchase electricity from a competitive electric generation supplier. Customer choice programs do not impact ComEd’s volume of deliveries, but do affect ComEd’s Operating revenues related to supplied energy, which is fully offset in Purchased power expense. Therefore, customer choice programs have no impact on Revenue net of purchased power expense.

~~Retail deliveries purchased from competitive electric generation suppliers (as a percentage of kWh sales) for the years ended December 31, 2017, 2016 and 2015, consisted of the following:~~

For the Years Ended December 31,
2017 2016 2015
Electric 70 % 72 % 76 %

~~Retail customers purchasing electric generation from competitive electric generation suppliers at December 31, 2017, 2016 and 2015 consisted of the following:~~

December 31, 2017 December 31, 2016 December 31, 2015
Number of customers % of total retail customers Number of customers % of total retail customers Number of customers % of total retail customers
Electric 1,371,700
34 % 1,502,900
38 % 1,655,400
42 %

The changes in ComEd’s Revenue net of purchased power expense for the year ended December 31, 2017, compared to the same period in 2016, and for the year ended December 31, 2016, compared to the same period in 2015, consisted of the following:

Increase (Decrease) 2017 vs. 2016 Increase (Decrease) 2016 vs. 2015
Weather^(a)
$ (36 ) $ 54
Volume^(a)
(5 ) (2 )
Pricing and customer mix^(a)
(18 ) 14
Electric distribution revenue 170
69
Transmission revenue 60
97
Energy efficiency revenue^(b)
16
—
Regulatory required programs^(b)
(85 ) (31 )
Uncollectible accounts recovery, net (7 ) (13 )
Other 4
22
Total increase $ 99
$ 210

~~__________~~

~~(a)~~

For the year ended December 31, 2017, compared to the same period in 2016, the changes reflect the 2016 impacts of weather, volume and pricing and customer mix. As further described below, pursuant to the revenue decoupling provision in FEJA, ComEd began recording an adjustment to revenue in the first quarter of 2017 to eliminate the favorable or unfavorable impacts associated with variations in delivery volumes associated with above or below normal weather, number of customers or usage per customer.


~~(b)~~	Beginning on June 1, 2017, ComEd is deferring energy efficiency costs as a regulatory asset that will be recovered through the energy efficiency formula rate over the weighted average useful life of the related energy efficiency measures.

Revenue Decoupling.The demand for electricity is affected by weather ~~conditions. Very warm weather in summer months~~ and ~~very cold weather in other months are referred to as “favorable weather conditions” because these weather conditions result in increased~~ customer usage. ~~Conversely, mild weather reduces demand.~~

Under EIMA, ComEd's electric distribution formula rate provided for an adjustment to future billings if its earned ROE fell outside a 50-basis-point collar of its allowed ROE, which partially eliminated the impacts of weather and load on ComEd's revenue. As allowed under FEJA, ComEd will revise its electric distribution formula rate to eliminate the ROE collar beginning with the reconciliation filed in 2018 for the 2017 calendar year. Elimination of the ROE collar effectively offsets the favorable or unfavorable impacts to Operating revenues ~~associated with variations in delivery volumes associated with above or below normal~~are not impacted by abnormal weather, ~~numbers of customers or~~ usage per ~~customer. ComEd began recognizing the impacts~~customer, or number of this change beginning in the first quarter of 2017. For the year ended December 31, 2017, ComEd recorded an increase to Electric distribution revenues of approximately $32 million to eliminate weather and load impacts.

~~For the year ended December 31, 2016, favorable weather conditions increased Operating revenues net of purchased power expense when compared to the prior year.~~

~~For the year ended December 31, 2016, the increase in Revenue net of purchased power~~customers as a result of ~~pricing and customer mix is primarily attributable~~revenue decoupling mechanisms implemented pursuant to ~~higher overall effective rates due to decreased usage across all major customer classes and change in customer mix.~~FEJA.

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 ComEd’s service territory with cooling degree days generally having a more significant impact to ComEd, particularly during the summer months. The changes in heating and cooling degree days in ComEd’s service territory for the years ended December 31, 2017, 2016 and 2015 consisted of the following:

Heating and Cooling Degree-Days For the Years Ended December 31, % Change
2017 2016 Normal 2017 vs. 2016 2017 vs. Normal
Heating Degree-Days 5,435
5,715
6,198
(4.9 )% (12.3 )%
Cooling Degree-Days 991
1,157
893
(14.3 )% 11.0 %

Heating and Cooling Degree-Days For the Years Ended December 31, % Change
2016 2015 Normal 2016 vs. 2015 2016 vs. Normal
Heating Degree-Days 5,715
6,091
6,198
(6.2 )% (7.8 )%
Cooling Degree-Days 1,157
806
893
43.5 % 29.6 %

~~Electric~~ 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. ComEd's allowed ROE is the annual average rate on 30-year treasury notes plus 580 basis points. In addition, ComEd's allowed ROE is subject to reduction if ComEd does not deliver the reliability and customer service benefits to which it has committed over the ten-year life of the investment program. DuringElectric distribution revenue increased during the year ended December 31, ~~2017, electric distribution revenue increased $170 million, primarily~~2022, compared to the same period in 2021, due to ~~increased capital investment, increased Depreciation expense,~~ higher allowed ROE due to an increase in ~~treasury~~U.S. Treasury rates, the impact of a higher rate base, and revenue decoupling impacts (as described above). During the year ended December 31, 2016, electric distribution revenue increased $69 million, primarily due to increased capital investment and Depreciation expense, partially offset by lower allowed ROE due to a decrease in treasury rates. See Operating and Maintenance Expense below and Note 3 — Regulatory Mattershigher fully recoverable costs.

Table of ~~the Combined Notes to Consolidated Financial Statements for additional information.~~Contents

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~~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. ~~For~~Transmission revenues increased during the ~~years~~year ended December 31, ~~2017 and 2016, ComEd recorded increased transmission revenue~~2022, compared to the same period in 2021, primarily due to ~~increased capital investment,~~the impact of a higher ~~Depreciation expense~~rate base and ~~increased highest daily peak load. See Operating and Maintenance Expense below and Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.~~higher fully recoverable costs.

Energy Efficiency Revenue. ~~Beginning June 1, 2017,~~ 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~~fluctuations in the underlying costs, investments being recovered, and allowed ROE. ~~ComEd’s~~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 ~~annual average rate on 30-year treasury notes plus 580 basis points. Beginning January 1, 2018, ComEd’s allowed ROE is subject~~year ended December 31, 2022, compared 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~~the same period in 2021, which primarily reflects mutual assistance revenues associated with storm restoration efforts.

~~incremental savings goal.~~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 ~~Depreciation and amortization expense discussions below and~~ Note 3 —- Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional ~~information.~~

~~Regulatory Required Programs.~~ ~~This represents the change~~information regarding CMCs. ETAC is a retail customer surcharge collected by electric utilities operating in ~~Operating revenues collected under approved rate riders~~Illinois established by CEJA and remitted to ~~recover costs incurred~~an Illinois state agency for ~~regulatory~~ programs ~~such as ComEd's purchased power administrative costs~~to support clean energy jobs and ~~energy efficiency and demand response through June 1, 2017 pursuant to FEJA.~~training. The riders are designed to provide full and current cost recovery. ~~An equal and offsetting amount has been~~The costs of these programs are included in ~~Operating and maintenance expense. See~~Purchased power expense, Operating and maintenance expense, ~~discussion below~~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 ~~additional information on included programs.~~

~~Uncollectible Accounts Recovery, Net.Uncollectible accounts recovery, net, represents recoveries under ComEd’s uncollectible accounts tariff. See~~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 ~~maintenance~~therefore does not record Operating revenues or Purchased power expense ~~discussion below for additional information on this tariff.~~

~~Other.Other revenue, which can vary period to period, includes rental revenue, revenue~~ related to ~~late payment charges, assistance provided~~the electricity. For customers that choose to ~~other utilities through mutual assistance programs, recoveries of environmental~~purchase electric generation from ComEd, ComEd is permitted to recover the electricity, ZEC, CMC, and REC procurement costs ~~associated with MGP sites,~~without mark-up and ~~recoveries of energy procurement costs.~~

~~Operating~~therefore records equal and ~~Maintenance Expense~~

Year Ended
December 31,

Increase
(Decrease)

Year Ended
December 31,

Increase
(Decrease)
2017 2016 2017 vs. 2016 2016 2015 2016 vs. 2015
Operating and maintenance expense—baseline $ 1,329
$ 1,347
$ (18 ) $ 1,347
$ 1,353
$ (6 )
Operating and maintenance expense—regulatory required programs^(a)
98
183
(85 ) 183
214
(31 )
Total operating and maintenance expense $ 1,427
$ 1,530
$ (103 ) $ 1,530
$ 1,567
$ (37 )

~~__________~~


~~(a)~~	Operating and maintenance expense for regulatory required programs are costs for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues.

~~The changes~~offsetting amounts in Operating revenues and ~~maintenance~~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, ~~2017,~~2022, compared to the same period in ~~2016,~~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.

Table of Contents

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
	58
Regulatory required programs(a)	(1)
Total increase	$	57

__________

(a)ComEd is allowed to recover from or refund to customers the difference between its annual credit loss expense and the amounts collected in rates annually through a rider mechanism.

The changes in Depreciation and amortization expense consisted of the following:


	2022 vs. 2021
	Increase
Depreciation and amortization(a)	$	63
Regulatory asset amortization(b)	55

Total increase	$	118

__________

(a)Reflects ongoing capital expenditures.

(b)Includes amortization of ComEd's energy efficiency formula rate regulatory asset.

Taxes other than income taxes increased by $54 million for the year December 31, 2022, compared to the same period in 2021, primarily due to taxes related to ETAC, which is recovered through Operating revenues.

Interest expense, net increased $25 million for the year ended December 31, ~~2016,~~2022, compared to the same period in ~~2015, consisted of the following:~~

Increase (Decrease) 2017 vs. 2016 Increase (Decrease) 2016 vs. 2015
Baseline
Labor, other benefits, contracting and materials $ (41 ) $ 12
Pension and non-pension postretirement benefits expense^(a)
3
(24 )
Storm-related costs 2
(9 )
Uncollectible accounts expense—provision^(b)
(6 ) 5
Uncollectible accounts expense—recovery, net^(b)
(1 ) (18 )
BSC costs^(c)
44
29
Other (19 ) (1 )
(18 ) (6 )
Regulatory required programs
Energy efficiency and demand response programs^(d)
(85 ) (31 )
Decrease in operating and maintenance expense $ (103 ) $ (37 )

~~__________~~


~~(a)~~	~~Primarily reflects the favorable impact of higher assumed pension and OPEB discount rates for the year ended December 31, 2016.~~

~~(b)~~

ComEd is allowed to recover from or refund to customers the difference between the utility’s annual uncollectible accounts expense and the amounts collected in rates annually through a rider mechanism. ComEd recorded a net decrease in 2017 and 2016 in Operating and maintenance expense related to uncollectible accounts due to the timing of regulatory cost recovery. An equal and offsetting amount has been recognized in Operating revenues for the periods presented.


~~(c)~~	Primarily reflects increased information technology support services from BSC in 2017 and 2016. For the year ended December 31, 2017, includes the $8 million write-off of a regulatory asset related to Constellation merger and integration costs for which recovery is no longer expected.


~~(d)~~	Beginning on June 1, 2017 ComEd is deferring energy efficiency costs as a regulatory asset that will be recovered through the energy efficiency over the weighted average useful life of the related energy efficiency measures.

~~Depreciation and Amortization Expense~~

~~The increases in Depreciation and amortization expense for 2017 compared to 2016, and 2016 compared to 2015, consisted of the following:~~

Increase (Decrease) 2017 vs. 2016 Increase (Decrease) 2016 vs. 2015
Depreciation expense^(a)
$ 60
$ 58
Regulatory asset amortization^(b)
7
(5 )
Other 8
15
Total increase $ 75
$ 68

~~__________~~


~~(a)~~	~~Primarily reflects ongoing capital expenditures for the years ended December 31, 2017 and 2016.~~


~~(b)~~	~~Beginning in June 2017, includes amortization of ComEd's energy efficiency formula rate regulatory asset.~~

~~Taxes Other Than Income~~

Taxes other than income, which can vary year to year, include municipal and state utility taxes, real estate taxes, and payroll taxes. Taxes other than income taxes remained relatively consistent for the year ended December 31, 2017, compared to the same period in 2016, and for the year ended December 31, 2016, compared to the same period in 2015.

~~Gain on Sale of Assets~~

Gain on sale of assets decreased during the year ended December 31, 2017, compared to the same period in 2016, and increased during the year ended December 31, 2016, compared to the same period in 2015,2021, primarily due to the ~~sale~~issuance of ~~land during March 2016.~~debt in 2021 and 2022.

~~Interest Expense, Net~~

The increase (decrease) in Interest expense, net, for the year ended 2017, compared to the same period in 2016, and for the year ended 2016, compared to the same period in 2015, consisted of the following:

Increase (Decrease) 2017 vs. 2016 Increase (Decrease) 2016 vs. 2015
Interest expense related to uncertain tax positions^(a)
$ (104 ) $ 109
Interest expense on debt (including financing trusts)^(b)
6
24
Other (2 ) (4 )
Increase (decrease) in interest expense, net $ (100 ) $ 129

~~__________~~

~~(a)~~

Primarily reflects the recognition of after-tax interest related to the Tax Court's decision on Exelon's like-kind exchange tax position in the 2016. For the year ended December 31, 2017, the decrease was partially offset by additional interest recorded in 2017 related to Exelon's like-kind exchange tax position. See Note 14—Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.


~~(b)~~	Primarily reflects an increase in interest expense due to the issuance of First Mortgage Bonds for the years ended December 31, 2016. See Note 13—Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on ComEd's debt obligations.

~~Other, Net~~

~~The increase (decrease) in Other, net, for the year ended 2017 compared to the same period in 2016, and for the year ended 2016 compared to the same period in 2015, consisted of the following:~~

Increase (Decrease) 2017 vs. 2016 Increase (Decrease) 2016 vs. 2015
Other income and deductions, net^(a)
$ 88
$ (94 )
AFUDC equity (2 ) 9
Other 1
(1 )
Increase (decrease) in Other, net $ 87
$ (86 )

~~__________~~


~~(a)~~	Primarily reflects the recognition of the penalty related to the Tax Court's decision on Exelon's like-kind exchange tax position in 2016. See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.

Effective ~~Income Tax Rate~~

~~ComEd’s effective~~ income tax rateswere 22.4%and 18.8% for the years ended December 31, ~~2017, 2016~~ 2022and ~~2015, were 42.4%, 44.3% and 39.7%,~~2021, respectively. The decrease in the effective income tax rate for the year ended December 31, 2017 compared to the same period in 2016 is primarily due to the recognition of a non-deductible penalty related to the Tax Court's decision on Exelon's like-kind exchange tax position in the third quarter of 2016. See Note 1413 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

~~ComEd Electric Operating Statistics and Revenue Detail~~

Retail Deliveries to customers (in GWhs) 2017 2016 % Change 2017 vs. 2016
Weather-
Normal
%
Change
2015 % Change 2016 vs. 2015
Weather-
Normal
%
Change
Retail Deliveries ^(a)

Residential 26,292
27,790
(5.4 )% (0.9 )% 26,496
4.9 % (0.6 )%
Small commercial & industrial 31,332
31,975
(2.0 )% (0.7 )% 31,717
0.8 % (0.3 )%
Large commercial & industrial 27,467
27,842
(1.3 )% (0.5 )% 27,210
2.3 % 1.5 %
Public authorities & electric railroads 1,286
1,298
(0.9 )% (0.3 )% 1,309
(0.8 )% (0.8 )%
Total retail deliveries 86,377
88,905
(2.8 )% (0.7 )% 86,732
2.5 % 0.2 %

Table of Contents

PECO

As of December 31,
Number of Electric Customers 2017 2016 2015
Residential 3,624,372
3,595,376
3,550,239
Small commercial & industrial 378,345
374,644
370,932
Large commercial & industrial 1,959
2,007
1,976
Public authorities & electric railroads 4,775
4,750
4,820
Total 4,009,451
3,976,777
3,927,967

Electric Revenue 2017 2016 % Change 2017 vs. 2016 2015 % Change 2016 vs. 2015
Retail Sales^(a)

Residential $ 2,746
$ 2,597
5.7 % $ 2,360
10.0 %
Small commercial & industrial 1,376
1,316
4.6 % 1,337
(1.6 )%
Large commercial & industrial 461
462
(0.2 )% 443
4.3 %
Public authorities & electric railroads 44
45
(2.2 )% 42
7.1 %
Total retail 4,627
4,420
4.7 % 4,182
5.7 %
Other revenue^(b)
909
834
9.0 % 723
15.4 %
Total electric revenue^(c)
$ 5,536
$ 5,254
5.4 % $ 4,905
7.1 %

~~__________~~


~~(a)~~	Reflects delivery revenue and volume from customers purchasing electricity directly from ComEd and customers purchasing electricity from a competitive electric generation supplier, as all customers are assessed delivery charges. For customers purchasing electricity from ComEd, revenue also reflects the cost of energy and transmission.


~~(b)~~	Other revenue primarily includes transmission revenue from PJM. Other revenue also includes rental revenue, revenue related to late payment charges, revenue from other utilities for mutual assistance programs and recoveries of remediation costs associated with MGP sites.


~~(c)~~	~~Includes operating revenues from affiliates totaling $15 million, $15 million, and $4 million for the years ended December 31, 2017, 2016, and 2015, respectively.~~

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

2017 2016 Favorable (unfavorable) 2017 vs. 2016 variance 2015 Favorable (unfavorable) 2016 vs. 2015 variance
Operating revenues $ 2,870
$ 2,994
$ (124 ) $ 3,032
$ (38 )
Purchased power and fuel expense 969
1,047
78
1,190
143
Revenues net of purchased power and fuel expense ^(a)
1,901
1,947
(46 ) 1,842
105
Other operating expenses
Operating and maintenance 806
811
5
794
(17 )
Depreciation and amortization 286
270
(16 ) 260
(10 )
Taxes other than income 154
164
10
160
(4 )
Total other operating expenses 1,246
1,245
(1 ) 1,214
(31 )
Gain on sales of assets —
—
—
2
(2 )
Operating income 655
702
(47 ) 630
72
Other income and (deductions)
Interest expense, net (126 ) (123 ) (3 ) (114 ) (9 )
Other, net 9
8
1
5
3
Total other income and (deductions) (117 ) (115 ) (2 ) (109 ) (6 )
Income before income taxes 538
587
(49 ) 521
66
Income taxes 104
149
45
143
(6 )
Net income $ 434
$ 438
$ (4 ) $ 378
$ 60

~~__________~~

~~(a)~~

PECO evaluates its operating performance using the measures of revenue net of purchased power expense for electric sales and revenue net of fuel expense for gas sales. PECO believes revenue net of purchased power expense and revenue net of fuel expense are useful measurements of its performance because they provide information that can be used to evaluate its net revenue from operations. PECO has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, revenue net of purchased power expense and revenue net of fuel expense figures are not a presentation defined under GAAP and may not be comparable to other companies’ presentations or more useful than the GAAP information provided elsewhere in this report.

~~Net Income~~

Year Ended December 31, ~~2017~~2022 Compared to Year Ended December 31, ~~2016.~~ ~~PECO's net~~2021.Net income ~~for the year ended December 31, 2017 was lower than the same period in 2016,~~ increased by $72 million, primarily due to increases in electric and gas distribution rates and a decrease in ~~Revenues net of purchased power and fuel expense as a result of unfavorable weather in PECO's service territory,~~storm costs, partially offset by the one-time non-cash impacts associated with the ~~Tax Cuts~~Pennsylvania corporate income tax legislation passed in July 2022, and ~~Jobs Act~~increases in ~~2017.~~depreciation expense, credit loss expense, and interest expense.

~~Year Ended December 31, 2016 Compared to Year Ended December 31, 2015.~~ ~~PECO's net income for the year ended December 31, 2016 was higher than the same period~~The changes in 2015, primarily due to an increase in Revenues net of purchased power and fuel expense as a result of increased electric distribution revenue pursuant to the 2015 PAPUC authorized electric distribution rate increase effective January 1, 2016.

~~Revenues Net of Purchased Power and Fuel Expense~~

Electric and natural gas revenue and purchased power and fuel expense are affected by fluctuations in commodity procurement costs. PECO's electric supply and natural gas cost rates charged to customers

are subject to adjustments as specified in the PAPUC-approved tariffs that are designed to recover or refund the difference between the actual cost of electric supply and natural gas and the amount included in rates in accordance with PECO's GSA and PGC, respectively. Therefore, fluctuations in electric supply and natural gas procurement costs have no impact on electric and natural gasOperating revenues ~~net of purchased power and fuel expense.~~

Electric and natural gas revenue and purchased power and fuel expense are also affected by fluctuations in participation in the Customer Choice Program. All PECO customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers, respectively. The customer’s choice of suppliers does not impact the volume of deliveries, but affects revenue collected from customers related to supplied energy and natural gas service. Customer Choice Program activity has no impact on electric and natural gas revenue net of purchase power and fuel expense.

~~Retail deliveries purchased from competitive electric generation and natural gas suppliers (as a percentage of kWh and mmcf sales, respectively) for the years ended December 31, 2017, 2016, and 2015~~ 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

For the Years Ended December 31,
2017 2016 2015
Electric 71 % 70 % 70 %
Natural Gas 26 % 26 % 25 %

~~Retail customers purchasing electric generation and natural gas from competitive electric generation and natural gas suppliers at December 31, 2017, 2016, and 2015consisted of the following:~~

The changes in PECO’s Operating revenues net of purchased power and fuel expense for the years ended December 31, 2017 and December 31, 2016 compared to the same periods in 2016 and 2015, respectively, consisted of the following:

2017 vs. 2016 2016 vs. 2015
Increase (Decrease) Increase (Decrease)
Electric Gas Total Electric Gas Total
Weather $ (28 ) $ 4
$ (24 ) $ 1
$ (12 ) $ (11 )
Volume (18 ) 3
(15 ) 6
4
10
Pricing 8
2
10
160
(1 ) 159
Regulatory required programs (31 ) —
(31 ) (46 ) —
(46 )
Other 14
—
14
(7 ) —
(7 )
Total increase (decrease) $ (55 ) $ 9
$ (46 ) $ 114
$ (9 ) $ 105

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, ~~2017~~2022 compared to the same period in ~~2016, and the year ended December 31, 2016 compared to the same period in 2015~~2021, Operating revenues ~~net of purchased power and fuel expense was reduced by~~related to weather increased due to the impact of ~~unfavorable~~favorable weather conditions in ~~PECO’s~~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, ~~2017 and December 31, 2016~~2022 compared to the same ~~periods~~period in ~~2016 and 2015, respectively,~~2021 and normal weather consisted of the following:

Table of Contents

PECO


									For the Years Ended December 31,			% Change
	For the Years Ended December 31,			% Change
Heating and Cooling Degree-Days	2017	2016	Normal	2017 vs. 2016		2017 vs. Normal
PECO Service Territory								PECO Service Territory	2022	2021	Normal	2022 vs. 2021		2022 vs. Normal
Heating Degree-Days	3,949	4,041	4,603	(2.3	)%	(14.2	)%	Heating Degree-Days	4,135	3,946	4,408	4.8	%	(6.2)	%
Cooling Degree-Days	1,490	1,726	1,290	(13.7	)%	15.5	%	Cooling Degree-Days	1,743	1,586	1,443	9.9	%	20.8	%

	For the Years Ended December 31,			% Change
Heating and Cooling Degree-Days	2016	2015	Normal	2016 vs. 2015		2016 vs. Normal
Heating Degree-Days	4,041	4,245	4,603	(4.8	)%	(12.2	)%
Cooling Degree-Days	1,726	1,720	1,290	0.3	%	33.8	%

Volume.~~The decrease in Operating revenues net of purchased power and fuel expense related to delivery~~ Electric volume, exclusive of the effects of weather, for the year ended December 31, ~~2017~~2022 compared to the same period in 2016, was driven by electric and primarily reflects the impact of energy efficiency initiatives on customer usages for residential and small commercial and industrial electric classes, partially offset by solid customer growth. Additionally, the decrease represents a shift in the2021, decreased due to unfavorable load change. Natural gas volume ~~profile across classes from residential and small commercial and industrial to large commercial and industrial.~~

~~The increase in Operating revenues net of purchased power and fuel expense related to delivery volume, exclusive of the effects of weather,~~ for the year ended December 31, ~~2016~~2022 compared to the same period in ~~2015, primarily reflects~~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 ~~impact of moderate economic~~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 ~~customer growth partially offset by energy efficiency initiatives~~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 ~~customer usages for gas and residential and small commercial and industrial electric classes. Additionally,~~ the ~~increase represents a shift in the volume profile across classes from large commercial and industrial classes to residential and small commercial and industrial classes for electric.~~historical 30-year average.

~~Pricing.The increase in Operating revenues net of purchased power expense as a result of pricing~~


	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, ~~2017~~2022 compared to the same period in ~~2016 reflects higher overall effective rates~~2021 increased primarily due to ~~decreased usage~~increases in electric and gas distribution rates charged to customers.

Table of Contents

PECO

Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the ~~residential~~underlying costs and ~~small commercial and industrial customer classes. Operating~~capital investments being recovered.

Other Revenue primarily includes revenue related to late payment charges. Other revenues ~~net of fuel expense as a result of pricing remained relatively consistent.~~

~~The increase in Operating revenues net of purchased power and fuel expense as a result of pricing~~ for the year ended December 31, ~~2016~~2022 compared to the same period in ~~2015 reflects an increase in~~2021, increased primarily due to revenue related to late payment charges.

electric distribution rates charged to customers. The increase in electric distribution rates was effective January 1, 2016 in accordance with the 2015 PAPUC approved electric distribution rate case settlement. See Note 3 — Regulatory Matters for further information.

Regulatory Required ~~Programs.This~~Programs represents ~~the change in operating~~ revenues collected under approved riders to recover costs incurred for regulatory programs such as ~~smart meter,~~ 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. ~~Refer to the Operating and maintenance expense discussion below for additional information on included programs.~~

~~Other.~~Other revenue, which can vary period to period, primarily includes wholesale transmission revenue, rental revenue, revenue related to late payment charges and assistance provided to other utilities through mutual assistance programs.

~~Operating and Maintenance Expense~~

Year
Ended December 31,
Increase (Decrease)
Year
Ended December 31,

Increase
(Decrease)
2017 2016 2017 vs. 2016 2016 2015 2016 vs. 2015
Operating and maintenance
expense—baseline
$ 746
$ 740
$ 6
$ 740
$ 685
$ 55
Operating and maintenance
expense—regulatory required programs ^(a)
60
71
(11 ) 71
109
(38 )
Total operating and
maintenance expense
$ 806
$ 811
$ (5 ) $ 811
$ 794
$ 17

~~__________~~


~~(a)~~	Operating and maintenance expenses for regulatory required programs are costs for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues.

~~The changes in Operating and maintenance expense for 2017 compared to 2016 and 2016 compared to 2015 consisted of the following:~~

Increase (Decrease) 2017 vs. 2016 Increase (Decrease) 2016 vs. 2015
Baseline
Labor, other benefits, contracting and materials $ 17
$ 22

Storm-related costs (7 ) (9 )
Pension and non-pension postretirement benefits expense (3 ) (4 )
PHI merger integration costs —
6

BSC costs 4
36
^(a)
Uncollectible accounts expense (5 ) 1

Other —
3

6
55

Regulatory required programs
Smart meter —
(28 )
Energy efficiency (10 ) (7 )
GSA —
(2 )
Other (1 ) (1 )
(11 ) (38 )
Increase (decrease) in operating and maintenance expense $ (5 ) $ 17

~~__________~~

~~(a) Primarily reflects increased information technology support services from BSC during 2016.~~

~~Depreciation and Amortization Expense~~

~~The changes in Depreciation and amortization expense for 2017 compared to 2016 and 2016 compared to 2015, consisted of the following:~~

Increase (Decrease) 2017 vs. 2016 Increase (Decrease) 2016 vs. 2015
Depreciation expense $ 17
$ 5
Regulatory asset amortization (1 ) 5
Increase in depreciation and amortization expense $ 16

$ 10

~~Taxes Other Than Income~~

Taxes other than income, which can vary year to year, include municipal and state utility taxes, real estate taxes, and payroll taxes. Taxes other than income decreased for the year ended December 31, 2017, compared to the same period in 2016, primarily due to a decrease in gross receipts tax driven by decreases in electric revenue.

Taxes other than income increased for the year ended December 31, 2016, compared to the same period in 2015, primarily due to an increase in gross receipts tax driven by increases in electric revenue, which was impacted primarily by the new distribution rates that went into effect in January 2016.

~~Interest Expense, Net~~

The increase in Interest expense, net for the year ended December 31, 2017, compared to the same period in 2016, primarily reflects an increase in interest expense due to the issuance of First and Refunding Mortgage Bonds in September 2017.

The increase in Interest expense, net for the year ended December 31, 2016, compared to the same period in 2015, primarily reflects an increase in interest expense due to the issuance of First and Refunding Mortgage Bonds in October 2015.

~~Other, Net~~

~~Other, net remained relatively consistent for the year ended December 31, 2017, compared to the same period in 2016, and the year ended December 31, 2016, compared to the same period in 2015.~~

~~Effective Income Tax Rate~~

PECO’s effective income tax rates for the years ended December 31, 2017, 2016 and 2015 were 19.3%, 25.4% and 27.4%, respectively. See Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for further discussion of the change in effective income tax rates.

~~PECO Electric Operating Statistics and Revenue Detail~~

Retail Deliveries to Customers (in GWhs) 2017 2016 % Change 2017 vs. 2016
Weather-
Normal %
Change
2015 % Change 2016 vs. 2015
Weather-
Normal %
Change
Retail Deliveries ^(a)

Residential 13,024
13,664
(4.7 )% (1.8 )% 13,630
0.2 % 0.4 %
Small commercial & industrial 7,968
8,099
(1.6 )% (1.1 )% 8,118
(0.2 )% 0.5 %
Large commercial & industrial 15,426
15,263
1.1 % 1.4 % 15,365
(0.7 )% (1.4 )%
Public authorities & electric railroads 809
890
(9.1 )% (9.1 )% 881
1.0 % 1.0 %
Total electric retail deliveries 37,227
37,916
(1.8 )% (0.5 )% 37,994
(0.2 )% (0.3 )%

As of December 31,
Number of Electric Customers 2017 2016 2015
Residential 1,469,916
1,456,585
1,444,338
Small commercial & industrial 151,552
150,142
149,200
Large commercial & industrial 3,112
3,096
3,091
Public authorities & electric railroads 9,569
9,823
9,805
Total 1,634,149
1,619,646
1,606,434

Electric Revenue 2017 2016 % Change 2017 vs. 2016 2015 % Change 2016 vs. 2015
Retail Sales ^(a)

Residential $ 1,505
$ 1,631
(7.7 )% $ 1,599
2.0 %
Small commercial & industrial 401
430
(6.7 )% 428
0.5 %
Large commercial & industrial 223
234
(4.7 )% 221
5.9 %
Public authorities & electric railroads 30
32
(6.3 )% 31
3.2 %
Total retail 2,159
2,327
(7.2 )% 2,279
2.1 %
Other revenue ^(b)
216
204
5.9 % 207
(1.4 )%
Total electric operating revenues ^(c)
$ 2,375
$ 2,531
(6.2 )% $ 2,486
1.8 %

~~__________~~


~~(a)~~	Reflects delivery volumes and revenue from customers purchasing electricity directly from PECO and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. For customers purchasing electricity from PECO, revenue also reflects the cost of energy and transmission.


~~(b)~~	~~Other revenue includes transmission revenue from PJM and wholesale electric revenue.~~


~~(c)~~	~~Total electric revenue includes operating revenues from affiliates totaling $6 million, $7 million and $1 million for the years ended December 31, 2017, 2016, and 2015, respectively.~~

~~PECO Gas Operating Statistics and Revenue Detail~~

Deliveries to customers (in mmcf) 2017 2016 % Change 2017 vs. 2016
Weather-
Normal %
Change
2015 % Change 2016 vs. 2015
Weather-
Normal %
Change
Retail Deliveries ^(a)

Retail sales 58,457
56,447
3.6 % 1.2 % 59,003
(4.3 )% 1.5 %
Transportation and other 26,382
27,630
(4.5 )% (2.3 )% 27,879
(0.9 )% (0.1 )%
Total natural gas deliveries 84,839
84,077
0.9 % 0.1 % 86,882
(3.2 )% 1.0 %

As of December 31,
Number of Gas Customers 2017 2016 2015
Residential 477,213
472,606
467,263
Commercial & industrial 43,892
43,668
43,160
Total retail 521,105
516,274
510,423
Transportation 771
790
827
Total 521,876
517,064
511,250

Gas revenue 2017 2016 % Change 2017 vs. 2016 2015 % Change 2016 vs. 2015
Retail Sales ^(a)

Retail sales $ 462
$ 430
7.4 % $ 511
(15.9 )%
Transportation and other 33
33
— % 35
(5.7 )%
Total natural gas operating revenues ^(b)
$ 495
$ 463
6.9 % $ 546
(15.2 )%

~~__________~~


~~(a)~~	Reflects delivery volumes and revenue from customers purchasing natural gas directly from PECO and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges. For customers purchasing natural gas from PECO, revenue also reflects the cost of natural gas.


~~(b)~~	~~Total natural gas revenue includes operating revenues from affiliates totaling $1 million for the years ended December 31, 2017~~, ~~2016 and 2015.~~

~~Results of Operations—BGE~~

2017 2016 Favorable (unfavorable) 2017 vs. 2016 variance 2015 Favorable (unfavorable) 2016 vs. 2015 variance
Operating revenues $ 3,176
$ 3,233
$ (57 ) $ 3,135
$ 98
Purchased power and fuel expense 1,133
1,294
161
1,305
11
Revenues net of purchased power and fuel expense^(a)
2,043
1,939
104
1,830
109
Other operating expenses
Operating and maintenance 716
737
21
683
(54 )
Depreciation and amortization 473
423
(50 ) 366
(57 )
Taxes other than income 240
229
(11 ) 224
(5 )
Total other operating expenses 1,429
1,389
(40 ) 1,273
(116 )
Gain on sales of assets —
—
—
1
(1 )
Operating income 614
550
64
558
(8 )
Other income and (deductions)
Interest expense, net (105 ) (103 ) (2 ) (99 ) (4 )
Other, net 16
21
(5 ) 18
3
Total other income and (deductions) (89 ) (82 ) (7 ) (81 ) (1 )
Income before income taxes 525
468
57
477
(9 )
Income taxes 218
174
(44 ) 189
15
Net income 307
294
13
288
6
Preference stock dividends —
8
8
13
5
Net income attributable to common shareholder $ 307
$ 286
$ 21
$ 275
$ 11

~~__________~~

~~(a)~~

BGE evaluates its operating performance using the measures of revenue net of purchased power expense for electric sales and revenue net of fuel expense for gas sales. BGE believes revenues net of purchased power and fuel expense are useful measurements of its performance because they provide information that can be used to evaluate its net revenue from operations. BGE has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, revenues net of purchased power and fuel expense figures are not a presentation defined under GAAP and may not be comparable to other companies’ presentations or more useful than the GAAP information provided elsewhere in this report.

~~Net Income Attributable to Common Shareholder~~

~~Year Ended December 31, 2017 Compared to Year Ended December 31, 2016.~~ Net income attributable to common shareholder was higher primarily due to an increase in Revenues net of purchased power and fuel expense and lower Operating and maintenance expense, partially offset by higher Depreciation and amortization expense and higher income tax expense. The increase in Revenues net of purchased power and fuel expense was primarily due to the impacts of the electric and natural gas distribution rate orders issued by the MDPSC in June 2016 and July 2016 and an increase in transmission formula rate revenues. The lower Operating and maintenance expense was primarily due to the absence of cost disallowances resulting from the 2016 distribution rate orders issued by the MDPSC and

decreased storm costs in 2017 partially offset by the favorable 2016 settlement of the Baltimore City conduit fee dispute. These items were partially offset by an increase in Depreciation and amortization expense primarily related to the initiation of cost recovery of the AMI programs under the distribution rate orders and the impacts of increased capital investment and higher income tax expense primarily resulting from higher taxable income as well as a 2016 favorable adjustment and 2017 impairment of certain transmission-related income tax regulatory assets.

~~Year Ended December 31, 2016 Compared to Year Ended December 31, 2015.~~Net income attributable to common shareholder was higher primarily due to lower income tax expense and decreased preference stock dividends partially offset by slightly lower operating income. The lower income tax expense was driven by a one-time adjustment associated with transmission-related regulatory assets. The slight decrease in operating income was driven by an increase in Operating and maintenance expense as a result of cost disallowances which reduced certain regulatory assets and other long-lived assets stemming from the distribution rate orders issued by the MDPSC in June 2016 and July 2016 and increased storm costs. This increase in Operating and maintenance expense was offset by an increase in Revenues net of purchased power and fuel expense, primarily as a result of an increase in transmission formula rate revenues and higher electric and natural gas revenues as a result of the distribution rate orders issued by the MDPSC in June 2016 and July 2016.

~~Revenues Net of Purchased Power and Fuel Expense~~

There are certain drivers to Operating revenues that are offset by their impact on Purchased power and fuel expense, such as commodity procurement costs and programs allowing customers to select a competitive electric or natural gas supplier. Operating revenues and Purchased power and fuel expense are affected by fluctuations in commodity procurement costs. BGE’s electric and natural gas rates charged to customers are subject to periodic adjustments that are designed to recover or refund the difference between the actual cost of purchased electric power and purchased natural gas and the amount included in rates in accordance with the MDPSC’s market-based SOS and gas commodity programs, respectively. Therefore, fluctuations in electric supply and natural gas procurement costs have no impact on Revenues net of purchased power and fuel expense.

Electric and natural gas revenue and purchased power and fuel expense are also affected by fluctuations in the number of customers electing to use a competitive supplier for electricity and/or natural gas. All BGE customersCustomers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers. ~~The customers'~~Customer choice ~~of suppliers does~~programs do not impact the volume of deliveries ~~but does affect revenue collected from~~as PECO remains the distribution service provider for all customers ~~related~~and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to ~~supplied electricity and natural gas.~~

Retail deliveries purchased from competitive electricity and natural gas suppliers (as a percentage of kWh and mmcf sales, respectively) for the years ended December 31, 2017, 2016 and 2015 consisted of the following:

For the Years Ended December 31,

2017 2016 2015
Electric 60 % 59 % 61 %
Natural Gas 55 % 57 % 56 %

~~The number of retail customers purchasing electricity and~~purchase electric generation or natural gas from competitive suppliers, ~~at December 31, 2017, 2016~~PECO either acts as the billing agent or the competitive supplier separately bills its own customers and ~~2015 consisted of the following:~~

December 31, 2017 December 31, 2016 December 31, 2015
Number of Customers % of total retail customers Number of Customers % of total retail customers Number of Customers % of total retail customers
Electric 341,000
27 % 337,000
27 % 343,000
27 %
Natural Gas 151,000
22 % 151,000
23 % 154,000
23 %

~~The changes in BGE’s~~therefore PECO does not record Operating revenues ~~net of purchased~~or Purchased power and fuel expense ~~for the year ended December 31, 2017 compared~~related to the ~~same period~~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 ~~2016~~Operating revenues and ~~for the year ended December 31, 2016 compared~~Purchased power and fuel expense related to the ~~same period in 2015, respectively, consisted of the following:~~

2017 vs. 2016 2016 vs. 2015
Increase (Decrease) Increase (Decrease)
Electric Gas Total Electric Gas Total
Distribution rate increase $ 21
$ 29
$ 50
$ 24
$ 22
$ 46
Regulatory required programs 17
3
20
10
(5 ) 5
Transmission revenue 18
—
18
30
—
30
Other, net 5
11
16
24
4
28
Total increase $ 61
$ 43

$ 104
$ 88
$ 21
$ 109

~~Distribution Rate Increase.~~ ~~During the years ended December 31, 2017 and December 31, 2016, the increases in distribution revenues were primarily due to the impact of the electric and~~electricity, natural gas, ~~distribution rate changes that became effective in June 2016 in accordance with the electric~~ and ~~natural gas distribution rate case orders in June 2016 and July 2016.~~ RECs.

See Note 35 — ~~Regulatory Matters~~Segment Information of the Combined Notes to Consolidated Financial Statements for ~~additional information.~~the presentation of PECO's revenue disaggregation.

~~Revenue Decoupling.~~The demand for electricity and natural gas is affected by weather and usage conditions. The MDPSC allows BGE to record a monthly adjustment to its electric and natural gas distribution revenue from all residential customers, commercial electric customers, the majorityincrease of large industrial electric customers, and all firm service natural gas customers to eliminate the effect of abnormal weather and usage patterns per customer on BGE's electric and natural gas distribution volumes, thereby recovering a specified dollar amount of distribution revenue per customer, by customer class, regardless of fluctuations in actual consumption levels. This allows BGE to recognize revenue at MDPSC-approved distribution charges per customer, regardless of what BGE's actual distribution volumes were for a billing period. Therefore, while this revenue is affected by customer growth (i.e., increase in the number of customers), it will not be affected by volatility in actual weather or usage conditions (i.e., changes in consumption per customer). BGE bills or credits customers in subsequent months for the difference between approved revenue levels under revenue decoupling and actual customer billings.

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 BGE’s service territory. The changes in heating and cooling degree days in BGE’s service territory$454 million for the year ended December 31, ~~2017~~2022, compared to the same period in ~~2016~~2021, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.

The changes in Operating and maintenance expense consisted of the following:


	2022 vs. 2021
	(Decrease) Increase
Storm-related costs	$	(34)
Pension and non-pension postretirement benefits expense	(9)
Credit loss expense	6
Labor, other benefits, contracting, and materials	20
BSC costs	29
Other(a)	30
	42
Regulatory Required Programs	16
Total increase	$	58

__________

(a) Primarily reflects an increase in charitable contributions.

The changes in Depreciation and amortization expense consisted of the following:


	2022 vs. 2021
	Increase
Depreciation and amortization(a)	$	24
Regulatory asset amortization	1
Total increase	$	25

__________

(a)Depreciation and amortization expense increased primarily due to ongoing capital expenditures.

Table of Contents

PECO

Taxes other than income taxes increased by $18 million for the year ended December 31, ~~2016~~2022, compared to the same period in ~~2015, respectively, and normal weather consisted of the following:~~

For the Year Ended December 31, Normal % Change
Heating and Cooling Degree-Days 2017 2016 2017 vs. 2016 2017 vs. Normal
Heating Degree-Days 4,190
4,427
4,666
(5.4 )% (10.2 )%
Cooling Degree-Days 940
998
875
(5.8 )% 7.4 %

For the Year Ended December 31, Normal % Change
Heating and Cooling Degree-Days 2016 2015 2016 vs. 2015 2016 vs. Normal
Heating Degree-Days 4,427
4,666
4,684
(5.1 )% (5.5 )%
Cooling Degree-Days 998
924
876
8.0 % 13.9 %

~~Regulatory Required Programs.~~Revenue from regulatory required programs are billings for the costs of various legislative and/or regulatory programs that are recoverable from customers on a full and current basis. These programs are designed to provide full cost recovery, as well as a return in certain instances. The costs of these programs are included in Operating and maintenance expense, Depreciation and amortization expense and Taxes other than income in BGE's Consolidated Statements of Operations and Comprehensive Income.

~~Transmission Revenue.~~ Under a FERC approved formula, transmission revenue varies from year to year based upon rate adjustments to reflect fluctuations in the underlying costs, capital investments being recovered and other billing determinants. During the years ended December 31, 2017 and 2016, the increase in transmission revenue was2021, primarily due to increases in capital investment and operating and maintenance expense recoveries. See Operating and Maintenance Expense below and Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

~~Other, Net.~~ ~~Other net revenue,~~higher Pennsylvania gross receipts tax, which can vary from period to period, primarily includes late payment fees and other miscellaneous revenue such as service application fees, assistance provided to other utilities through BGE's mutual assistance program and recoveries of electric supply and natural gas procurement costs.

~~Operating and Maintenance Expense~~

Year Ended
December 31,

Increase
(Decrease)

Year Ended
December 31,

Increase
(Decrease)
2017 2016 2017 vs. 2016 2016 2015 2016 vs. 2015
Operating and maintenance
expense—baseline
$ 672
$ 701
$ (29 ) $ 701
$ 636
$ 65
Operating and maintenance
expense—regulatory required programs^(a)
44
36
8
36
47
(11 )
Total operating and maintenance expense $ 716
$ 737
$ (21 ) $ 737
$ 683
$ 54

~~__________~~


~~(a)~~	Operating and maintenance expense for regulatory required programs are costs for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues.

~~The changes~~is offset in Operating revenues, and ~~maintenance~~offset by lower Pennsylvania use tax.

Interest expense, net increased $16 million for the year ended December 31, ~~2017~~2022, compared to the same period in ~~2016 and the year ended December 31, 2016 compared to the same period in 2015 consisted of the following:~~

Increase (Decrease) 2017 vs. 2016 Increase (Decrease) 2016 vs. 2015
Baseline
Impairment on long-lived assets and losses on regulatory assets^(a)
$ (50 ) $ 52
Labor, other benefits, contracting and materials (11 ) 7
Storm-related costs (13 ) 18
Uncollectible accounts expense 7
(14 )
BSC costs 16
11
Conduit lease settlement^(b)
15
(15 )
Other 7
6
$ (29 ) $ 65
Regulatory Required Programs
Other 8
(11 )
8
(11 )
Total (decrease) increase $ (21 ) $ 54

~~__________~~


~~(a)~~	~~See Note 3~~—~~Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.~~


~~(b)~~	~~See Note 23— Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.~~

~~Depreciation and Amortization~~

The changes in Depreciation and amortization expense for the year ended December 31, 2017 compared to the same period in 2016 and December 31, 2016 compared to the same period in 2015 consisted of the following:

Increase (Decrease) 2017 vs. 2016 Increase (Decrease) 2016 vs. 2015
Depreciation expense^(a)
$ 13
$ 10
Regulatory asset amortization^(b)
25
31
Regulatory required programs^(c)
12
16
Increase in depreciation and amortization expense $ 50
$ 57

~~__________~~


~~(a)~~	~~Depreciation expense increased due to ongoing capital expenditures.~~

~~(b)~~

Regulatory asset amortization increased primarily due to an increase in regulatory asset amortization related to energy efficiency programs and the initiation of cost recovery of the AMI programs under the final electric and natural gas distribution rate case order issued by the MDPSC in June 2016. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.


~~(c)~~	Depreciation and amortization expenses for regulatory required programs are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues.

~~Taxes Other Than Income~~

Taxes other than income, which can vary period to period, include municipal and state utility taxes, real estate taxes and payroll taxes. Taxes other than income taxes increased for the year ended December 31, 2017 compared to the same period in 2016, and for the year ended December 31, 2016 compared to the same period in 2015,2021, primarily due to ~~an increase~~the issuance of debt in ~~property taxes.~~2021 and 2022 and increases in interest rates.

~~Interest Expense, Net~~

Interest expense, net remained relatively consistent for the year ended December 31, 2017 compared to the same period in 2016, and for the year ended December 31, 2016 compared to the same period in 2015.

~~Other, Net~~

~~Other, net remained relatively consistent for the year ended December 31, 2017, compared to the same period in 2016, and the year ended December 31, 2016, compared to the same period in 2015.~~

Effective ~~Income Tax Rate~~

~~BGE’s effective~~ income tax rates were 12.1% and 2.3% for the years ended December 31, ~~2017, 2016~~2022 and ~~2015 were 41.5%, 37.2% and 39.6%,~~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 1413 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

~~BGE Electric Operating Statistics and Revenue Detail~~

Retail Deliveries to Customers (in GWhs) 2017 2016 % Change 2017 vs. 2016
Weather-
Normal %
Change
2015 % Change 2016 vs. 2015
Weather-
Normal %
Change
Retail Deliveries^(a)

Residential 12,094
12,740
(5.1 )% (2.8 )% 12,598
1.1 % (3.2 )%
Small commercial & industrial
2,921
3,040
(3.9 )% (4.9 )% 3,119
(2.5 )% 2.7 %
Large commercial & industrial
13,688
13,957
(1.9 )% (2.4 )% 14,293
(2.4 )% (1.6 )%
Public authorities & electric railroads 268
283
(5.3 )% (3.0 )% 294
(3.7 )% (8.9 )%
Total electric deliveries 28,971
30,020
(3.5 )% (2.8 )% 30,304
(0.9 )% (1.9 )%

As of December 31,
Number of Electric Customers 2017 2016 2015
Residential 1,160,783
1,150,096
1,137,934
Small commercial & industrial
113,594
113,230
113,138
Large commercial & industrial
12,155
12,053
11,906
Public authorities & electric railroads 272
280
285
Total 1,286,804
1,275,659
1,263,263

Electric Revenue 2017 2016 % Change 2017 vs. 2016 2015 % Change 2016 vs. 2015
Retail Sales^(a)

Residential $ 1,428
$ 1,554
(8.1 )% $ 1,449
7.2 %
Small commercial & industrial
266
277
(4.0 )% 273
1.5 %
Large commercial & industrial
450
449
0.2 % 469
(4.3 )%
Public authorities & electric railroads 31
35
(11.4 )% 32
9.4 %
Total retail 2,175
2,315
(6.0 )% 2,223
4.1 %
Other revenue^(b)(c)
314
294
6.8 % 267
10.1 %
Total electric revenue

$ 2,489
$ 2,609
(4.6 )% $ 2,490
4.8 %

~~__________~~


~~(a)~~	Reflects delivery volumes and revenue from customers purchasing electricity directly from BGE and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. For customers purchasing electricity from BGE, revenue also reflects the cost of energy and transmission.


~~(b)~~	~~Other revenue primarily includes wholesale transmission revenue and late payment charges.~~


~~(c)~~	~~Includes operating revenues from affiliates totaling $5 million, $7 million and less than $1 million for the years ended 2017, 2016 and 2015, respectively.~~

Table of Contents

BGE ~~Natural Gas Operating Statistics and Revenue Detail~~

Deliveries to customers (in mmcf) 2017 2016 % Change 2017 vs. 2016
Weather-
Normal %
Change
2015 % Change 2016 vs. 2015
Weather-
Normal %
Change
Retail Deliveries^(a)

Retail sales 89,337
96,808
(7.7 )% (4.2 )% 96,618
0.2 % 3.5 %
Transportation and other^(b)
3,615
5,977
(39.5 )% n/a
6,238
(4.2 )% n/a
Total natural gas deliveries 92,952
102,785
(9.6 )% (4.2 )% 102,856
(0.1 )% 3.5 %

As of December 31,
Number of Gas Customers 2017 2016 2015
Residential 629,690
623,647
616,994
Commercial & industrial 44,247
44,255
44,119
Total 673,937
667,902
661,113

Natural Gas revenue 2017 2016 % Change 2017 vs. 2016 2015 % Change 2016 vs. 2015
Retail Sales^(a)

Retail sales $ 655
$ 593
10.5 % $ 607
(2.3 )%
Transportation and other^(b)
32
31
3.2 % 38
(18.4 )%
Total natural gas revenues^(c)

$ 687
$ 624
10.1 % $ 645
(3.3 )%

~~__________~~


~~(a)~~	Reflects delivery volumes and revenue from customers purchasing natural gas directly from BGE and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges. For customers purchasing natural gas from BGE, revenue also reflects the cost of natural gas.


~~(b)~~	Transportation and other natural gas revenue includes off-system revenue of 3,615 mmcfs ($21 million), 5,977 mmcfs ($23 million), and 6,238 mmcfs ($35 million) for the years ended 2017, 2016 and 2015, respectively.


~~(c)~~	~~Includes operating revenues from affiliates totaling $11 million, $14 million, and $14 million for the years ended 2017, 2016 and 2015, respectively.~~

Results of Operations—~~PHI~~BGE

~~PHI’s results~~


	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 ~~operations include~~ the ~~results~~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 ~~its three reportable segments, Pepco, DPL~~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

Table of Contents

BGE

Revenue Decoupling. The demand for electricity and ~~ACE~~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 ~~periods presented below.~~customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For ~~"Predecessor" reporting periods, PHI's results of operations also include~~customers that choose to purchase electric generation or natural gas from competitive suppliers, BGE acts as the ~~results of PES~~billing agent and ~~PCI.~~ 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 255 — Segment Information of the Combined Notes to Consolidated Financial Statements for ~~additional information regarding PHI's reportable segments. All material intercompany accounts and transactions have been eliminated in consolidation. A separate specific discussion~~the presentation of ~~the results~~BGE's revenue disaggregation.

The increase of ~~operations for Pepco, DPL and ACE is presented elsewhere in this report.~~

As a result of the PHI Merger, the following consolidated financial results present two separate reporting periods for 2016. The "Predecessor" reporting periods represent PHI's results of operations for the period of January 1, 2016 to March 23, 2016 and the year ended December 31, 2015. The "Successor" reporting periods represents PHI's results of operations for the year ended December 31, 2017 and for the period of March 24, 2016 to December 31, 2016. All amounts presented below are before the impact of income taxes, except as noted.

Successor Predecessor
For the Year Ended December 31, March 24 to December 31, January 1 to
March 23, For the Year Ended December 31,
2017 2016 2016 2015
Operating revenues $ 4,679
$ 3,643
$ 1,153
$ 4,935
Purchased power and fuel 1,716
1,447
497
2,073
Revenues net of purchased power and fuel expense^(a)
2,963
2,196
656

2,862
Other operating expenses
Operating and maintenance 1,068
1,233
294
1,156
Depreciation and amortization 675
515
152
624
Taxes other than income 452
354
105
455
Total other operating expenses 2,195
2,102
551

2,235
Gain (loss) on sales of assets 1
(1 ) —
46
Operating income 769
93
105
673
Other income and (deductions)
Interest expense, net (245 ) (195 ) (65 ) (280 )
Other, net 54
44
(4 ) 88
Total other income and (deductions) (191 ) (151 ) (69 )
(192 )
Income (loss) before income taxes 578
(58 ) 36
481
Income taxes 217
3
17
163
Equity in earnings of unconsolidated affiliates 1
—
—
—
Net income (loss) from continuing operations 362
(61 ) 19

318
Net income from discontinued operations —
—
—
9
Net income (loss) attributable to membership interest/common shareholders $ 362
$ (61 ) $ 19
$ 327

~~__________~~

~~(a)~~

PHI evaluates its operating performance using the measure of revenue net of purchased power and fuel expense for electric and natural gas sales. PHI believes revenue net of purchased power and fuel expense is a useful measurement because it provides information that can be used to evaluate its operational performance. PHI has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, Revenue net of purchased power and fuel expense 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.

~~Successor Year Ended December 31, 2017~~

~~PHI's Net income was $362~~$392 million for the year ended December 31, ~~2017. There were no significant~~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.

Table of Contents

BGE

The changes in the underlying trends affecting PHI's results of operations during the Successor year except for the impact of increases in electric distribution and natural gas rates within Revenue net of purchased power expense (Pepco electric distribution rates effective November 2016 and October 2017 in Maryland, Pepco electric distribution rates effective August 2017 in the District of Columbia, DPL electric distribution rates effective February 2017 in Maryland, DPL electric distribution and natural gas rates effective July 2016 and December 2016 in Delaware, and ACE electric distribution rates effective August 2016 and

~~October 2017 in New Jersey).~~ Operating and maintenance expense ~~incurred included~~ consisted of the deferral of merger-related, rate case, and customer billing system costs to regulatory assets and lower uncollectible accounts expense, partially offset by a pre-tax impairment charge of $25 million. Income taxes expense incurred included unrecognized tax benefits of $59 millionfollowing:


	2022 vs. 2021
	Increase (Decrease)
Asset impairment(a)	$	48
BSC costs	14
Credit loss expense	7
Labor, other benefits, contracting, and materials	4
Storm-related costs	(11)
Pension and non-pension postretirement benefits expense	(12)
Other	12
	62
Regulatory required programs	4
Total increase	$	66

__________

(a)See Note 11 — Asset Impairments for uncertain tax positions related to the deductibility of certain merger commitments in the first quarter of 2017, and was offset by a $27 million December 2017 impairment of certain transmission-related income tax regulatory assets and the one-time non-cash impacts of $35 million associated with the Tax Cuts and Jobs Act in 2017. For moreadditional information on ~~2017 results please refer~~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 ~~Results of Operations for Pepco, DPL, and ACE.~~ongoing capital expenditures.

~~PHI's effective~~Taxes other than income ~~tax rate~~taxes increased by $19 million for the year ended December 31, ~~2017 was 37.5%.~~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 143 — ~~Income Taxes~~Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information ~~regarding~~on both the ~~components of effective income tax rates.~~

~~Successor Period of March 24, 2016 to December 31, 2016~~

PHI's Net loss for the Successor period of March 24, 2016 to December 31, 2016 was $61 million. There were no significant changes in the underlying trends affecting PHI's results of operations during the Successor period March 24, 2016 to December 31, 2016 except for the pre-tax recording of $392 million of non-recurring merger-related costs including merger integrationthree-year electric and ~~merger commitments within Operating~~natural gas distribution multi-year plans and ~~maintenance expense. For more information on 2016 results please refer to Results of Operations for Pepco, DPL and ACE.~~

~~PHI's effective income tax rate for the period of March 24, 2016 to December 31, 2016 was (5.2)%. See~~ Note 1413 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

~~Predecessor Period~~

Table of ~~January 1, 2016~~Contents

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 ~~March 23, 2016~~

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 ~~Predecessor~~year ended December 31, 2022 compared to the same period in 2021. See the Results of ~~January 1, 2016~~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 ~~March 23, 2016 was $19 million. There were no significant~~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.

Table of Contents

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)
	42
Regulatory required programs	215
Total increase	$	257

Revenue Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from electric distribution in both Maryland and the District of Columbia are not impacted by abnormal weather or usage per customer as a result of a BSA that provides for a fixed distribution charge per customer by customer class. While Operating revenues are not impacted by abnormal weather or usage per customer, they are impacted by changes in the ~~underlying trends affecting PHI's results~~number of ~~operations during~~customers. See Note 3 — Regulatory Matters of the ~~Predecessor period~~Combined Notes to Consolidated Financial Statements for additional information on revenue decoupling for Pepco Maryland and District of ~~January 1, 2016 to March 23, 2016 except~~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

Table of Contents

Pepco

Distribution Revenue increased for the ~~pre-tax recording~~year ended December 31, 2022 compared to the same period in 2021, primarily due to favorable impacts of ~~$29 million~~the Maryland and District of ~~non-recurring merger-related~~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 ~~within~~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 ~~$18~~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 ~~preferred stock derivative~~regulatory required programs.

Table of Contents

Pepco

The changes in Operating and maintenance expense ~~within Other, net.~~ consisted of the following:

~~PHI's effective~~


	2022 vs. 2021
	Increase (Decrease)


Credit loss expense	$	17
BSC and PHISCO costs	13
Storm-related costs	8
Labor, other benefits, contracting, and materials	(2)



Other	(6)
	30
Regulatory required programs	6
Total increase	$	36

The changes in Depreciation and amortizationexpense consisted of the following:


	2022 vs. 2021
	Increase (Decrease)
Depreciation and amortization(a)	$	14
Regulatory asset amortization	(3)
Regulatory required programs	3
Total increase	$	14

__________

(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.

Taxes other than income taxes increased $9 million for the year ended December 31, 2022 compared to the same period in 2021, primarily due to an increase in property taxes and gross receipts taxes.

Interest expense, net increased $10 million for the year ended December 31, 2022 compared to the same period in 2021 primarily due to the issuance of debt in 2021 and 2022 and increases in interest rates.

Other, net increased $7 million for the year ended December 31, 2022 compared to the same period in 2021, primarily due to higher AFUDC equity.

Effective income tax ~~rate~~rates were (3.0)% and 4.8% for the ~~period~~years ended December 31, 2022 and 2021, respectively. The change is primarily due to the acceleration of ~~January 1, 2016 to March 23, 2016 was 47.2%.~~certain income tax benefits as a result of the Maryland and District of Columbia multi-year plans. See Note 143 — 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.

~~Predecessor Period~~

Table of Contents

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, ~~2015~~

PHI's Net income was $327 million for the year ended December 31, 2015. There were no significant changes in the underlying trends affecting PHI's results of operations during the Predecessor year except for the impact of increases in electric distribution rates within Revenue net of purchased power expense (Pepco electric distribution rates effective April 2014 in the District of Columbia, Pepco electric distribution rates effective July 2014 in Maryland, and ACE electric distribution rates effective September 2014), partially offset by Operating and maintenance costs incurred due to the implementation of a new customer information system for Pepco, DPL, and ACE in 2015. Gain (loss) on sales of assets were $46 million, primarily due to 2015 gains recorded at Pepco associated with the sale of unimproved land, held as non-utility property.

PHI's effective income tax rate for the year ended December 31, 2015 was 33.9%. See Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

~~Results of Operations~~—~~Pepco~~

2017 2016 Favorable (unfavorable) 2017 vs. 2016 variance 2015 Favorable (unfavorable) 2016 vs. 2015 variance
Operating revenues $ 2,158
$ 2,186
$ (28 ) $ 2,129
$ 57
Purchased power expense 614
706
92
719
13
Revenues net of purchased power expense^(a)
1,544
1,480
64
1,410
70
Other operating expenses
Operating and maintenance 454
642
188
439
(203 )
Depreciation and amortization 321
295
(26 ) 256
(39 )
Taxes other than income 371
377
6
376
(1 )
Total other operating expenses 1,146
1,314
168
1,071
(243 )
Gain on sales of assets 1
8
(7 ) 46
(38 )
Operating income 399
174
225
385
(211 )
Other income and (deductions)
Interest expense, net (121 ) (127 ) 6
(124 ) (3 )
Other, net 32
36
(4 ) 28
8
Total other income and (deductions) (89 ) (91 ) 2
(96 ) 5
Income before income taxes 310
83
227
289
(206 )
Income taxes 105
41
(64 ) 102
61
Net income $ 205
$ 42
$ 163
$ 187
$ (145 )

~~__________~~

~~(a)~~

Pepco evaluates its operating performance using the measure of revenue net of purchased power expense for electric sales. Pepco believes revenue net of purchased power expense is a useful measurement because it provides information that can be used to evaluate its operational performance. Pepco has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, Revenue net of purchased power expense 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.

~~Net Income~~

~~Year Ended December 31, 2017~~2022 Compared to Year Ended December 31, ~~2016.Pepco's~~ 2021.Net income ~~for the year ended December 31, 2017, was higher than the same period in 2016,~~increased by $41 million primarily due to higher distribution rates and the absence of the recognition of a ~~decrease in Operating and maintenance expense~~valuation allowance against a deferred tax asset due to ~~merger-related costs recognized~~a change in ~~March 2016 and an increase~~Delaware tax law in Revenue net of purchased power expense as a result of the distribution rate increases approved by the MDPSC effective November 2016 and October 2017 and an electric distribution rate increase approved by the DCPSC effective August 2017,2021, partially offset by higher depreciation expense due to increased depreciation rates in Maryland effective November 2016. Income taxes expense incurred included unrecognized tax benefits of $21 million for uncertain tax positions related to the deductibility of certain merger commitments in the first quarter of 2017. This decrease was offset by an increase in ~~income taxes due to the $14 million December 2017 impairment of certain transmission-related income tax regulatory assets~~depreciation expense, interest expense, storm costs, and ~~the one-time non-cash impacts of $8 million associated with the Tax Cuts and Jobs Act~~credit loss expense.

The changes in ~~2017.~~

~~Year Ended December 31, 2016 Compared to Year Ended December 31, 2015.~~ ~~Pepco's Net income for the year ended December 31, 2016, was lower than the same period in 2015, primarily due to an increase in Operating and maintenance expense due to merger-related costs.~~

~~Operating Revenue Net of Purchased Power Expense~~

Operating revenues include revenue from the distribution and supply of electricity to Pepco’s customers within its service territories at regulated rates. Operating revenues also include transmission service revenue that Pepco receives as a transmission owner from PJM at rates regulated by FERC. Transmission rates are updated annually based on a FERC-approved formula methodology.

Electric revenues and purchased power expense are also affected by fluctuations in participation in the Customer Choice Program. All Pepco customers have the choice to purchase electricity from competitive electric generation suppliers. The customers' choice of supplier does not impact the volume of deliveries, but affects revenue collected from customers related to supplied energy service.

~~Retail deliveries purchased from competitive electric generation suppliers (as a percentage of kWh sales) for the years ended December 31, 2017, 2016 and 2015 respectively,~~ 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

For the Years Ended December 31,
2017 2016 2015
Electric 66 % 65 % 65 %

~~Retail customers purchasing electric generation from competitive electric generation suppliers at December 31, 2017, 2016~~Revenue Decoupling. The demand for electricity is affected by weather and ~~2015 consisted of the following:~~

Retail deliveries purchased from competitive electric generation suppliers represented 73% of Pepco’s retail kWh sales to the District of Columbia customers and 60% of Pepco’s retail kWh sales to Maryland customers for the year ended December 31, 2017; 73% of Pepco’s retail kWh sales to the District of Columbia customers and 59% of Pepco’s retail kWh sales to Maryland customers for the year ended December 31, 2016; and 71% of Pepco’s retail kWh sales to the District of Columbia customers and 60% of Pepco’s retail kWh sales to Maryland customers for year ended December 31, 2015.

customer usage. However, Operating revenues ~~include transmission enhancement credits that Pepco receives~~from electric distribution in Maryland are not impacted by abnormal weather or usage per customer as a ~~transmission owner from PJM in consideration~~result of a BSA that provides for ~~approved regional transmission expansion plan expenditures.~~

a fixed distribution charge per customer by customer class. While Operating revenues also include work and services performed on behalf of customers, including other utilities, which is generally not subject to price regulation. Work and services includes mutual assistance to other utilities, highway relocation, rentals of pole attachments, late payment fees and collection fees.

~~Purchased power expense consists of the cost of electricity purchased by Pepco to fulfill its default electricity supply obligation and, as such, is recoverable~~ from ~~customers in accordance with the terms of public service commission orders.~~

The changes in Pepco’s Operating revenues net of purchased power expense for the years ended December 31, 2017 and 2016 compared to the same periods in 2016 and 2015, respectively, consisted of the following:

Increase (Decrease) 2017 vs. 2016 Increase (Decrease) 2016 vs. 2015
Volume $ 16
$ 15
Distribution rate increase 66
5
Regulatory required programs (12 ) 38
Transmission revenues 9
(1 )
Other (15 ) 13
Total increase $ 64
$ 70

~~Volume.~~The increase in operating revenues net of purchased power and fuel expense related to delivery volume, exclusive of the effects of weather, for the year ended December 31, 2017 compared to the same period in 2016 primarily reflects the impact of residential customer growth. The increase in operating revenues net of purchased power and fuel expense related to delivery volume, exclusive of the effects of weather, for the year ended December 31, 2016 compared to the same period in 2015 primarily reflects the impact of moderate economic and customer growth.

~~Distribution Rate Increase.The increase in electric operating revenues net of purchased power expense for the year ended December 31, 2017 compared to the same period in 2016 was primarily due to the impact of the higher~~ electric distribution ~~rates charged to~~ customers in Maryland ~~that became effective in November 2016 and October 2017 and higher electric distribution rates charged to customers~~are not impacted by abnormal weather or usage per customer, they are impacted by changes in the ~~District~~number of Columbia that became effective August 2017. The increase in distribution revenue for the year ended December 31, 2016 compared to the same period in 2015 was primarily due to the impact of the new electric distribution rates charged to customers in Maryland that became effective in November 2016.customers. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional ~~information.~~

~~Revenue Decoupling.~~Pepco’s results historically have been seasonal, generally producing higher revenue and income in the warmest and coldest periods of the year. For retail customers of Pepco in Maryland and in the District of Columbia, revenues are not affected by unseasonably warmer or colder weather because a bill stabilization adjustment (BSA) for retail customers was implemented that provides for a fixed distribution charge per customer. The BSA has the effect of decoupling the distribution revenue recognized in a reporting period from the amount of power delivered during the period. As a result, the only factors that will cause distribution revenue from customers in Maryland and the District of Columbia to fluctuate from period to period are changes in the number of customers and changes in the approved distribution charge per customer. Changes in customer usage (due to weather conditions, energy prices, energy efficiency programs or other reasons) from period to period have no impact on reported distribution revenue for customers to whom the BSA applies.

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 Pepco's service territory. The changes in heating and cooling degree days in Pepco’s service territory for the years ended December 31, 2017 and December 31, 2016 compared to same periods in 2016 and 2015, respectively, and normal weather consisted of the following:

For the Years Ended December 31, % Change
Heating and Cooling Degree-Days 2017 2016 Normal 2017 vs. 2016 2017 vs. Normal
Heating Degree-Days 3,312

3,624
3,869
(8.6 )% (14.4 )%
Cooling Degree-Days 1,767

1,936
1,653
(8.7 )% 6.9 %

For the Years Ended December 31, % Change
Heating and Cooling Degree-Days 2016 2015 Normal 2016 vs. 2015 2016 vs. Normal
Heating Degree-Days 3,624
3,657
3,887
(0.9 )% (6.8 )%
Cooling Degree-Days 1,936
1,936
1,626
— % 19.1 %

~~Regulatory Required Programs.~~ This represents the change in Operating revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs. The riders are designed to provide full and current cost recovery as well as a return. The costs of these programs are included in Operating and maintenance expense, Depreciation and amortization expense and Taxes other than income in Pepco's Consolidated Statements of Operations and Comprehensive Income. Revenue from regulatory required programs decreased for the year ended December 31, 2017 compared to the same period in 2016 primarily due to lower demand-side management program surcharge revenue due to a decrease in kWh sales and a rate decrease effective January 2017. Revenue from regulatory required programs increased for the year ended December 31, 2016 compared to the same period in 2015 primarily due to higher demand-side management program surcharge revenue due to a rate increase effective February 2016. Refer to the Operating and maintenance expense and Depreciation and amortization expense discussion below for additional information on ~~included programs.~~

~~Transmission Revenues~~.~~Under a FERC approved formula, transmission~~ revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered and other billing adjustments. Transmission revenue increased for the year ended December 31, 2017 compared to the same period in 2016 due to higher rates effective June 1, 2017 and June 1, 2016 related to increases in transmission plant investment and operating expenses. Transmission revenue decreased for the year ended December 31, 2016 compared to the same period in 2015 due to lower revenue related to the MAPP abandonment recovery period that ended in March 2016, partially offset by higher rates effective June 1, 2016 and June 1, 2015 related to increases in transmission plant investment and operating expenses.

~~Other.~~The decrease in other operating revenue net of purchased power expense for the year ended December 31, 2017 compared to the same period in 2016 is primarily due to lower pass-through revenue (which is substantially offset in Taxes other than income) primarily the result of lower sales that resulted in a decrease in utility taxes that are collected by Pepco on behalf of the jurisdiction. The increase in other operating revenue net of purchased power expense for the year ended December 31, 2016 compared to the same period in 2015 is primarily due to higher pass-through revenue (which is substantially offset in Taxes other than income) primarily the result of higher sales that resulted in an increase in utility taxes that are collected by Pepco on behalf of the jurisdiction.

~~Operating and Maintenance Expense~~

Year Ended December 31, Increase (Decrease) Year Ended December 31,
Increase
(Decrease)
2017 2016 2017 vs. 2016 2016 2015 2016 vs. 2015
Operating and maintenance expense - baseline $ 449
$ 631
$ (182 ) $ 631
$ 427
$ 204
Operating and maintenance expense - regulatory required programs^(a)
5
11
(6 ) 11
12
(1 )
Total operating and maintenance expense $ 454
$ 642
$ (188 ) $ 642
$ 439
$ 203

~~__________~~


~~(a)~~	Operating and maintenance expenses for regulatory required programs are costs for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues.

~~The changes in Operating and maintenance expense for 2017 compared to 2016 and 2016 compared to 2015 consisted of the following:~~

Increase (Decrease) 2017 vs. 2016 Increase (Decrease) 2016 vs. 2015
Baseline
Labor, other benefits, contracting and materials $ 16
$ 7
Storm-related costs (1 ) 6
Remeasurement of AMI-related regulatory asset^(a)
(7 ) 7
Deferral of billing system transition costs to regulatory asset —
(7 )
Deferral of merger-related costs to regulatory asset —
(11 )
Uncollectible accounts expense - provision (11 ) 8
BSC and PHISCO allocations^(b)
(24 ) 53
Merger commitments^(c)
(132 ) 126
Write-off of construction work in progress^(d)
(14 ) 13
Other (9 ) 2
(182 )
204
Regulatory required programs
Purchased power administrative costs (6 ) (1 )
Total (decrease) increase $ (188 ) $ 203

~~__________~~


~~(a)~~	~~Related to a remeasurement of a regulatory asset for legacy meters recognized in 2016.~~


~~(b)~~	~~Primarily related to merger severance and compensation costs recognized in 2016~~


~~(c)~~	~~Primarily related to merger-related commitments for customer rate credits and charitable contributions recognized in 2016.~~


~~(d)~~	~~Primarily resulting from a review of capital projects during the fourth quarter of 2016.~~

~~Depreciation and Amortization Expense~~

~~The changes in Depreciation and amortization expense for 2017 compared to 2016 and 2016 compared to 2015 consisted of the following:~~

Increase (Decrease) 2017 vs. 2016 Increase (Decrease) 2016 vs. 2015
Depreciation expense^(a)
$ 28
$ 11
Regulatory asset amortization^(b)
8
(11 )
Regulatory required programs ^(c)
(10 ) 39
Total increase $ 26
$ 39

~~_________~~


~~(a)~~	~~Depreciation expense increased primarily due to higher depreciation rates in Maryland effective November 2016 and ongoing capital expenditures.~~

~~(b)~~

Regulatory asset amortization increased for the year ended December 31, 2017 compared to the same period in 2016 primarily due to higher amortization of AMI-related regulatory assets, partially offset by lower amortization of MAPP abandonment costs. Regulatory asset amortization decreased for the year ended December 31, 2016 compared to the same period in 2015 primarily due to lower amortization of MAPP abandonment costs.

~~(c)~~

Regulatory required programs decreased for the year ended December 31, 2017 compared to the same period in 2016 primarily due to an EmPower Maryland surcharge rate decrease effective February 2016 and increased for the year ended December 31, 2016 compared to the same period in 2015 due to an EmPower Maryland surcharge rate increase effective February 2015. Depreciation and amortization expenses for regulatory required programs are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues and Operating and maintenance expense.

~~Taxes Other Than Income~~

Taxes other than income for the year ended December 31, 2017 compared to the same period in 2016 decreased primarily due to lower utility taxes that are collected and passed through by Pepco (which is substantially offset in Operating revenues), partially offset by higher property taxes. Taxes other than income for the year ended December 31, 2016 compared to the same period in 2015 increased primarily due to higher utility taxes that are collected and passed through by Pepco, partially offset by lower property taxes in Maryland.

~~Gain on Sales of Assets~~

Gain on sales of assets for the year ended December 31, 2017 compared to the same period in 2016 decreased primarily due to higher gains recorded in 2016 at Pepco associated with the sale of land. Gain on sale of assets for the year ended December 31, 2016 compared to the same period in 2015 decreased primarily due to higher gains recorded in 2015 at Pepco associated with the sale of land held as non-utility property.

~~Interest Expense, Net~~

Interest expense, net for the year ended December 31, 2017 compared to the same period in 2016 decreased primarily due to the recording of interest expense for an uncertain tax position in 2016, partially offset by higher interest expense associated with the issuance of long term debt in May 2017. Interest expense, net for the year ended December 31, 2016 compared to the same period in 2015 increased primarily due to the recording of interest expense for an uncertain tax position in 2016, partially offset by an increase in capitalized AFUDC debt.

~~Other, Net~~

~~Other, net for the year ended December 31, 2017 compared to the same period in 2016 decreased primarily due to the September 2016 reversal of contributions in aid of construction tax gross-~~

up reserves due to the determination that there is no legal obligation to refund customers per contract term. Other, net for the year ended December 31, 2016 compared to the same period in 2015 increased primarily due to higher income from AFUDC equity.

~~Effective Income Tax Rate~~

Pepco's effective income tax rates for the years ended December 31, 2017, 2016, and 2015 were 33.9%, 49.4%, and 35.3%, respectively. See Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective income tax rates. In the first quarter of 2017, Pepco decreased its liability for unrecognized tax benefits by $21 million resulting in a benefit to Income taxes and corresponding decrease to its effective tax rate. This decrease was offset by an increase in income taxes due to the $14 million December 2017 impairment of certain transmission-related income tax regulatory assets and the one-time non-cash impacts of $8 million associated with the Tax Cuts and Jobs Act in 2017.

As a result of the merger, Pepco recorded an after-tax charge of $31 million during the year ended December 31, 2016 as a result of the assessment and remeasurement of certain federal and state uncertain tax positions.

~~Pepco Electric Operating Statistics and Revenue Detail~~

Retail Deliveries to Customers (in GWhs) 2017 2016 % Change 2017 vs. 2016 Weather - Normal % Change 2015 % Change 2016 vs. 2015 Weather - Normal % Change
Retail Deliveries^(a)

Residential 7,831
8,372
(6.5 )% (2.5 )% 8,452
(0.9 )% (0.3 )%
Small commercial & industrial 1,303
1,459
(10.7 )% (9.0 )% 1,471
(0.8 )% (0.6 )%
Large commercial & industrial 14,988
15,559
(3.7 )% (2.5 )% 15,351
1.4 % 1.6 %
Public authorities & electric railroads 734
724
1.4 % 1.4 % 714
1.4 % 1.7 %
Total retail deliveries 24,856
26,114
(4.8 )% (2.8 )% 25,988
0.5 % 0.9 %

As of December 31,
Number of Electric Customers 2017 2016 2015
Residential 792,211
780,652
767,392
Small commercial & industrial

53,489
53,529
53,838
Large commercial & industrial 21,732
21,391
20,976
Public authorities & electric railroads 144
130
129
Total 867,576
855,702
842,335

Electric Revenue 2017 2016 % Change 2017 vs. 2016 2015 % Change 2016 vs. 2015
Retail Sales^(a)

Residential $ 956
$ 1,000
(4.4 )% $ 970
3.1 %
Small commercial & industrial 147
150
(2.0 )% 153
(2.0 )%
Large commercial & industrial 810
803
0.9 % 777
3.3 %
Public authorities & electric railroads 33
32
3.1 % 30
6.7 %
Total retail 1,946
1,985
(2.0 )% 1,930
2.8 %
Other revenue^(b)
212
201
5.5 % 199
1.0 %
Total electric revenue^(c)
$ 2,158
$ 2,186
(1.3 )% $ 2,129
2.7 %

~~__________~~


~~(a)~~	Reflects delivery volumes and revenues from customers purchasing electricity directly from Pepco and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. For customers purchasing electricity from Pepco, revenue also reflects the cost of energy and transmission.


~~(b)~~	~~Other revenue includes transmission revenue from PJM and wholesale electric revenues.~~


~~(c)~~	~~Includes operating revenues from affiliates totaling $6 million for the year ended December 31, 2017 and $5 million for the years ended December 31, 2016 and 2015, respectively.~~

~~Results of Operations~~—~~DPL~~

2017 2016 Favorable (unfavorable) 2017 vs. 2016 variance 2015 Favorable (unfavorable) 2016 vs. 2015 variance
Operating revenues $ 1,300
$ 1,277
$ 23
$ 1,302
$ (25 )
Purchased power and fuel expense 532
583
51
634
51
Revenues net of purchased power and fuel expense^(a)
768
694
74
668
26
Other operating expenses

Operating and maintenance 315
441
126
304
(137 )
Depreciation and amortization 167
157
(10 ) 148
(9 )
Taxes other than income 57
55
(2 ) 51
(4 )
Total other operating expenses 539
653
114
503
(150 )
Gain on sales of assets —
9
(9 ) —
9
Operating income 229
50
179
165
(115 )
Other income and (deductions)

Interest expense, net (51 ) (50 ) (1 ) (50 ) —
Other, net 14
13
1
10
3
Total other income and (deductions) (37 ) (37 ) —
(40 ) 3
Income before income taxes 192
13
179
125
(112 )
Income taxes 71
22
(49 ) 49
27
Net income (loss) $ 121
$ (9 ) $ 130
$ 76
$ (85 )

~~__________~~

~~(a)~~

DPL evaluates its operating performance using the measure of revenue net of purchased power expense for electric sales and revenue net of fuel expense for gas sales. DPL believes revenue net of purchased power expense and revenue net of fuel expense are useful measurements because they provide information that can be used to evaluate its operational performance. DPL has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, Revenue net of purchased power expense and Revenue net of fuel expense 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.

~~Net Income (Loss)~~

~~Year Ended December 31, 2017Compared to Year Ended December 31, 2016.~~ The increase in Net income was driven primarily by a decrease in Operating and maintenance expense primarily due to merger-related costs recognized in March 2016 and an increase in Revenues net of purchased power and fuel expense as a result of the distribution rate increases approved by the DPSC effective July and December 2016 and a distribution rate increase approved by the MDPSC effective February 2017, partially offset by higher depreciation expense due to increased depreciation rates in Maryland effective February 2017. Income taxes expense incurred included unrecognized tax benefits of $16 million for uncertain tax positions related to the deductibility of certain merger commitments in the first quarter of 2017. This decrease was offset by an increase in income taxes due to the $6 million December 2017 impairment of certain transmission-related income tax regulatory assets and the one-time non-cash impacts of $5 million associated with the Tax Cuts and Jobs Act in 2017.

~~Year Ended December 31, 2016 Compared to Year Ended December 31, 2015.~~ ~~The decrease in Net income was driven primarily by an increase in Operating and maintenance expense primarily due to merger-related costs.~~

~~Operating Revenue Net of Purchased Power and Fuel Expense~~

Operating revenues include revenue from the distribution and supply of electricity and natural gas to DPL’s customers within its service territories at regulated rates. Operating revenues also include transmission service revenue that DPL receives as a transmission owner from PJM at rates regulated by FERC. Transmission rates are updated annually based on a FERC-approved formula methodology.

Electric and natural gas revenues and purchased power and fuel expense are also affected by fluctuations in participation in the Customer Choice Program. All DPL customers have the choice to purchase electricity and gas from competitive electric generation and natural gas suppliers, respectively. The customers' choice of suppliers does not impact the volume of deliveries, but affects revenue collected from customers related to supplied energy and natural gas service.

Retail deliveries purchased from competitive electric generation and natural gas suppliers (as a percentage of kWh and mmcf sales, respectively) for the years ended December 31, 2017, 2016 and 2015, consisted of the following:

For the Years Ended December 31,
2017 2016 2015
Electric 52 % 51 % 51 %
Natural Gas 33 % 28 % 31 %

~~Retail customers purchasing electric generation and natural gas from competitive electric generation and natural gas suppliers at December 31, 2017, 2016 and 2015 consisted of the following:~~

~~Retail deliveries purchased from competitive electric generation suppliers represented 54% of DPL’s retail kWh sales to Delaware customers and 48% of DPL retail kWh sales to Maryland customers for~~

the year ended December 31, 2017; 53% of DPL’s retail kWh sales to Delaware customers and 48% of DPL’s retail kWh sales to Maryland customers for the year ended December 31, 2016; and 53% of DPL’s retail kWh sales to Delaware customers and 47% of DPL’s retail kWh sales to Maryland customers for the year ended December 31, 2015.

~~Operating revenues include transmission enhancement credits that DPL receives as a transmission owner from PJM in consideration for approved regional transmission expansion plan expenditures.~~

Operating revenues also include work and services performed on behalf of customers, including other utilities, which is generally not subject to price regulation. Work and services includes mutual assistance to other utilities, highway relocation, rentals of pole attachments, late payment fees and collection fees.

Natural gas operating revenues includes sources that are subject to price regulation (Regulated Gas Revenue) and those that generally are not subject to price regulation (Other Gas Revenue). Regulated gas revenue includes the revenue DPL receives from on-system natural gas delivered sales and the transportation of natural gas for customers within its service territory at regulated rates. Other gas revenue consists of off-system natural gas sales and the short-term release of interstate pipeline transportation and storage capacity not needed to serve customers. Off-system sales are made possible when low demand for natural gas by regulated customers creates excess pipeline capacity.

Purchased power expense consists of the cost of electricity purchased by DPL to fulfill its default electricity supply obligation and, as such, is recoverable from customers in accordance with the terms of public service commission orders. Purchased fuel expense consists of the cost of gas purchased by DPL to fulfill its obligation to regulated gas customers and, as such, is recoverable from customers in accordance with the terms of public service commission orders. It also includes the cost of gas purchased for off-system sales.

The changes in DPL’s Operating revenues net of purchased power and fuel expense for the years ended December 31, 2017 and 2016 compared to the same periods in 2016 and 2015, respectively, consisted of the following:

2017 vs. 2016 2016 vs. 2015
Increase (Decrease) Increase (Decrease)
Electric Gas Total Electric Gas Total
Weather $ (7 ) $ (13 ) $ (20 ) $ —
$ —
$ —
Volume 2
11
13
2
2
4
Distribution rate increase 65
4
69
2
1
3
Regulatory required programs (3 ) —
(3 ) 10
—
10
Transmission revenues 10
—
10
8
—
8
Other 6
(1 ) 5
1
—
1
Increase in revenue net of purchased power expense $ 73

$ 1

$ 74

$ 23

$ 3

$ 26

~~Revenue Decoupling.~~ DPL’s results historically have been seasonal, generally producing higher revenue and income in the warmest and coldest periods of the year. For retail customers of DPL in Maryland, revenues are not affected by unseasonably warmer or colder weather because a bill stabilization adjustment (BSA) for retail customers was implemented that provides for a fixed distribution charge per customer. The BSA has the effect of decoupling the distribution revenue recognized in a reporting period from the amount of power delivered during the period. As a result, the only factors that will cause distribution revenue from customers in Maryland to fluctuate from period to period are changes

in the number of customers and changes in the approved distribution charge per customer. A modified fixed variable rate design, which would provide for a charge not tied to a customer’s volumetric consumption of electricity or natural gas, has been proposed for DPL electricity and natural gas customers in Delaware. Changes in customer usage (due to weather conditions, energy prices, energy efficiency programs or other reasons) from period to period have no impact on reported distribution revenue for customers to whom the BSA applies.Maryland.

Weather.The demand for electricity and natural gas in ~~areas not subject to the BSA~~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, ~~2017~~2022 compared to the same period in ~~2016, operating~~2021, Operating revenues ~~net of purchased power and fuel expenses was lower~~related to weather increased due to ~~the impact of unfavorable~~favorable weather conditions in DPL's Delaware natural gas service territory. ~~During the year ended December 31, 2016 compared to the same period in 2015, weather was not a significant impact.~~

Table of Contents

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 ~~years~~year ended December 31, ~~2017 and December 31, 2016~~2022 compared to same ~~periods~~period in ~~2016 and 2015, respectively,~~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	%

Electric Service Territory For the Years Ended December 31, % Change
Heating and Cooling Degree-Days 2017 2016 Normal 2017 vs. 2016 2017 vs. Normal
Heating Degree-Days 4,077
4,319
4,519
(5.6 )% (9.8 )%
Cooling Degree-Days 1,300
1,453
1,210
(10.5 )% 7.4 %

For the Years Ended December 31, % Change
Heating and Cooling Degree-Days 2016 2015 Normal 2016 vs. 2015 2016 vs. Normal
Heating Degree-Days 4,319
4,421
4,572
(2.3 )% (5.5 )%
Cooling Degree-Days 1,453
1,328
1,188
9.4 % 22.3 %


	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)	%

Natural Gas Service Territory For the Years Ended December 31, % Change
Heating and Cooling Degree-Days 2017 2016 Normal 2017 vs. 2016 2017 vs. Normal
Heating Degree-Days 4,203
4,454
4,739
(5.6 )% (11.3 )%

For the Years Ended December 31, % Change
Heating and Cooling Degree-Days 2016 2015 Normal 2016 vs. 2015 2016 vs. Normal
Heating Degree-Days 4,454
4,618
4,754
(3.6 )% (6.3 )%

Volume,. ~~The increase in operating revenues net of purchased power and fuel expense related to delivery volume,~~ exclusive of the effects of weather, increased for the year ended December 31, ~~2017~~2022 compared to the same period in ~~2016,~~2021 primarily ~~reflects~~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 ~~impact~~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	%

Table of ~~customer growth. The increase~~Contents

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 ~~operating revenues net of purchased power and fuel expense related to~~ delivery ~~volume, exclusive of~~volumes assuming normalized weather based on the ~~effects~~historical 30-year average.

~~of weather,~~Distribution Revenue increased for the year ended December 31, ~~2016~~2022 compared to the same period in ~~2015,~~2021 primarily ~~reflects~~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 ~~impact of moderate economic~~underlying costs and ~~customer growth.~~

~~Distribution Rate Increase~~. ~~The increase in electric operating revenues net of purchased power expense~~capital investments being recovered. Transmission revenue increased for the year ended December 31, ~~2017~~2022 compared to the same period in ~~2016 was~~2021 primarily due to ~~the impact~~increases in underlying costs.

Other Revenue includes rental revenue, revenue related to late payment charges, mutual assistance revenues, and recoveries of the higher electric distribution and natural gas rates charged to Delaware customers that became effective in July and December 2016 and the impact of higher electric distribution rates charged to Maryland customers that became effective in February 2017. The increase in electric operating revenues net of purchased power expense for the year ended December 31, 2016 compared to the same period in 2015 was primarily due to the impact of the new electric distribution rates charged to Delaware customers that became effective in July 2016. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.other taxes.

Regulatory Required ~~Programs.~~ ~~This represents the change in operating~~Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency ~~programs.~~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.~~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 ~~Consolidated Statements~~revenue disaggregation.

The increase of ~~Operations and Comprehensive Income. Revenue from regulatory required programs decreased~~$167 million for the year ended December 31, ~~2017~~2022 compared to the same period in ~~2016~~2021, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.

Table of Contents

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 ~~lower demand-side management program surcharge revenue due to a decrease in kWh sales and a rate decrease effective January 2017. Revenue from regulatory required programs~~ ongoing capital expenditures.

Taxes other than income taxes increased by $5 million for the year ended December 31, ~~2016~~2022 compared to the same period in ~~2015~~2021, primarily due to ~~higher demand-side management program surcharge revenue due to a rate~~an increase ~~effective February 2016. Refer to the Operating~~in property taxes and ~~maintenance~~gross receipts taxes.

Interest expense, ~~and Depreciation and amortization expense discussion below for additional information on included programs.~~

Effective income tax rates ~~effective June 1, 2017~~ were 7.7%and ~~June 1, 2016 related to increases in transmission plant investment~~ 24.7% for the years ended December 31, 2022and ~~operating expenses. Transmission revenue increased~~2021, respectively. The decrease for the year ended December 31, 2016 compared to the same period in 2015 due to higher rates effective June 1, 2016 and June 1, 2015 related to increases in transmission plant investment and operating expenses, partially offset by lower revenue2022 is primarily related to the ~~MAPP abandonment recovery period that ended in March 2016.~~

~~Other.~~Other revenue, which can vary period to period, includes rental revenue, revenue related to late payment charges, assistance provided to other utilities through mutual assistance programs, and recoveries of other taxes.

~~Operating and Maintenance Expense~~

Year Ended December 31, Increase (Decrease) Year Ended December 31, Increase (Decrease)
2017 2016 2016 2015
Operating and maintenance expense - baseline $ 306
$ 425
$ (119 ) $ 425
$ 289
$ 136
Operating and maintenance expense - regulatory required programs^(a)
9
16
(7 ) 16
15
1
Total operating and maintenance expense $ 315
$ 441
$ (126 ) $ 441
$ 304
$ 137

~~__________~~


~~(a)~~	Operating and maintenance expenses for regulatory required programs are costs for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues.

~~The changes in Operating and maintenance expense for 2017 compared to 2016 and 2016 compared to 2015 consisted~~absence of the ~~following:~~

Increase (Decrease) 2017 vs. 2016 Increase (Decrease) 2016 vs. 2015
Baseline
Labor, other benefits, contracting and materials $ 4
$ 1
Storm-related costs 4
5
Deferral of billing system transition costs to regulatory asset 2
(2 )
  Deferral of merger-related costs to regulatory asset (6 ) (4 )
Uncollectible accounts expense - provision (10 ) 3
  BSC and PHISCO allocations^(a)
(15 ) 34
  Merger commitments^(b)
(88 ) 86
  Write-off of construction work in progress^(c)
(3 ) 4
Other (7 ) 9
(119 )
136
Regulatory required programs
Purchased power administrative costs (7 ) 1
Total (decrease) increase $ (126 ) $ 137

~~_________~~


~~(a)~~	~~Primarily related to merger severance and compensation costs recognized in 2016.~~


~~(b)~~	~~Primarily related to merger-related commitments for customer rate credits and charitable contributions recognized in 2016.~~


~~(c)~~	~~Primarily resulting from a review of capital projects during the fourth quarter of 2016.~~

~~Depreciation and Amortization Expense~~

~~The changes in Depreciation and amortization expense for 2017 compared to 2016 and 2016 compared to 2015 consisted~~recognition of ~~the following:~~

Increase (Decrease) 2017 vs. 2016 Increase (Decrease) 2016 vs. 2015
Depreciation expense^(a)
$ 14
$ 7
Regulatory asset amortization ^(b)
—
(7 )
Regulatory required programs^(c)
(4 ) 9
Total increase $ 10
$ 9

~~_________~~


~~(a)~~	~~Depreciation expense increased due to higher depreciation rates in Maryland effective February 2017 and due to ongoing capital expenditures.~~


~~(b)~~	~~Regulatory~~a valuation allowance against a deferred tax asset ~~amortization decreased for the year ended December 31, 2016 compared to the same period in 2015 primarily due to lower amortization of MAPP abandonment costs.~~

~~(c)~~

Regulatory required programs decreased for the year ended December 31, 2017 compared to the same period in 2016 primarily due to an EmPower Maryland surcharge rate decrease effective February 2016 and increased for the year ended December 31, 2016 compared to the same period in 2015 due to an EmPower Maryland surcharge rate increase effective February 2015. Depreciation and amortization expenses for regulatory required programs are recoverable from customers on a full and current basis through approved regulated rates. A partially offsetting amount has been reflected in Operating revenues and Operating and maintenance expense.

~~Taxes Other Than Income~~

Taxes other than income for the year ended December 31, 2017 compared to the same period in 2016 remained relatively constant. Taxes other than income for the year ended December 31, 2016 compared to the same period in 2015 increased primarily due to ~~higher property taxes~~a change in ~~Maryland related to higher property assessments and rate increases.~~

~~Gain on Sales of Assets~~

~~Gain on sales of assets for the year ended December 31, 2017 compared to the same period~~Delaware tax law in 2016 decreased primarily due to gains recorded in 2016 at DPL associated with the sale of land held as non-utility property. Gain on sales of assets for the year ended December 31, 2016 compared to the same period in 2015 increased primarily due to gains recorded in 2016 at DPL associated with the sale of land held as non-utility property.

~~Interest Expense, Net~~

Interest expense, net for the year ended December 31, 2017 compared to the same period in 2016 and for the year ended December 31, 2016 compared to the same period in 2015 remained relatively constant.

~~Other, Net~~

Other, net for the year ended December 31, 2017 compared to the same period in 2016 remained relatively constant. Other, net for the year ended December 31, 2016 compared to the same period in 2015 increased primarily due to higher income from AFUDC equity.

~~Effective Income Tax Rate~~

~~DPL's effective income tax rates for the years ended December 31, 2017, 2016 and 2015 were 37.0%, 169.2% and 39.2%, respectively.~~2021. See Note 1413 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective income tax rates. ~~In the first quarter~~

Table of ~~2017, DPL decreased its liability for unrecognized~~Contents

tax benefits by $16 million resulting in a benefit to Income taxes and corresponding decrease to its effective tax rate. This decrease was offset by an increase in income taxes due to the $6 million December 2017 impairment of certain transmission-related income tax regulatory assets and the one-time non-cash impacts of $5 million associated with the Tax Cuts and Jobs Act in 2017.

As a result of the merger, DPL recorded an after-tax charge of $23 million during the year ended December 31, 2016 as a result of the assessment and remeasurement of certain federal and state uncertain tax positions.

~~DPL Electric Operating Statistics and Revenue Detail~~

ACE

Retail Deliveries to Customers (in GWhs) 2017 2016 % Change 2017 vs. 2016 Weather - Normal % Change 2015 % Change 2016 vs. 2015 Weather - Normal % Change
Retail Deliveries^(a)

Residential 5,010
5,181
(3.3 )% (0.3 )% 5,337
(2.9 )% (2.9 )%
Small commercial & industrial 2,237
2,290
(2.3 )% (0.9 )% 2,311
(0.9 )% (1.3 )%
Large commercial & industrial 4,585
4,623
(0.8 )% 0.3 % 4,781
(3.3 )% (3.9 )%
Public authorities & electric railroads 44
46
(4.3 )% (8.3 )% 45
2.2 % 6.7 %
Total retail deliveries 11,876
12,140
(2.2 )% (0.2 )% 12,474
(2.7 )% (2.9 )%

As of December 31,
Number of Electric Customers 2017 2016 2015
Residential 459,389
456,181
453,145
Small commercial & industrial 60,697
60,173
59,714
Large commercial & industrial

1,400
1,411
1,410
Public authorities & electric railroads 629
643
643
Total 522,115
518,408
514,912

Electric Revenue 2017 2016 % Change 2017 vs. 2016 2015 % Change 2016 vs. 2015
Retail Sales^(a)

Residential $ 660
$ 668
(1.2 )% $ 681
(1.9 )%
Small commercial & industrial 185
187
(1.1 )% 192
(2.6 )%
Large commercial & industrial 102
98
4.1 % 101
(3.0 )%
Public authorities & electric railroads 14
13
7.7 % 12
8.3 %
Total retail 961

966
(0.5 )% 986
(2.0 )%
Other revenue^(b)
178
163
9.2 % 152
7.2 %
Total electric revenue^(c)
$ 1,139
$ 1,129
0.9 % $ 1,138
(0.8 )%

~~__________~~


~~(a)~~	Reflects delivery volumes and revenues from customers purchasing electricity directly from DPL and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. For customers purchasing electricity from DPL, revenue also reflects the cost of energy and transmission.


~~(b)~~	~~Other revenue includes transmission revenue from PJM and wholesale electric revenues.~~


~~(c)~~	~~Includes operating revenues from affiliates totaling $8 million, $7 million and $6 million for the years ended December 31, 2017, 2016 and 2015, respectively.~~

~~DPL Gas Operating Statistics and Revenue Detail~~

Retail Deliveries to Customers (in mmcf) 2017 2016 % Change 2017 vs. 2016 Weather Normal % change 2015 % Change 2016 vs. 2015 Weather Normal % change
Retail Deliveries
Residential 13,107
13,341
(1.8 )% 5.2 % 13,816
(3.4 )% (0.4 )%
Transportation & other 6,538
6,201
5.4 % 6.9 % 6,193
0.1 % 1.4 %
Total gas deliveries 19,645
19,542
0.5 % 5.7 % 20,009
(2.3 )% 0.1 %

As of December 31,
Number of Gas Customers 2017 2016 2015
Residential 122,347
120,951
119,771
Commercial & industrial 9,853
9,801
9,712
Transportation & other 154
156
159
Total 132,354
130,908
129,642

Gas Revenue 2017 2016 % Change 2017 vs. 2016 2015 % Change 2016 vs. 2015
Retail Sales^(a)

Retail sales $ 136
$ 127
7.1 % $ 143
(11.2 )%
Transportation & other^(b)
25
21
19.0 % 21
— %
Total gas revenues $ 161
$ 148
8.8 % $ 164
(9.8 )%

~~__________~~


~~(a)~~	Reflects delivery volumes and revenues from customers purchasing natural gas directly from DPL and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges. For customers purchasing natural gas from DPL, revenue also reflects the cost of natural gas.


~~(b)~~	~~Transportation and other revenue includes off-system natural gas sales and the short-term release of interstate pipeline transportation and storage capacity not needed to serve customers.~~

Results of ~~Operations~~—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

2017 2016 Favorable (unfavorable) 2017 vs. 2016 variance 2015 Favorable (unfavorable) 2016 vs. 2015 variance
Operating revenues $ 1,186
$ 1,257
$ (71 ) $ 1,295
$ (38 )
Purchased power expense 570
651
81
708
57
Revenues net of purchased power expense^(a)
616
606
10
587
19
Other operating expenses

Operating and maintenance 307
428
121
271
(157 )
Depreciation and amortization 146
165
19
175
10
Taxes other than income 6
7
1
7
—
Total other operating expenses 459
600
141
453
(147 )
Gain on sales of assets —
1
(1 ) —
1
Operating income 157
7
150
134
(127 )
Other income and (deductions)

Interest expense, net (61 ) (62 ) 1
(64 ) 2
Other, net 7
9
(2 ) 3
6
Total other income and
(deductions)
(54 ) (53 ) (1 ) (61 ) 8
Income (loss) before income taxes 103
(46 ) 149
73
(119 )
Income taxes 26
(4 ) (30 ) 33
37
Net income (loss) $ 77
$ (42 ) $ 119
$ 40
$ (82 )

~~__________~~

~~(a)~~

ACE evaluates its operating performance using the measure of revenue net of purchased power expense for electric sales. ACE believes Revenue net of purchased power expense is a useful measurement of its performance because it provides information that can be used to evaluate its operational performance. ACE has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, Revenue net of purchased power expense 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.

~~Net Income (Loss)~~

Year Ended December 31, ~~2017~~2022 Compared to Year Ended December 31, ~~2016.~~ ~~The increase in~~ 2021. Net income ~~was~~increased $2 million primarily due to ~~a decrease~~increases in ~~Operating and maintenance expense primarily due to merger-related costs recognized in March 2016 and an increase in Revenues net of purchased power expense resulting from impact of~~ distribution ~~rate increases approved by the NJBPU effective August 2016 and October 2017 and an increase in transmission formula rate revenues,~~rates, partially offset by lower customer usage. Income taxes expense incurred included unrecognized tax benefits of $22 million for uncertain tax positions related to the deductibility of certain merger commitments in the first quarter of 2017. This decrease was offset by an increase in ~~income taxes due to~~depreciation expense, the ~~December 2017 impairment~~absence of ~~certain transmission-related income tax regulatory assets~~favorable weather and volume as a result of ~~$7 million~~the CIP, and ~~the one-time non-cash impacts of $2 million associated with the Tax Cuts and Jobs Act in 2017.~~

~~Year Ended December 31, 2016 Compared to Year Ended December 31, 2015.~~ ~~The decrease in Net income was driven primarily by~~ an increase in ~~Operating and maintenance expense primarily due to merger-related costs.~~interest expense.

~~Revenues Net of Purchased Power Expense~~

The changes in Operating revenues include revenue from the distribution and supply of electricity to ACE’s customers within its service territories at regulated rates. Operating revenues also include transmission service revenue that ACE receives as a transmission owner from PJM at rates regulated by FERC. Transmission rates are updated annually based on a FERC-approved formula methodology.

Electric revenues and purchased power expense are also affected by fluctuations in participation in the Customer Choice Program. All ACE customers have the choice to purchase electricity from competitive electric generation suppliers. The customer's choice of supplier does not impact the volume of deliveries, but affects revenue collected from customers related to supplied energy service.

~~Retail deliveries purchased from competitive electric generation suppliers (as a percentage of kWh sales) for the years ended December 31, 2017, 2016 and 2015,~~ consisted of the following:


	2022 vs. 2021
	(Decrease) Increase
Weather	$	(3)
Volume	(11)
Distribution	48

Transmission	9



Other	(1)
	42
Regulatory required programs	1
Total increase	$	43

For the Years Ended December 31,
2017 2016 2015
Electric 48 % 47 % 45 %

~~Retail customers purchasing electric generation from competitive electric generation suppliers at December 31, 2017, 2016 and 2015 consisted of the following:~~

Operating revenues include revenue from Transition Bond Charges that ACE receives, and pays to ACE Funding, to fund the principal and interest payments on Transition Bonds, revenue from the resale in the PJM wholesale markets for energy and capacity purchased under contracts with unaffiliated NUGs, and revenue from transmission enhancement credits.

Purchased power expense consists of the cost of electricity purchased by ACE to fulfill its default electricity supply obligation and, as such, is recoverable from customers in accordance with the terms of public service commission orders.

The changes in ACE’s Operating revenues net of purchased power expense for the years ended December 31, 2017 and 2016 compared to the same periods in 2016 and 2015, respectively, consisted of the following:

Increase (Decrease) 2017 vs. 2016 Increase (Decrease) 2016 vs. 2015
Weather $ (3 ) $ (3 )
Volume (20 ) 1
Distribution rate increase 40
14
Regulatory required programs (24 ) (14 )
Transmission revenues 22
23
Other (5 ) (2 )
Increase in revenue net of purchased power expense $ 10
$ 19

~~Weather.~~Revenue Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from electric distribution in New Jersey are not impacted by abnormal weather or usage per customer as a result of the CIP which became effective, prospectively, in the third quarter of 2021. The CIP compares current distribution revenues by customer class to approved target revenues established in ACE’s most recent distribution base rate case. The CIP is calculated annually, and recovery is subject to certain conditions, including an earnings test and ceilings on customer rate increases. While Operating revenues are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers. See Note 3 — Regulatory Matters of the Combined Notes to the Consolidated Financial Statements for additional information on the ACE CIP.

Weather. Prior to the third quarter of 2021, the demand for electricity was affected by weather conditions. With respect to the electric business, very warm weather in summer months and very cold weather in winter months are referred to as “favorable weather conditions” because these weather conditions result in increased deliveries of electricity. Conversely, mild weather reduces demand. During the year ended December 31, ~~2017~~2022 compared to the same period in ~~2016, operating~~2021, Operating revenues ~~net of purchased power and fuel expense was lower~~related to weather decreased due to the ~~impact~~absence of ~~unfavorable winter weather conditions~~favorable impacts in ~~ACE's service territory. During~~ the ~~year ended December 31, 2016 compared to~~first and second quarter of 2022 as a result of the ~~same period in 2015, operating revenues net~~CIP.

Table of ~~purchased power and fuel expense was lower due to the impact of unfavorable winter weather conditions in ACE's service territory.~~Contents

~~For retail customers of~~ ACE distribution revenues are not decoupled for the distribution of electricity by ACE, and thus are subject to variability due to changes in customer consumption. Therefore, changes in customer usage (due to weather conditions, energy prices, energy savings programs or other reasons) from period to period have a direct impact on reported distribution revenue for customers in ACE's service territory.

Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 20-year period in ACE’s service territory. The changes in heating and cooling degree days in ACE’s service territory for the ~~years~~year ended December 31, ~~2017 and December 31, 2016~~2022 compared to same ~~periods~~period in ~~2016 and 2015, respectively,~~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	%

For the Years Ended December 31, Normal % Change
Heating and Cooling Degree-Days 2017 2016 2017 vs. 2016 2017 vs. Normal
Heating Degree-Days 4,206
4,487
4,713
(6.3 )% (10.8 )%
Cooling Degree-Days 1,228
1,303
1,115
(5.8 )% 10.1 %

For the Years Ended December 31, Normal % Change
Heating and Cooling Degree-Days 2016 2015 2016 vs. 2015 2016 vs. Normal
Heating Degree-Days 4,487
4,671
4,768
(3.9 )% (5.9 )%
Cooling Degree-Days 1,303
1,259
1,093
3.5 % 19.2 %

~~Volume.The decrease in operating revenues net of purchased power and fuel expense related to delivery volume,~~ Volume,exclusive of the effects of weather, decreased for the year ended December 31, ~~2017~~2022 compared to the same period in ~~2016,~~2021, primarily ~~reflects lower average customer usage, partially offset by~~due to the ~~impact~~absence of ~~customer growth. The increase~~favorable impacts in ~~operating revenues net~~the first and second quarter of ~~purchased power and fuel expense related to delivery volume, exclusive~~2022 as a result of the ~~effects of~~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, ~~2016~~2022 compared to the same period in ~~2015, primarily reflects~~2021 due to higher distribution rates that became effective in January 2022.

~~Distribution Rate Increase.~~ ~~The increase in electric operating revenues net of purchased power expense~~capital investments being recovered. Transmission revenue increased for the year ended December 31, ~~2017~~2022 compared to the same period in ~~2016 was~~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

Table of Contents

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 ~~new electric distribution rates charged~~Combined Notes to ~~customers that became effective in August 2016 and October 2017.~~ Consolidated Financial Statements for the presentation of ACE's revenue disaggregation.

The ~~increase in electric operating revenues net~~decrease of ~~purchased power expense~~$70 million for the year ended December 31, ~~2016~~2022 compared to same period in 2021, in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs.

The changes in Operating and maintenance expense consisted of the following:


	2022 vs. 2021
	(Decrease) Increase
Labor, other benefits, contracting and materials	$	(5)

Storm-related costs	1
BSC and PHISCO costs	1


Other	9
	6
Regulatory required programs(a)	5
Total increase	$	11

__________

(a)ACE is allowed to recover from or refund to customers the difference between its annual credit loss expense and the amounts collected in rates annually through the Societal Benefits Charge.

The changes in Depreciation and amortizationexpense consisted of the following:


	2022 vs. 2021
	Increase
Depreciation and amortization(a)	$	18
Regulatory asset amortization	2
Regulatory required programs(b)	62

Total increase	$	82

__________

(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.

(b)Regulatory required programs increased primarily due to the regulatory asset amortization of the PPA termination obligation which is fully offset in Operating revenues.

Interest expense, net increased $8 million for the year ended December 31, 2022 compared to the same period in ~~2015 was~~2021 primarily due to the ~~impact~~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 ~~new electric distribution rates charged~~July 14, 2021 settlement, which allowed ACE to ~~customers that became effective~~retain certain tax benefits in ~~August 2016.~~2021. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional ~~information.~~

~~Regulatory Required Programs.~~ ~~This represents~~information regarding the ~~change in operating revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs. The riders are designed to provide full~~July 14, 2021 settlement agreement and current cost recovery as well as a return. The costs of these programs are included in Operating and maintenance expense, Depreciation and amortization expense and Taxes other than income in ACE's Consolidated Statements of Operations and Comprehensive Income. Revenue from regulatory required programs decreased for the year ended December 31, 2017 compared to the same period in 2016 due to a rate decrease effective October 2016 for the ACE Transition Bond Charge and Market Transition Charge Tax. Revenue from required regulatory programs decreased for the year ended December 31, 2016 compared to the same period in 2015 due to rate decreases effective October 2016 and October 2015 for the ACE Market Transition charge tax. Refer to the Operating and maintenance expense and Depreciation and amortization expense discussion below for additional information on included programs.

~~Transmission Revenues~~.Under a FERC approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered and other billing adjustments. Transmission revenue increased for the year ended December 31, 2017 compared to the same period in 2016 due to higher rates effective June 1, 2017 and June 1, 2016 related to increases in transmission plant investment and operating expenses. Transmission revenue increased for the year ended December 31, 2016 compared to the same period in 2015 due to higher rates effective June 1, 2016 and June 1, 2015 related to increases in transmission plant investment and operating expenses.

~~Operating and Maintenance Expense~~

Year Ended December 31, Increase (Decrease) Year Ended December 31,
Increase
(Decrease)
2017 2016 2017 vs. 2016 2016 2015 2016 vs. 2015
Operating and maintenance expense - baseline $ 303
$ 424
$ (121 ) $ 424
$ 267
$ 157
Operating and maintenance expense - regulatory required programs^(a)
4
4
—
4
4
—
Total operating and maintenance expense $ 307
$ 428
$ (121 ) $ 428
$ 271
$ 157

~~__________~~


~~(a)~~	Operating and maintenance expenses for regulatory required programs are costs for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues.

~~The changes in Operating and maintenance expense for 2017 compared to 2016 and 2016 compared to 2015 consisted of the following:~~

Increase (Decrease) 2017 vs. 2016 Increase (Decrease) 2016 vs. 2015
Baseline
Labor, other benefits, contracting and materials $ 9
$ 6
BSC and PHISCO allocations^(a)
(11 ) 26
Merger commitments^(b)
(111 ) 111
Deferral of merger-related costs to regulatory asset (9 ) —
Other 1
14
Total (decrease) increase $ (121 ) $ 157

~~_________~~


~~(a)~~	~~Primarily related to merger severance and compensation costs recognized in 2016.~~


~~(b)~~	~~Primarily related to merger-related commitments for customer rate credits and charitable contributions recognized in~~ ~~2016.~~

~~Depreciation and Amortization Expense~~

~~The changes in Depreciation and amortization expense for 2017 compared to 2016 and 2016 compared to 2015 consisted of the following:~~

Increase (Decrease) 2017 vs. 2016 Increase (Decrease) 2016 vs. 2015
Depreciation expense^(a)
$ 6
$ 6
Regulatory asset amortization (2 ) (4 )
Required regulatory programs^(b)
(24 ) (12 )
Other 1
—
Total decrease $ (19 ) $ (10 )

~~_________~~


~~(a)~~	~~Depreciation expense increased due to ongoing capital expenditures.~~

~~(b)~~

Regulatory required programs decreased for the year ended December 31, 2017 compared to the same period in 2016 primarily as a result of lower revenue due to a rate decrease effective October 2016 for the ACE Transition Bond Charge and Market Transition Charge Tax. Required regulatory programs amortization decreased for the year ended December 31, 2016 compared to the same period in 2015 primarily as a result of lower revenue due to a rate decrease effective October 2015 for the ACE Market Transition charge tax. Depreciation and amortization expenses for regulatory required programs are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues and Operating and maintenance expense.

~~Taxes Other Than Income~~

Taxes other than income for the year ended December 31, 2017 compared to the same period in 2016, remained constant. Taxes other than income for the year ended December 31, 2016 compared to the same period in 2015, remained constant.

~~Interest Expense, Net~~

Interest expense, net remained relatively consistent for the year ended December 31, 2017, compared to the same period in 2016, and the year ended December 31, 2016, compared to the same period in 2015.

~~Gain on Sales of Assets~~

Gain on sales of assets for the year ended December 31, 2017 compared to the same period in 2016 decreased primarily due to gains recorded in 2016 at ACE associated with the sale of property. Gain on sales of assets for the year ended December 31, 2016 compared to the same period in 2015 increased primarily due to gains recorded in 2016 at ACE associated with the sale of property.

~~Other, Net~~

~~Effective Income Tax Rate~~

~~ACE's effective income tax rates for the years ended December 31, 2017, 2016 and 2015 were 25.2%, 8.7%, and 45.2%, respectively. See~~ Note 1413 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the ~~change in~~ effective income tax rates. ~~In the first quarter~~

Table of 2017, ACE decreased its liability for unrecognized tax benefits by $22 million resulting in a benefit to Income taxes and corresponding decrease to its effective tax rate. This decrease was offset by an increase in income taxes due to the December 2017

~~impairment of certain transmission-related income tax regulatory assets of $7 million and the one-time non-cash impacts of $2 million associated with the Tax Cuts and Jobs Act in 2017.~~

As a result of the merger, ACE recorded an after-tax charge of $22 million during the year ended December 31, 2016 as a result of the assessment and remeasurement of certain federal and state uncertain tax positions.

~~ACE Electric Operating Statistics and Revenue Detail~~

Contents

Retail Deliveries to Customers (in GWhs) 2017 2016 % Change 2017 vs. 2016 Weather - Normal % Change 2015 % Change 2016 vs. 2015 Weather - Normal % Change
Retail Deliveries^(a)

Residential 3,853
4,153
(7.2 )% (6.2 )% 4,322
(3.9 )% (2.9 )%
Small commercial & industrial 1,286
1,455
(11.6 )% (11.1 )% 1,288
13.0 % 13.5 %
Large commercial & industrial 3,399
3,402
(0.1 )% 0.4 % 3,594
(5.3 )% (5.2 )%
Public authorities & electric railroads 47
49
(4.1 )% (4.1 )% 45
8.9 % 8.9 %
Total retail deliveries 8,585
9,059
(5.2 )% (4.5 )% 9,249
(2.1 )% (1.4 )%

As of December 31,
Number of Electric Customers 2017 2016 2015
Residential 487,168
484,240
482,000
Small commercial & industrial 61,013
61,008
60,745
Large commercial & industrial 3,684
3,763
3,871
Public authorities & electric railroads 636
610
529
Total 552,501
549,621
547,145

% Change 2017 vs. 2016 % Change 2016 vs. 2015
Electric Revenue 2017 2016 2015
Retail Sales^(a)

Residential $ 619
$ 664
(6.8 )% $ 690
(3.8 )%
Small commercial & industrial 166
183
(9.3 )% 175
4.6 %
Large commercial & industrial 189
201
(6.0 )% 213
(5.6 )%
Public authorities & electric railroads 13
13
— % 12
8.3 %
Total retail 987
1,061
(7.0 )% 1,090
(2.7 )%
Other revenue^(b)
199
196
1.5 % 205
(4.4 )%
Total electric revenue^(c)
$ 1,186
$ 1,257
(5.6 )% $ 1,295
(2.9 )%

~~__________~~


~~(a)~~	Reflects delivery volumes and revenues from customers purchasing electricity directly from ACE and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. For customers purchasing electricity from ACE, revenue also reflects the cost of energy and transmission.

~~(b) Other revenue includes transmission revenue from PJM and wholesale electric revenues.~~

~~(c) Includes operating revenues from affiliates totaling $2 million, $3 million and $4 million for the years ended December 31, 2017, 2016 and 2015, respectively.~~

Liquidity and Capital Resources

Exelon activity presented below includes the activity of PHI, Pepco, DPL and ACE, from the PHI Merger effective date of March 24, 2016 through December 31, 2017. Exelon prior year activity is unadjusted for the effects of the PHI Merger. Due to the application of push-down accounting to the PHI entity, PHI's activity is presented in two separate reporting periods, the legacy PHI activity through March 23, 2016 (Predecessor), and PHI activity for the remainder of the period after the PHI merger date (Successor). For each of Pepco, DPL and ACE the activity presented below include its activity for the years ended December 31, 2017, 2016 and 2015. 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 ~~unsecured revolving~~ credit facilities with aggregate bank commitments of ~~$9 billion. In addition, Generation has $480 million in bilateral facilities with banks which have various expirations between January 2019 and~~$4.0 billion, as of December ~~2019.~~31, 2022. The Registrants utilize their credit facilities to support their commercial paper programs, provide for other short-term borrowings, and to issue letters of credit. See the “Credit ~~Matters”~~Matters and Cash Requirements” section below for ~~further discussion.~~additional information. The Registrants expect cash flows to be sufficient to meet operating expenses, financing costs, and capital expenditure requirements.

The Registrants primarily use their capital resources, including cash, to fund capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and other postretirement benefit obligations and invest in new and existing ventures. The Registrants spend a significant amount of cash on capital improvements and construction projects that have a long-term return on investment. Additionally, ComEd, PECO, BGE, Pepco, DPL and ACE operate in rate-regulated environments in which the amount of new investment recovery may be delayed or limited and where such recovery takes place over an extended period of time. See Note 1316 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for ~~further discussion of~~additional information on the Registrants’ debt and credit agreements.

~~NRC Minimum Funding Requirements~~

~~NRC regulations require that licensees~~Cash flows related to Generation have not been presented as discontinued operations and are included in the Consolidated Statements of nuclear generating facilities demonstrate reasonable assurance that sufficient funds will be available in certain minimum amounts to decommission the facility. These NRC minimum funding levels are based upon the assumption that decommissioning activities will commence after the end of the current licensed life of each unit. If a unit fails the NRC minimum funding test, then the plant’s owners or parent companies would be required to take steps, such as providing financial guarantees through letters of credit or parent company guarantees or making additional cash contributions to the NDT fund to ensure sufficient funds are available. See Note 15 - Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information on the NRC minimum funding requirements.

If a nuclear plant were to early retire there is a risk that it will no longer meet the NRC minimum funding requirements due to the earlier commencement of decommissioning activities and a shorter time period over which the NDT fund investments could appreciate in value. A shortfall could require Exelon to post parental guarantees for Generation’s share of the obligations. However, the amount of any required guarantees will ultimately depend on the decommissioning approach adopted at each site, the associated level of costs, and the decommissioning trust fund investment performance going forward.

Within two years after shutting down a plant, Generation must submit a post-shutdown decommissioning activities report (PSDAR) to the NRC that includes the planned option for decommissioning the site. As discussed in Note 15 - Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements, Generation filed its biennial decommissioning funding status report with the NRC on March 31, 2017 and demonstrated adequate funding assuranceCash Flows for all ~~nuclear units currently operating. As~~periods presented. The Exelon Consolidated Statement of Cash Flows for the year ended December 31, ~~2017, across the four alternative decommissioning approaches available, Generation estimates a parental guarantee~~2022 includes one month of ~~up to $90 million~~cash flows from Generation. The Exelon ~~could be required for TMI, dependent upon the ultimate decommissioning approach selected. For Oyster Creek, none~~Consolidated Statement of the alternative decommissioning approaches available would require Exelon to post a parental guarantee. In the event PSEG decides to early retire Salem, Generation estimates a parental guarantee of up to $45 million from Exelon could be required for Salem, dependent upon the ultimate decommissioning approach selected.

Upon issuance of any required financial guarantees, each site would be able to utilize the respective NDT funds for radiological decommissioning costs, which represent the majority of the total expected decommissioning costs. However, the NRC must approve an additional exemption in orderCash Flows for the ~~plant’s owner(s) to utilize~~year ended December 31, 2021 includes twelve months of cash flows from Generation. This is the ~~NDT fund to pay~~primary reason for ~~non-radiological decommissioning costs (i.e., spent fuel management and site restoration costs). If a unit does not receive this exemption,~~ the costs would be borne by the owner(s). While the ultimate amounts may vary greatly and could be reduced by alternate decommissioning scenarios and/or reimbursement of certain costs under the United States Department of Energy reimbursement agreements or future litigation, across the four alternative decommissioning approaches available, if TMI or Oyster Creek were to fail to obtain the exemption, Generation estimates it could incur spent fuel management and site restoration costs over the next ten years of up to $225 million and $200 million net of taxes, respectively, dependent upon the ultimate decommissioning approach selected. In the event PSEG decides to early retire Salem and Salem were to fail to obtain the exemption, Generation estimates it could incur spent fuel management and site restoration costs over the next ten years of up to $80 million net of taxes.

~~Junior Subordinated Notes~~

~~In June 2014, Exelon issued $1.15 billion of junior subordinated notes~~changes in cash flows as shown in the form of 23 million equity units at a stated amount of $50.00 per unit. Each equity unit represented an undivided beneficial ownership interest in Exelon’s $1.15 billion of 2.50% junior subordinated notes due in 2024 (“2024 notes”) and a forward equity purchase contract. As contemplated in the June 2014 equity unit structure, in April 2017, Exelon completed the remarketing of the 2024 notes into $1.15 billion of 3.497% junior subordinated notes due in 2022 (“Remarketing”). Exelon conducted the Remarketing on behalf of the holders of equity units and did not directly receive any proceeds therefrom. Instead, the former holders of the 2024 notes used debt remarketing proceeds towards settling the forward equity purchase contract with Exelon on June 1, 2017. Exelon issued approximately 33 million shares of common stock from treasury stock and received $1.15 billion upon settlement of the forward equity purchase contract. When reissuing treasury stock Exelon uses the average price paid to repurchase shares to calculate a gain or loss on issuance and records gains or losses directly to retained earnings. A loss on reissuance of treasury shares of $1.05 billion was recorded to retained earnings as of December 31, 2017. See Note 21 — Earnings Per Share of the Combined Notes to Consolidated Financial Statements for further information on the issuance of common stock.tables unless otherwise noted below.

Cash Flows from Operating Activities

~~General~~

Generation’s cash flows from operating activities primarily result from the sale of electric energy and energy-related products and services to customers. Generation’s future cash flows from operating activities may be affected by future demand for and market prices of energy and its ability to continue to produce and supply power at competitive costs as well as to obtain collections from customers.

The Utility Registrants' cash flows from operating activities primarily result from the transmission and distribution of electricity and, in the case of PECO, BGE, and DPL, gas distribution services. The Utility Registrants' distribution services are provided to an established and diverse base of retail customers. The Utility Registrants' future cash flows may be affected by the economy, weather conditions, future legislative initiatives, future regulatory proceedings with respect to their rates or operations, ~~competitive suppliers,~~ and their ability to achieve operating cost reductions. Additionally, ComEd is required to purchase CMCs from participating nuclear-powered generating facilities for a five-year period, and all of its costs of doing so will be recovered through a new rider. The price to be paid for each CMC is established through a competitive bidding process. ComEd will provide net payments to, or collect net payments from, customers for the difference between customer credits issued and the credit to be received from the participating nuclear-powered generating facilities. ComEd’s cash flows are affected by the establishment of CMC prices and the timing of recovering costs through the CMC regulatory asset.

See ~~Notes~~Note 3 — Regulatory Matters and 23Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for ~~further discussion of~~additional information on regulatory and legal proceedings and proposed legislation.

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The following table provides a summary of the ~~major items affecting Exelon’s~~change in cash flows from ~~operations~~operating activities for the years ended December 31, ~~2017, 2016~~2022 and ~~2015:~~2021 by Registrant:

2017 2016 2017 vs. 2016 Variance 2015 2016 vs. 2015 Variance
Net income $ 3,849
$ 1,204
$ 2,645
2,250
$ (1,046 )
Add (subtract):
Non-cash operating activities^(a)
5,446
7,722
(2,276 ) 5,630
2,092
Pension and non-pension
postretirement benefit
contributions (405 ) (397 ) (8 ) (502 ) 105
Income taxes 299
(674 ) 973
97
(771 )
Changes in working capital and other noncurrent assets and liabilities^(b)
(1,579 ) (275 ) (1,304 ) (264 ) (11 )
Option premiums received (paid), net 28
(66 ) 94
58
—
(124 )
Collateral received
(posted), net (158 ) 931
(1,089 ) 347
584
Net cash flows provided by operations $ 7,480
$ 8,445
$ (965 ) $ 7,616
$ 829

~~__________~~

~~(a)~~

Represents depreciation, amortization, depletion and accretion, net fair value changes related to derivatives, deferred income taxes, provision for uncollectible accounts, pension and non-pension postretirement benefit expense, equity in earnings and losses of unconsolidated affiliates and investments, decommissioning-related items, stock compensation expense, impairment of long-lived assets, and other non-cash charges. See Note 24 —Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements for further detail on non-cash operating activity.


~~(b)~~	~~Changes in working capital and other noncurrent assets and liabilities exclude the changes in commercial paper, income taxes and the current portion of long-term debt.~~

~~Pension and Other Postretirement Benefits~~

Management considers various factors when making pension funding decisions, including actuarially determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act of 2006 (the Act), management of the pension obligation and regulatory implications. The Act requires the attainment of certain funding levels to avoid benefit restrictions (such as an inability to pay lump sums or to accrue benefits prospectively), and at-risk status (which triggers higher minimum contribution requirements and participant notification). The projected contributions below reflect a funding strategy of contributing the greater of (1) $300 million (updated for the inclusion of PHI) until the qualified plans are fully funded on an ABO basis, and (2) the minimum amounts under ERISA to avoid benefit restrictions and at-risk status. This level funding strategy helps minimize volatility of future period required pension contributions. Unlike

~~the qualified pension plans, Exelon’s non-qualified pension plans are not funded given that they are not subject to statutory minimum contribution requirements.~~

While other postretirement plans are also not subject to statutory minimum contribution requirements, Exelon does fund certain of its plans. For Exelon's funded OPEB plans, contributions generally equal accounting costs, however, Exelon’s management has historically considered several factors in determining the level of contributions to its other postretirement benefit 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 other postretirement plans in 2018:

Qualified Pension Plans Non-Qualified Pension Plans Other
Postretirement
Benefits
Exelon $ 301
$ 30
$ 42
Generation 119
11
13
ComEd 38
2
3
PECO 17
1
—
BGE 41
1
16
BSC 36
7
1
PHI 50
8
9
Pepco 4
2
8
DPL —
1
—
ACE 6
—
—
PHISCO 40
5
1

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.

On October 3, 2017, the US Department of Treasury and IRS released final regulations updating the mortality tables to be used for defined benefit pension plan funding, as well as the valuation of lump sum and other accelerated distribution options, effective for plan years beginning in 2018. The new mortality tables reflect improved projected life expectancy as compared to the existing table, which is generally expected to increase minimum pension funding requirements, Pension Benefit Guaranty Corporation premiums and the value of lump sum distributions. The IRS permits plan sponsors the option of delaying use of the new mortality tables for determining minimum funding requirements until 2019, which Exelon intends to utilize. The one-year delay does not apply for use of the mortality tables to determine the present value of lump sum distributions. The estimated impact of the new mortality tables along with other current assumptions and market information are reflected in the estimated future pension contributions in the “Contractual Obligations” section below.

~~The EMA requires CENG to fund the obligation related to pre-transfer service of employees, including the underfunded balance of the pension and other postretirement welfare benefit plans~~

measured as of July 14, 2014 by making periodic payments to Generation. These payments will be made on an agreed payment schedule or upon the occurrence of certain specified events, such as EDF’s disposition of a majority of its interest in CENG. However, in the event that EDF exercises its rights under the Put Option, all payments not made as of the put closing date shall accelerate to be paid immediately prior to such closing date. See Note 2 — Variable Interest Entities of the Combined Notes to Consolidated Financial Statements for additional information regarding the investment in CENG.

~~Tax Matters~~

~~The Registrants’ future cash flows from operating activities may be affected by the following tax matters:~~

Pursuant to the TCJA, beginning in 2018 Generation is expected to have higher operating cash flows in the range of approximately $1.2 billion to $1.6 billion for the period from 2018 to 2021, reflecting the reduction in the corporate federal income tax rate and full expensing of capital investments.

The TCJA is generally expected to result in lower operating cash flows for the Utility Registrants as a result of the elimination of bonus depreciation and lower customer rates. Increased operating cash flows for the Utility Registrants from lower corporate federal income tax rates is expected to be more than offset over time by lower customer rates resulting from lower income tax expense recoveries and the settlement of deferred income tax net regulatory liabilities established pursuant to the TCJA. The amount and timing of settlement of the net regulatory liabilities will be determined by the Utility Registrants’ respective rate regulators, subject to certain IRS “normalization” rules. The table below sets forth the Registrants’ estimated categorization of their net regulatory liabilities as of December 31, 2017. The amounts in the table below are shown on an after-tax basis reflecting future net cash outflows after taking into consideration the income tax benefits associated with the ultimate settlement with customers.

Successor
Exelon ComEd
PECO^(a)
BGE PHI PEPCO DPL ACE
Subject to IRS Normalization Rules $ 3,040
$ 1,400
$ 533
$ 459
$ 648
$ 299
$ 195
$ 153
Subject to Rate Regulator Determination 1,694
573
43
324
754
391
194
170
Net Regulatory Liabilities $ 4,734
$ 1,973
$ 576
$ 783
$ 1,402
$ 690
$ 389
$ 323

~~__________~~

~~(a)~~

Given the regulatory treatment of income tax benefits related to electric and gas distribution repairs, PECO remains in an overall net regulatory asset position as of December 31, 2017 after recording the impacts related to the TCJA. As a result, the amount of customer benefits resulting from the TCJA subject to the discretion of PECO's rate regulators are lower relative to the other Utility Registrants. Refer to Note 3 - Regulatory Matters for additional information.

Net regulatory liability amounts subject to normalization rules generally may not be passed back to customers any faster than over the remaining useful lives of the underlying assets giving rise to the associated deferred income taxes. Such deferred income taxes generally relate to property, plant and equipment with remaining useful lives ranging from 30 to 40 years across the Utility Registrants. For the remaining amounts, rate regulators could require the passing back of amounts to customers over shorter time frames, which could materially decrease operating cash outflows at each of the Utility Registrants in the near term.

The Utility Registrants expect to fund any such required incremental operating cash outflows using a combination of third party debt financings and equity funding from Exelon in combinations generally consistent with existing capitalization ratio structures. To fund any additional equity contributions to the Utility Registrants, Exelon would have available to it its typical sources, including, but not limited to, the increased operating cash flows at Generation

~~referenced above, which over time are expected to exceed the incremental equity needs at the Utility Registrants.~~

The Utility Registrants continue to work with their state regulatory commissions to determine the amount and timing of the passing back of TCJA income tax savings benefits to customers; with filings either made, or expected to be made, at Pepco, DPL and ACE, and approved filings at ComEd and BGE. The amounts being passed back or proposed to be passed back to customers reflect the benefit of lower income tax expense beginning January 1, 2018 (Feb. 1, 2018 for DPL Delaware), and the settlement of a portion of deferred income tax regulatory liabilities established upon enactment of the TCJA. To date, neither the PAPUC nor FERC has yet issued guidance on how and when to reflect the impacts of the TCJA in customer rates. Refer to Note 3 - Regulatory Matters of the Combined Notes to the Consolidated Financial Statements for additional information on their filings.

In general, most states use federal taxable income as the starting point for computing state corporate income tax. Now that the TCJA has been enacted, state governments are beginning to analyze the impact of the TCJA on their state revenues. Exelon is uncertain regarding what the state governments will do, and there is a possibility that state corporate income taxes could change due to the enactment of the TCJA. In 2018, Exelon will be closely monitoring the states’ responses to the TCJA as these could have an impact on Exelon’s future cash flows.

See Note 14 - Income Taxes of the Combined Notes to Consolidated Financial Information for further information on the amounts of the net regulatory liabilities subject to determinations by rate regulators.

Exelon appealed the Tax Court’s like-kind exchange decision in the third quarter of 2017. In the fourth quarter of 2017, the IRS assessed the tax, penalties and interest of approximately $1.3 billion related to the like-kind exchange, including $300 million attributable to ComEd. While Exelon will receive a tax benefit of approximately $350 million associated with the deduction for the interest, Exelon currently has a net operating loss carryforward and thus does not expect to realize the cash benefit until 2018. After taking into account these interest deduction tax benefits, the total estimated net cash outflow for the like-kind exchange is approximately $950 million, of which approximately $300 million is attributable to ComEd after giving consideration to Exelon’s agreement to hold ComEd harmless from any unfavorable impacts on ComEd’s equity from the like-kind exchange position.

Of the above amounts payable, Exelon deposited with the IRS $1.25 billion in October of 2016. Exelon funded the $1.25 billion deposit with a combination of cash on hand and short-term borrowings. As a result of the IRS’s assessment of the tax, penalties and interest in the fourth quarter of 2017, the deposit is no longer available to Exelon and thus was reclassified from a current asset and is now reflected as an offset to the related liabilities for the tax, penalties, and interest that are included on Exelon’s balance sheet as current liabilities. The remaining amount due of approximately $20 million was paid in the fourth quarter of 2017. In the third quarter of 2017, the $300 million payable discussed above attributable to ComEd, net of ComEd’s receivable pursuant to the hold harmless agreement, was settled with Exelon. See Note 14 - Income Taxes of the Combined Notes to Consolidated Financial Statements for further discussion of the like-kind exchange tax position.

State and local governments continue to face increasing financial challenges, which may increase the risk of additional income tax, property taxes and other taxes or the imposition, extension or permanence of temporary tax increases. On July 6, 2017, Illinois enacted Senate Bill 9, which permanently increased Illinois’ total corporate income tax rate from 7.75% to 9.50% effective July 1, 2017. The rate increase is not expected to have a material ongoing

impact to Exelon’s, Generation’s or ComEd’s future cash taxes. See Note 14 - Income Taxes of the Combined Notes to Consolidated Financial Statements for further discussion of the Illinois tax rate change.

~~Cash flows provided by operations for the year ended December 31, 2017, 2016 and 2015 by Registrant were as follows:~~

2017 2016 2015
Exelon $ 7,480
$ 8,445
$ 7,616
Generation 3,299
4,444
4,199
ComEd 1,527
2,505
1,896
PECO 755
829
770
BGE 821
945
782
Pepco 407
651
373
DPL 321
310
266
ACE 206
385
256

Successor Predecessor
For the Year Ended December 31, 2017 March 24, 2016 to December 31, 2016 January 1, 2016 to March 23, 2016 For the Year Ended December 31, 2015
PHI $ 950
$ 888
$ 264
$ 939


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. ~~In addition, significant~~See above for additional information related to cash flows from Generation. Significant operating cash flow impacts for the Registrants and Generation for ~~2017, 2016~~2022 and ~~2015~~2021 were as follows:

~~Generation~~•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.

~~Depending~~•Changes in collateral depended upon whether Generation iswas in a net mark-to-market liability or asset position, and collateral may behave been required to be posted with or collected from its counterparties. In addition, the collateral posting and collection requirements ~~differ~~differed depending on whether the transactions ~~are~~were on an exchange or in the ~~OTC~~over-the-counter markets. ~~During 2017, 2016 and 2015, Generation had net collections/(payments)~~Changes in collateral for the Utility Registrants are dependent upon the credit exposure of ~~counterparty cash collateral of $(129) million, $923 million and $407 million, respectively, primarily due~~procurement contracts that may require suppliers to ~~market conditions that resulted in changes to Generation’s net mark-to-market position.~~

~~During 2017, 2016 and 2015, Generation had net collections/(payments) of approximately $28 million, $(66) million and $58 million, respectively, related to purchases and sales of options.~~post collateral. The ~~level of option activity in a given year may vary due to several factors, including changes in market conditions as well as changes in hedging strategy.~~

~~ComEd~~

~~During 2017, 2016, and 2015 ComEd (posted)/received approximately $(27 million), $7 million, and $(31 million)~~amount of cash collateral ~~with/~~received from ~~PJM, respectively. ComEd’s collateral posted with PJM has~~external counterparties increased ~~from 2017 to 2016, primarily~~ due to ~~an increase in ComEd’s RPM credit requirements and peak market activity with PJM. The collateral posted with PJM decreased from 2016 to 2015 due to lower PJM billings.~~rising energy prices. See Note 15 — Derivative Financial Instruments for additional information.

~~For further discussion regarding changes in non-cash operating activities, please refer to~~•See Note 2413 — ~~Supplemental Financial Information~~Income Taxes of the Combined Notes to Consolidated Financial ~~Statements.~~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

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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

~~Cash~~The following table provides a summary of the change in cash flows ~~used in~~from investing activities for the ~~year~~years ended December 31, ~~2017, 2016~~2022 and ~~2015~~2021 by ~~Registrant were as follows:~~Registrant:

2017 2016 2015
Exelon $ (7,934 ) $ (15,503 ) $ (7,822 )
Generation ^(a)
(2,592 ) (3,851 ) (4,069 )
ComEd (2,296 ) (2,685 ) (2,362 )
PECO (597 ) (798 ) (588 )
BGE (849 ) (910 ) (675 )
Pepco (630 ) (647 ) (477 )
DPL (429 ) (336 ) (345 )
ACE (310 ) (309 ) (306 )

Successor Predecessor
For the Year Ended December 31, 2017 March 24, 2016 to December 31, 2016 January 1, 2016 to March 23, 2016 For the Year Ended December 31, 2015
PHI $ (1,396 ) $ (1,030 ) $ (343 ) $ (1,161 )


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 ~~2017, 2016~~2022 and ~~2015~~2021 were as follows:

~~Exelon~~

~~During 2017, Exelon had additional~~•Variances in capital expenditures ~~of $23 million and $178 million relating~~ are primarily due to the ~~ConEdison Solutions~~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 ~~acquisitions~~Utility Registrants. See Note 2 — Discontinued Operations of the ~~FitzPatrick nuclear generating station, respectively. During 2016, Exelon had expenditures of $6.6 billion, $235 million, and $58 million relating~~Combined Notes to ~~the acquisitions of PHI, ConEdison Solutions and the acquisitions of the FitzPatrick nuclear generating station, respectively.~~

~~During 2017, Exelon had proceeds of $219 million from sales of long-lived assets.~~

~~During 2016, Exelon had proceeds of $360 million as a result of early termination of direct financing leases.~~

~~Generation~~

During 2017, Generation had additional expenditures of $23 million and $178 million relating to the ConEdison Solutions and the acquisitions of the FitzPatrick nuclear generating station, respectively. During 2016, Generation had expenditures of $235 million, and $58 million relating to the acquisitions of ConEdison Solutions and the acquisitions of the FitzPatrick nuclear generating station, respectively.

~~During 2017, Generation had proceeds of $218 million from sales of long-lived assets.~~

~~Capital Expenditure Spending~~

~~Generation~~

Generation has entered into several agreements to acquire equity interests in privately held development stage entities which develop energy-related technology. The agreements contain a series of scheduled investment commitments, including in-kind services contributions. There are anticipated expenditures to fund anticipated planned capital and operating needs of the associated companies.

~~Capital expenditures by Registrant~~Consolidated Financial Statements for ~~the year ended December 31, 2017, 2016 and 2015 and projected amounts for 2018 are as follows:~~

Projected
2018 ^(a)
2017 2016 2015
Exelon^(b)
$ 7,825
$ 7,584
$ 8,553
$ 7,624
Generation 2,100
2,259
3,078
3,841
ComEd^(c)
2,125
2,250
2,734
2,398
PECO 800
732
686
601
BGE
1,000
882
934
719
Pepco 725
628
586
544
DPL 400
428
349
352
ACE 375
312
311
300

Successor Predecessor

Projected 2018 ^(a)
For the Year Ended December 31, 2017 March 24, 2016 to December 31, 2016 January 1, 2016 to March 23, 2016 For the Year Ended December 31, 2015
PHI^(d)
$ 1,500
$ 1,396
$ 1,008
$ 273
$ 1,230

~~__________~~


~~(a)~~	~~Total projected capital expenditures do not include adjustments for non-cash activity.~~


~~(b)~~	~~Includes corporate operations, BSC and PHISCO rounded to the nearest $25 million.~~


~~(c)~~	The capital expenditures and 2018 projections include $86 million of expected incremental spending pursuant to EIMA, ComEd has committed to invest approximately $2.6 billion over a ten-year period to modernize and storm-harden its distribution system and to implement smart grid technology.


~~(d)~~	~~Includes PHISCO rounded to the nearest $25 million.~~

~~Projected capital expenditures and other investments are subject to periodic review and revision to reflect changes in economic conditions and other factors.~~

~~Generation~~

Approximately 40% and 10% of the projected 2018 capital expenditures at Generation are for the acquisition of nuclear fuel, and the construction of new natural gas plants and solar facilities, respectively, with the remaining amounts reflecting investment in renewable energy and additions and upgrades to existing facilities (including material condition improvements during nuclear refueling outages). Generation anticipates that they will fund capital expenditures with internally generated funds and borrowings.

~~ComEd, PECO, BGE, Pepco, DPL and ACE~~

Projected 2018 capital expenditures at the Utility Registrants are for continuing projects to maintain and improve operations, including enhancing reliability and adding capacity to the transmission and distribution systems such as ComEd’s reliability related investments required under EIMA, and the Utility Registrants' construction commitments under PJM’s RTEP.

The Utility Registrants as transmission owners are subject to NERC compliance requirements. NERC provides guidance to transmission owners regarding assessments of transmission lines. The results of these assessments could require the Utility Registrants to incur incremental capital or operating and maintenance expenditures to ensure their transmission lines meet NERC standards. In 2010, NERC provided guidance to transmission owners that recommended the Utility Registrants perform assessments of their transmission lines. ComEd, PECO and BGE submitted their final bi-annual reports to NERC in January 2014. ComEd, PECO and BGE will be incurring incremental capital expenditures associated with this guidance following the completion of the assessments. Specific projects and

expenditures are identified as the assessments are completed. ComEd’s, PECO’s and BGE’s forecasted 2018 capital expenditures above reflect capital spending for remediation to be completed through 2019. Pepco, DPL and ACE have substantially completed their assessments and thus do not expect significant capital expenditures related to ~~this guidance~~Generation prior to the separation.

•Collection of DPP relates to Generation's revolving accounts receivable financing agreement which Generation entered into in ~~2018.~~April 2020. Generation received $400 million of additional funding related to the DPP in February and March of 2021.

~~The Utility Registrants anticipate that they will fund their capital expenditures with~~•Proceeds from sales of assets and businesses decreased primarily due to the sale of a ~~combination~~significant portion of ~~internally generated funds~~Generation's solar business and ~~borrowings and additional capital contributions from parent.~~a biomass facility in 2021.

Cash Flows from Financing Activities

~~Cash~~The following table provides a summary of the change in cash flows ~~provided by (used in)~~from financing activities for the ~~year~~years ended December 31, ~~2017, 2016~~2022 and ~~2015~~2021 by ~~Registrant~~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)

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Significant financing cash flow impacts for the Registrants for 2022 and 2021 were as follows:

2017 2016 2015
Exelon $ 717
$ 1,191
$ 4,830
Generation (581 ) (734 ) (479 )
ComEd 789
169
467
PECO 50
(263 ) 83
BGE 22
(21 ) (162 )
Pepco 219
—
103
DPL 64
67
80
ACE 5
22
51

Successor Predecessor
For the Year Ended December 31, 2017 March 24, 2016 to December 31, 2016 January 1, 2016 to March 23, 2016 For the Year Ended December 31, 2015
PHI $ 306
$ (7 ) $ 372
$ 233

~~Debt~~

~~See~~•Changes in short-term borrowings, net, are driven by repayments on and issuances of notes due in less than 365 days. Refer to Note 1316 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for ~~further details~~additional information on short-term borrowings for the Registrants. These changes also included repayments of $552 million in commercial paper and term loans by Generation prior to the separation.

•Long-term debt, net, varies due to debt issuances and redemptions each year. Refer to the debt issuances and redemptions tables below for additional information for the Registrants.

•Changes inintercompany money pool are driven by short-term borrowing needs. Refer below for more information regarding the intercompany money pool.

•Issuance of common stock relates to the August 2022 underwritten public offering of Exelon common stock. See Note 19 — Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for additional information.

•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.

Table of Contents

Debt Issuances and Redemptions

See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of the Registrants’ ~~debt issuances and retirements.~~long-term debt. Debt activity for ~~2017, 2016~~2022 and ~~2015~~2021 by Registrant was as follows:

During ~~the year ended December 31, 2017,~~2022, the following long-term debt was issued:

Company Type Interest Rate Maturity Amount Use of Proceeds
Exelon Corporate Junior Subordinated Notes 3.50 % June 1, 2022 $ 1,150
Refinance Exelon's Junior Subordinated Notes issued in June 2014.
Generation
Albany Green Energy Project Financing ^(a)
LIBOR + 1.25%
November 17, 2017 $ 14
Albany Green Energy biomass generation development.
Generation
Energy Efficiency Project Financing ^(a)
3.90 % February 1, 2018 $ 19
Funding to install energy conservation measures for the Naval Station Great Lakes project.
Generation
Energy Efficiency Project Financing ^(a)
3.72 % May 1, 2018 $ 5
Funding to install energy conservation measures for the Smithsonian Zoo project.

Company

Type

Interest Rate

Maturity

Amount

Use of Proceeds

Company

Type

Interest Rate

Maturity

Amount

Use of Proceeds

Generation

Energy Efficiency Project Financing ^(a)

2.61

September 30, 2018

Funding to install energy conservation measures for the Pensacola project.

Generation

Energy Efficiency Project Financing ^(a)

3.53

April 1, 2019

Funding to install energy conservation measures for the State Department project.

Generation

Senior Notes

2.95

January 15, 2020

250

Repay outstanding commercial paper obligations and for general corporate purposes.

Generation

Senior Notes

3.40

March 15, 2022

500

Repay outstanding commercial paper obligations and for general corporate purposes.

Generation

ExGen Texas Power Nonrecourse Debt ^(b)(c)

LIBOR + 4.75%

September 18, 2021

General corporate purposes.

Generation

ExGen Renewables IV, Nonrecourse Debt ^(b)

LIBOR + 3.00%

November 30, 2024

850

General corporate purposes.

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

Procurement of software licenses

Exelon

Long-Term Software License Agreements

3.70%

August 9, 2025

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 122

2.95

August 15, 2027

350

Refinance maturing mortgage bonds, repay a portion of ComEd’s outstanding commercial paper obligations and for general corporate purposes.

ComEd

First Mortgage Bonds, Series 133

3.85%

March 15, 2052

450

Repay outstanding commercial paper obligations and to fund other general corporate purposes.

ComEd

First Mortgage Bonds, Series 123

3.75

August 15, 2047

650

Refinance maturing mortgage bonds, repay a portion of ComEd’s outstanding commercial paper obligations and for general corporate purposes.

PECO

First and Refunding Mortgage Bonds

4.60%

May 15, 2052

350

Refinance existing indebtedness and for general corporate purposes.

PECO

First and Refunding Mortgage Bonds

3.70

September 15, 2047

325

General corporate purposes.

PECO

First and Refunding Mortgage Bonds

4.375%

August 15, 2052

425

Refinance outstanding commercial paper and for general corporate purposes.

BGE

Senior Notes

3.75

August 15, 2047

300

Redeem $250 million in principal amount of the 6.20% Deferrable Interest Subordinated Debentures due October 15, 2043 issued by BGE's affiliate BGE Capital Trust II, repay commercial paper obligations and for general corporate purposes.

BGE

Notes

4.55%

June 1, 2052

500

Repay outstanding commercial paper obligations, repay existing indebtedness, and for general corporate purposes.

Pepco

Energy Efficiency Project Financing^(a)

3.30

December 15, 2017

Funding to install energy conservation measures for the DOE Germantown project.

Pepco

First Mortgage Bonds

3.97%

March 24, 2052

400

Repay existing indebtedness and for general corporate purposes.

Pepco

First Mortgage Bonds

4.15

March 15, 2043

200

Funding to repay outstanding commercial paper 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

Repay existing indebtedness and for general corporate purposes.

ACE

First Mortgage Bonds

3.06%

February 15, 2052

150

Repay existing indebtedness and for general corporate purposes.

__________


~~(a)~~	~~For Energy Efficiency Project Financing, the maturity dates represent the expected date of project completion, upon which the respective customer assumes the outstanding debt.~~


~~(b)~~	~~See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for discussion of nonrecourse debt.~~


~~(c)~~	As a result of the bankruptcy filing for EGTP on November 7, 2017, the nonrecourse debt was deconsolidated from Exelon's and Generation's consolidated financial statements. Refer to Note 4 — Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for further discussion.

(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 ~~ended December 31, 2016,~~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,

Table of Contents

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~~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

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

Repay existing indebtedness and for general corporate purposes.

Company Type Interest Rate Maturity Amount Use of Proceeds
Exelon Corporate Senior Unsecured Notes 2.45 % April 15, 2021 $ 300
Repay commercial paper issued by PHI and for general corporate purposes.
Exelon Corporate Senior Unsecured Notes 3.40 % April 15, 2026 $ 750
Repay commercial paper issued by PHI and for general corporate purposes.
Exelon Corporate Senior Unsecured Notes 4.45 % April 15, 2046 $ 750
Repay commercial paper issued by PHI and for general corporate purposes.
Generation
Renewable Power Generation Nonrecourse Debt^(a)
4.11 % March 31, 2035 $ 150
Paydown long-term debt obligations at Sacramento PV Energy and Constellation Solar Horizons and for general corporate purposes.
Generation
Albany Green Energy Project Financing^(b)
LIBOR + 1.25%
November 17, 2017 $ 98
Albany Green Energy biomass generation development
Generation
Energy Efficiency Project Financing ^(b)
3.17 % December 31, 2017 $ 16
Funding to install energy conservation measures in Brooklyn, NY.
Generation
Energy Efficiency Project Financing ^(b)
3.90 % January 31, 2018 $ 19
Funding to install energy conservation measures for the Naval Station Great Lakes project.
Generation
Energy Efficiency Project Financing ^(b)
3.52 % April 30, 2018 $ 14
Funding to install energy conservation measures for the Smithsonian Zoo project.
Generation
SolGen Nonrecourse Debt ^(a)
3.93 % September 30, 2036 $ 150
General corporate purposes.
Generation
Energy Efficiency Project Financing^(b)
3.46 % October 1, 2018 $ 36
Funding to install energy conservation measures or the Marine Corps Logistics Base project.
Generation
Energy Efficiency Project Financing ^(b)
2.61 % September 30, 2018 $ 4
Funding to install energy conservation measures for the Pensacola project
ComEd First Mortgage Bonds, Series 120 2.55 % June 15, 2026 $ 500
Refinance maturing mortgage bonds, repay a portion of ComEd's outstanding commercial paper obligations and for general corporate purposes.
ComEd First Mortgage Bonds, Series 121 3.65 % June 15, 2046 $ 700
Refinance maturing mortgage bonds, repay a portion of ComEd's outstanding commercial paper obligations and for general corporate purposes.
PECO First Mortgage Bonds 1.70 % September 15, 2021 $ 300
Refinance maturing mortgage bonds.
BGE Notes 2.40 % August 15, 2026 $ 350
Redeem the $190M of outstanding preference shares and for general corporate purposes.

BGE Notes 3.50 % August 15, 2046 $ 500
Redeem the $190M of outstanding preference shares and for general corporate purposes.
Pepco
Energy Efficiency Project Financing^(b)
3.30 % December 15, 2017 $ 4
Funding to install energy conservation measures for the DOE Germantown project.
DPL First Mortgage Bonds 4.15 % May 15, 2045 $ 175
Refinance maturing mortgage bonds, repay commercial paper and for general corporate purposes.

~~__________~~


~~(a)~~	~~See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for discussion of nonrecourse debt.~~


~~(b)~~	~~For Energy Efficiency Project Financing, the maturity dates represent the expected date of project completion, upon which the respective customer assumes the outstanding debt.~~

~~During the year ended December 31, 2015, the following long term-debt was issued:~~

Company Type Interest Rate Maturity Amount Use of Proceeds
Exelon Corporate Senior Unsecured Notes 1.55 % June 9, 2017 $ 550
Finance a portion of the pending merger with PHI and related costs and expenses and for general corporate purposes.
Exelon Corporate Senior Unsecured Notes 2.85 % June 15, 2020 $ 900
Finance a portion of the pending merger with PHI and related costs and expenses and for general corporate purposes.
Exelon Corporate Senior Unsecured Notes 3.95 % June 15, 2025 $ 1,250
Finance a portion of the pending merger with PHI and related costs and expenses and for general corporate purposes.
Exelon Corporate Senior Unsecured Notes 4.95 % June 15, 2035 $ 500
Finance a portion of the pending merger with PHI and related costs and expenses and for general corporate purposes.
Exelon Corporate Senior Unsecured Notes 5.10 % June 15, 2045 $ 1,000
Finance a portion of the pending merger with PHI and related costs and expenses and for general corporate purposes.
Exelon Corporate Long-Term Software License Agreement 3.95 % May 1, 2024 $ 111
Procurement of software licenses.
Generation Senior Unsecured Notes 2.95 % January 15, 2020 $ 750
Fund the optional redemption of Exelon's $550 million, 4.550% Senior Notes and for general corporate purposes.
Generation
AVSR DOE Nonrecourse Debt^(a)
2.29 - 2.96%
January 5, 2037 $ 39
Antelope Valley solar development.
Generation
Energy Efficiency Project Financing^(b)
3.71 % July 31, 2017 $ 42
Funding to install energy conservation measures in Coleman, Florida.

Generation
Energy Efficiency Project Financing^(b)
3.55 % November 15, 2016 $ 19
Funding to install energy conservation measures in Frederick, Maryland.
Generation Tax Exempt Pollution Control Revenue Bonds 2.50 - 2.70%
2019 - 2020 $ 435
General corporate purposes.
Generation
Albany Green Energy Project Financing^(b)
LIBOR + 1.25%
November 17, 2017 $ 100
Albany Green Energy biomass generation development.
Generation Nuclear Fuel
Purchase Contract 3.15 % September 30, 2020 $ 57
Procurement of uranium.
ComEd First Mortgage Bonds, Series 118 3.70 % March 1, 2045 $ 400
Refinance maturing mortgage bonds, repay a portion of ComEd's outstanding commercial paper obligations and for general corporate purposes.
ComEd First Mortgage Bonds, Series 119 4.35 % November 15, 2045 $ 450
Repay a portion of ComEd's outstanding commercial paper obligations and for general corporate purposes.
PECO First and Refunding Mortgage Bonds 3.15 % October 15, 2025 $ 350
General corporate purposes
Pepco First Mortgage Bonds 4.15 % March 15, 2043 $ 200
Repay outstanding commercial paper obligations and general corporate purposes
DPL First Mortgage Bonds 4.15 % May 15, 2045 $ 200
Repay outstanding commercial paper obligations and general corporate purposes
ACE First Mortgage Bonds 3.50 % December 1, 2025 $ 150
Repay outstanding commercial paper obligations and general corporate purposes

~~__________~~


~~(a)~~	~~See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for discussion of nonrecourse debt.~~


~~(b)~~	~~For Energy Efficiency Project Financing, the maturity dates represent the expected date of project completion, upon which the respective customer assumes the outstanding debt.~~

During ~~the year ended December 31, 2017,~~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

Exelon

Long-Term Software License Agreement

2.30%

December 1, 2025

Exelon

Long-Term Software License Agreement

3.70%

August 9, 2025

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

Table of Contents

Company Type Interest Rate Maturity Amount
Exelon Corporate Long-Term Software License Agreement 3.95% May 1, 2024 $ 24
Exelon Corporate Senior Notes 1.55% June 9, 2017 $ 550
Generation Senior Notes - Exelon Wind 2.00% July 31, 2017 $ 1
Generation
CEU Upstream
Nonrecourse Debt ^(a)
LIBOR + 2.25% January 14, 2019 $ 6
Generation
SolGen Nonrecourse Debt ^(a)
3.93% September 30, 2036 $ 2
Generation
AVSR DOE Nonrecourse Debt ^(a)
2.29% - 3.56% January 5, 2037 $ 22
Generation Kennett Square Capital Lease 7.83% September 20, 2020 $ 2
Generation
Continental Wind Nonrecourse Debt ^(a)
6.00% February 28, 2033 $ 31
Generation PES - PGOV Notes Payable 6.70-7.60% 2017 - 2018 $ 1
Generation
ExGen Texas Power
Nonrecourse Debt ^(a)(b)
LIBOR + 4.75% September 18, 2021 $ 665
Generation
Renewable Power Generation Nonrecourse Debt ^(a)
4.11% March 31, 2035 $ 14
Generation NUKEM 3.25% - 3.35% June 30, 2018 $ 23
Generation ExGen Renewables I, Nonrecourse Debt LIBOR + 4.25% February 6, 2021 $ 233
Generation Senior Notes 6.20% October 1, 2017 $ 700
Generation Albany Green Energy Project Financing LIBOR + 1.25% November 17, 2017 $ 212
ComEd First Mortgage Bonds 6.15% September 15, 2017 $ 425
BGE Rate Stabilization Bonds 5.82% April 1, 2017 $ 41
BGE Capital Trust Preferred Securities 6.20% October 15, 2043 $ 258
PHI Senior Notes 6.13% June 1, 2017 $ 81
DPL Medium Term Notes, Unsecured 7.56% - 7.58% February 1, 2017 $ 14
DPL Variable Rate Demand Bonds Variable October 1, 2017 $ 26
Pepco Third Party Financing 6.97% - 7.99% 2018 - 2022 $ 1
ACE Transition Bonds 5.05% - 5.55% 2020 - 2023 $ 35

~~__________~~


~~(a)~~	~~See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for discussion of nonrecourse~~— Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the mirror debt.


~~(b)~~	As a result of the bankruptcy filing for EGTP on November 7, 2017, the nonrecourse debt was deconsolidated from Exelon's and Generation's consolidated financial statements. Refer to Note 4 — Mergers, Acquisitions and Dispositions for further discussion.

During ~~the year ended December 31, 2016,~~2021, the following long-term debt was retired and/or redeemed:

Company Type Interest Rate Maturity Amount
Exelon Corporate Long Term Software License Agreement 3.95% May 1, 2024 $ 8
Exelon Corporate Senior Notes 4.95% June 15, 2035 $ 1
Generation
AVSR DOE Nonrecourse Debt ^(a)
2.29% - 3.56% January 5, 2037 $ 22
Generation Kennett Square Capital Lease 7.83% September 20, 2020 $ 4
Generation
Continental Wind Nonrecourse Debt ^(a)
6.00% February 28, 2033 $ 29
Generation
CEU Upstream Nonrecourse Debt ^(a)
LIBOR + 2.25% January 14, 2019 $ 46
Generation
ExGen Texas Power
Nonrecourse Debt ^(a)(b)
5.00% September 18, 2021 $ 7
Generation Sacramento Solar Nonrecourse Debt LIBOR + 2.25% December 31, 2030 $ 33
Generation
Clean Horizons Nonrecourse Debt
LIBOR + 2.25% September 7, 2030 $ 32
Generation ExGen Renewables I, Nonrecourse Debt LIBOR + 4.25% February 6, 2021 $ 24
Generation PES - PGOV Notes Payable 6.70% - 7.46% 2017-2018 $ 1
Generation NUKEM 3.35% June 30, 2018 $ 12
Generation NUKEM 3.25% July 1, 2018 $ 10
Generation
Renewable Power Generation Nonrecourse Debt ^(a)
4.11% March 31, 2035 $ 9
Generation
SolGen Nonrecourse Debt ^(a)
3.93% September 30, 2036 $ 2
ComEd �� First Mortgage Bonds, Series 104 5.95% August 15, 2016 $ 415
ComEd First Mortgage Bonds, Series 111 1.95% August 1, 2016 $ 250
PECO First and Refunding Mortgage Bonds 1.20% October 15, 2016 $ 300
BGE Rate Stabilization Bonds 5.72% April 1, 2016 $ 1
BGE Rate Stabilization Bonds 5.82% April 1, 2017 $ 38
BGE Notes 5.90% October 1, 2016 $ 300
BGE Rate Stabilization Bonds 5.82% April 1, 2017 $ 40
PHI Senior Unsecured Notes 5.90% December 12, 2016 $ 190
DPL First Mortgage Bonds 5.22% December 30, 2016 $ 100
ACE Transition Bonds 5.05% October 20, 2020 $ 12
ACE Transition Bonds 5.55% October 20, 2023 $ 34
ACE First Mortgage Bonds 7.68% August 23, 2016 $ 2

~~__________~~


~~(a)~~	~~See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for discussion of nonrecourse debt.~~


~~(b)~~	As a result of the bankruptcy filing for EGTP on November 7, 2017, the nonrecourse debt was deconsolidated from Exelon's and Generation's consolidated financial statements. Refer to Note 4 — Mergers, Acquisitions and Dispositions for further discussion.

~~During the year ended December 31, 2015, the following long-term debt was retired and/or redeemed:~~

Company Type Interest Rate Maturity Amount
Exelon Corporate Senior Unsecured Notes 4.55% June 15, 2015 $ 550
Exelon Corporate Senior Notes 4.90% June 15, 2015 $ 800
Exelon Corporate Senior Unsecured Notes 3.95% June 15, 2025 $ 443
Exelon Corporate Senior Unsecured Notes 4.95% June 15, 2035 $ 167
Exelon Corporate Senior Unsecured Notes 5.10% June 15, 2045 $ 259
Exelon Corporate Long-Term Software License Agreement 3.95% May 1, 2024 $ 1
Generation Senior Unsecured Notes 4.55% June 15, 2015 $ 550
Generation
CEU Upstream Nonrecourse Debt ^(a)
LIBOR + 2.25% January 14, 2019 $ 9
Generation
AVSR DOE Nonrecourse Debt ^(a)
2.29%-3.56% January 5, 2037 $ 23
Generation Kennett Square Capital Lease 7.83% September 20, 2020 $ 3
Generation Continental Wind Nonrecourse Debt 6.00% February 28, 2033 $ 20
Generation
ExGen Texas Power Nonrecourse Debt ^(a)(b)
LIBOR + 4.75% September 8, 2021 $ 5
Generation ExGen Renewables I Nonrecourse Debt LIBOR + 4.25% February 6, 2021 $ 24
Generation Constellation Solar Horizons Nonrecourse Debt 2.56% September 7, 2030 $ 2
Generation Sacramento PV Energy Nonrecourse Debt 2.58% December 31, 2030 $ 2
Generation
Energy Efficiency Project ^(b)
3.55% November 15, 2016 $ 19
ComEd First Mortgage Bonds, Series 101 4.70% April 15, 2015 $ 260
BGE Rate Stabilization Bonds 5.72% April 1, 2016 $ 75
PHI Senior Unsecured Notes 2.70% October 1, 2015 $ 250
PHI ^(c)
Energy Efficiency Project Financing 4.68% February 10, 2015 $ 7
PHI ^(c)
Energy Efficiency Project Financing 8.87% June 1, 2021 $ 5
PHI ^(c)
Energy Efficiency Project Financing 7.61% August 1, 2015 $ 1
PHI ^(c)
PES - PGOV Notes Payable 6.70% 2017-2018 $ 1
Pepco Energy Efficiency Project Financing 3.12% February 20, 2015 $ 12
DPL Senior Unsecured Notes 5.00% June 1, 2015 $ 100
ACE Secured Medium-Term Notes Series C 7.68% August 24, 2015 $ 15
ACE Transition Bonds 5.05% October 20, 2020 $ 12
ACE Transition Bonds 5.55% October 20, 2023 $ 32

~~__________~~


~~(a)~~	~~See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for discussion of nonrecourse debt.~~


~~(b)~~	As a result of the bankruptcy filing for EGTP on November 7, 2017, the nonrecourse debt was deconsolidated from Exelon's and Generation's consolidated financial statements. Refer to Note 4 — Mergers, Acquisitions and Dispositions for further discussion.


~~(c)~~	~~Represents Pepco Energy Services energy efficiency project financing. As of the date of the merger, PES financing was included with Generation.~~

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

Exelon

Long-Term Software License Agreements

3.62%

December 1, 2025

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

ACE

Transition Bonds

5.55%

October 20, 2021

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

~~Cash dividend payments and distributions for the year ended December 31, 2017, 2016 and 2015 by Registrant were as follows:~~

2017 2016 2015
Exelon $ 1,236
$ 1,166
$ 1,105
Generation 659
922
2,474
ComEd 422
369
299
PECO 288
277
279
BGE^(a)
198
187
171
Pepco 133
136
146
DPL 112
54
92
ACE 68
63
12

Successor Predecessor
For the Year Ended December 31, 2017 March 24, 2016 to December 31, 2016 January 1, 2016 to March 23, 2016 For the Year Ended December 31, 2015
PHI $ 311
$ 273
$ —
$ 275

~~__________~~


~~(a)~~	~~Includes dividends paid on BGE's preference stock during 2016 and 2015.~~

Quarterly dividends declared by the Exelon Board of Directors during the year ended December 31, ~~2017~~2022 and for the first quarter of ~~2018~~2023 were as follows:

Period Declaration Date Shareholder of Record Date Dividend Payable Date Cash per Share
First Quarter 2017 January 31, 2017 February 15, 2017 March 10, 2017 $ 0.3275
Second Quarter 2017 April 25, 2017 May 15, 2017 June 9, 2017 $ 0.3275
Third Quarter 2017 July 25, 2017 August 15, 2017 September 8, 2017 $ 0.3275
Fourth Quarter 2017 September 25, 2017 November 15, 2017 December 8, 2017 $ 0.3275
First Quarter 2018^(a)
January 30, 2018 February 15, 2018 March 9, 2018 $ 0.3450

~~___________~~

~~(a)~~Period

~~Exelon's Board~~

Declaration Date

Shareholder of ~~Directors approved an updated dividend policy providing an increase of 5% each year for the period covering 2018 through 2020, beginning with the~~
Record Date

Dividend Payable Date

Cash per Share(a)

First Quarter 2022

February 8, 2022

February 25, 2022

March ~~2018 dividend.~~10, 2022

~~Short-Term Borrowings~~

~~Short-term borrowings incurred (repaid) during 2017, 2016 and 2015 by Registrant were as follows:~~

2017
2016
2015
Exelon $ (261 ) $ (353 ) $ 80
Generation (620 ) 620
—
ComEd —
(294 ) (10 )
BGE 32
(165 ) 90
Pepco 3
(41 ) (40 )
DPL 216
(105 ) (1 )
ACE 108
(5 ) (122 )

Successor Predecessor
For the Year Ended December 31, 2017 March 24, 2016 to December 31, 2016 January 1, 2016 to March 23, 2016 For the Year Ended December 31, 2015
PHI $ 328
$ (515 ) $ (121 ) $ 34

~~Retirement of Long-Term Debt to Financing Affiliates~~

~~On August 28, 2017, BGE redeemed all of the outstanding shares of BGE Capital Trust II 6.20% Preferred Securities. See Note 13 — Debt and Credit Agreements for further discussion.~~

~~Contributions from Parent/Member~~

~~Contributions from Parent/Member (Exelon) during 2017, 2016 and 2015 by Registrant were as follows:~~

2017 2016 2015
Generation $ 102
$ 142
$ 47
ComEd^(a)(b)
672
473
209
PECO^(b)
16
18
16
BGE^(b)
184
61
7
Pepco^(c)
161
187
112
DPL^(c)
—
152
75
ACE^(c)
—
139
95

Successor Predecessor
For the Year Ended December 31, 2017 March 24, 2016 to December 31, 2016 January 1, 2016 to March 23, 2016 For the Year Ended December 31, 2015
PHI^(b)
$ 758
$ 1,251
$ —
$ —

~~__________~~

			$	0.3375
~~(a)~~Second Quarter 2022			Additional contributions from parent or external debt financing may be required as a result of increased capital investment in infrastructure improvements and modernization pursuant to EIMA, transmission upgrades and expansions and Exelon's agreement to indemnify ComEd for any unfavorable after-tax impacts associated with ComEd's LKE tax matter.

April 26, 2022

May 13, 2022

June 10, 2022

0.3375

~~(b)~~Third Quarter 2022

~~Contribution paid by Exelon.~~

July 26, 2022

August 15, 2022

September 9, 2022

0.3375

~~(c)~~Fourth Quarter 2022

~~Contribution paid by PHI.~~

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

~~Pursuant to the orders approving the merger, Exelon made equity contributions~~___________

(a)Exelon's Board of ~~$73 million, $46 million and $49 million to Pepco, DPL and ACE, respectively, in the second quarter of 2016 to fund the after-tax amount of the customer bill credit and the customer base rate credit.~~

~~Redemptions of Preference Stock.~~ ~~BGE had $190 million of cumulative preference stock that was redeemable at its option at any time after October 1, 2015~~Directors approved an updated dividend policy for ~~the redemption price of $100~~2023. The 2023 quarterly dividend will be $0.36 per share, plus accrued and unpaid dividends. On July 3, 2016, BGE redeemed all 400,000 shares of its outstanding 7.125% Cumulative Preference Stock, 1993 Series and all 600,000 shares of its outstanding 6.990% Cumulative Preference Stock, 1995 Series for $100 million, plus accrued and unpaid dividends. On September 18, 2016, BGE redeemed the remaining 500,000 shares of its outstanding 6.970% Cumulative Preference Stock, 1993 Series and the remaining 400,000 shares of its outstanding 6.700% Cumulative Preference Stock, 1993 Series for $90 million, plus accrued and unpaid dividends. As of December 31, 2017, BGE no longer has any preferred stock outstanding. See Note 21 - Earnings Per Share~~of the Combined Notes to Consolidated Financial Statements for further details.~~

~~Other~~

For the year ended December 31, 2017, other financing activities primarily consists of debt issuance costs. See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements’ for additional information.share.

Credit Matters

~~Market Conditions~~ and Cash Requirements

The Registrants fund liquidity needs for capital ~~investment,~~expenditures, working capital, energy hedging, and other financial commitments through cash flows from continuing operations, public debt offerings, commercial paper markets, and large, diversified credit facilities. The credit facilities include ~~$9.5~~$4.0 billion in aggregate total commitments of which ~~$8.3~~$2.1 billion was available to support additional commercial paper as of December 31, ~~2017,~~2022, and of which no financial institution has more than 7%6% of the aggregate commitments for the Registrants. On February 1, 2022, Exelon ~~Generation, ComEd, PECO, BGE, Pepco, DPL~~Corporate and ~~ACE.~~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 ~~market~~markets and had availability under their revolving credit facilities during ~~2017~~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 ~~have continued to~~ closely monitor events in the financial markets and the financial institutions associated with the credit facilities, including monitoring credit ratings and outlooks, credit default swap levels, capital raising, and merger activity. See PART I.I, ITEM 1A. RISK FACTORS for ~~further~~additional information regarding the effects of uncertainty in the capital and credit markets.

The Registrants believe their cash flow from operating activities, access to credit markets, and their credit facilities provide sufficient ~~liquidity. If Generation lost~~liquidity to support the estimated future cash requirements discussed below.

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On August 4, 2022, Exelon entered into an agreement with certain underwriters in connection with an underwritten public offering of 12.995 million shares of its ~~investment grade~~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 ~~rating as~~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, ~~2017, it would have been required~~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 ~~provide incremental collateral~~the Separation Agreement between Exelon and Constellation Energy Corporation, Exelon made a cash payment of ~~$1.8~~$1.75 billion to ~~meet collateral obligations for derivatives, non-derivatives, normal purchases and normal sales contracts and applicable payables and receivables, net~~Generation on January 31, 2022. See Note 2 — Discontinued Operations of the ~~contractual right of offset under master netting agreements, which is well within its current available credit facility capacities of $4.7 billion.~~

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, ~~2017~~2022 and available credit facility capacity prior to any incremental collateral at December 31, ~~2017:~~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

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PJM Credit Policy Collateral
Other Incremental Collateral Required^(a)
Available Credit Facility Capacity Prior to Any Incremental Collateral
ComEd $ 18
$ —
$ 998
PECO 3
34
599
BGE 3
66
600
Pepco 4
—
300
DPL 1
11
300
ACE —
—
300
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	—		—		—

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:

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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.

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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.

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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

__________

(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.

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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

__________

(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

__________

(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.

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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

__________

(b)Represents the future estimated value, as of December 31, 2022, of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between ACE and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.

See Note 18 — Commitments and Contingencies and Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information of the Registrants’ other commitments potentially triggered by future events. Additionally, see below for where to find additional information regarding the financial commitments in the tables above in the Combined Notes to the Consolidated Financial Statements:


Item			Location within Notes to the Consolidated Financial Statements
Long-term debt			Note 16 — Debt and Credit Agreements
Interest payments on long-term debt			Note 16 — Debt and Credit Agreements
Finance leases			Note 10 — Leases
Operating leases			Note 10 — Leases

~~(a)~~REC commitments			~~Represents incremental collateral related to natural gas procurement contracts.~~Note 3 — Regulatory Matters
ZEC commitments			Note 3 — Regulatory Matters
DC PLUG obligation			Note 3 — Regulatory Matters
Pension contributions			Note 14 — Retirement Benefits

~~Exelon~~ Credit Facilities

Exelon Corporate, ComEd, and BGE meet their short-term liquidity requirements primarily through the issuance of commercial paper. ~~Generation and~~ PECO ~~meet their~~meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from ~~the intercompany money pool. PHI meets its short-term liquidity requirements primarily through the issuance of short-term notes and~~ 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 ~~notes.~~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 1316 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for ~~discussion of~~additional information on the Registrants’ credit facilities and short term borrowing activity.

~~Other Credit Matters~~

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Capital Structure~~. At~~

As of December 31, ~~2017,~~2022, the capital structures of the Registrants consisted of the following:


	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE			Exelon(a)		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Long-term debt	51	%	32	%	44	%	44	%	45	%	39	%	50	%	46	%	49	%	Long-term debt	57	%	43	%	44	%	44	%	41	%	48	%	48	%	50	%
Long-term debt to affiliates^(a)	1	%	4	%	1	%	3	%	—	%	—	%	—	%	—	%	—	%
Long-term debt to affiliates(b)																			Long-term debt to affiliates(b)	1	%	1	%	2	%	—	%	—	%	—	%	—	%	—	%
Common equity	47	%	—	%	55	%	53	%	54	%	—		49	%	46	%	46	%	Common equity	38	%	54	%	52	%	52	%	—	%	48	%	49	%	50	%
Member’s equity	—	%	64	%	—	%	—	%	—	%	59	%	—		—		—		Member’s equity	—	%	—	%	—	%	—	%	57	%	—	%	—	%	—	%
Commercial paper and notes payable	1	%	—	%	—		—	%	1	%	2	%	1	%	8	%	5	%	Commercial paper and notes payable	4	%	2	%	2	%	4	%	2	%	4	%	3	%	—	%

__________

~~(a)~~

Includes approximately $389 million, $205 million and $184 million owed to unconsolidated affiliates of Exelon, ComEd, and PECO respectively. These special purpose entities were created for the sole purposes of issuing mandatorily redeemable trust preferred securities of ComEd and PECO. See Note 2 — Variable Interest Entities of the Combined Notes to Consolidated Financial Statements for additional information regarding the authoritative guidance for VIEs.

(a)As of December 31, 2021, Exelon's Long-term debt and Common equity capital structure percentages were 50% and 45%, respectively. The change in capital structure percentages above is a result of a decrease in common equity due to the separation of Constellation in addition to an increase in long-term debt issuances. See Note 2 — Discontinued Operations for additional information regarding the separation.

(b)Includes approximately $390 million, $205 million, and $184 million owed to unconsolidated affiliates of Exelon, ComEd, and PECO respectively. These special purpose entities were created for the sole purposes of issuing mandatory redeemable trust preferred securities of ComEd and PECO.

Security Ratings

The Registrants’ access to the capital markets, including the commercial paper market, and their respective financing costs in those markets, may depend on the securities ratings of the entity that is accessing the capital markets.

The Registrants’ borrowings are not subject to default or prepayment as a result of a downgrading of securities, although such a downgrading of a Registrant’s securities could increase fees and interest charges under that Registrant’s credit agreements.

As part of the normal course of business, the Registrants enter into contracts that contain express provisions or otherwise permit the Registrants and their counterparties to demand adequate assurance of future performance when there are reasonable grounds for doing so. In accordance with the contracts and applicable contracts law, if the Registrants are downgraded by a credit rating agency, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance, which could include the posting of additional collateral. See Note 1215 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on collateral provisions.

The credit ratings for ComEd, PECO, BGE, and DPL did not change for the year ended December 31, 2022. On January 14, 2022, Fitch lowered Exelon Corporate's long-term and senior unsecured ratings from BBB+ to BBB and affirmed the short-term rating of F2. In addition, Fitch upgraded Pepco, ACE, and PHI's long-term rating from BBB to BBB+ and upgraded Pepco and ACE's senior secured rating from A- to A.

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~~Intercompany Money Pool~~Liquidity and Capital Resources

~~To provide~~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 ~~additional short-term borrowing option~~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 ~~will generally be more favorable~~of the utility industry in general. If these conditions deteriorate to the ~~borrowing participants than~~extent that the ~~cost~~Registrants no longer have access to the capital markets at reasonable terms, the Registrants have access to credit facilities with aggregate bank commitments of ~~external financing, both Exelon and PHI operate an intercompany money pool. Maximum amounts contributed to and borrowed from the money pool by participant and the net contribution or borrowing~~$4.0 billion, as of December 31, ~~2017, are presented in~~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 ~~following tables:~~

Exelon Intercompany Money Pool For the Year Ended December 31, 2017 As of
December 31, 2017
Contributed (borrowed)
Maximum
Contributed

Maximum
Borrowed
Contributed (Borrowed)
Exelon Corporate $ 579
$ —
$ 217
Generation 20
(589 ) (54 )
PECO 336
(22 ) —
BSC —
(423 ) (217 )
PHI Corporate —
(47 ) —
PCI 55
—
54

PHI Intercompany Money Pool For the Year Ended December 31, 2017 As of
December 31, 2017
Contributed (borrowed)
Maximum
Contributed

Maximum
Borrowed
Contributed (Borrowed)
PHI Corporate $ 9
$ (2 ) $ 1
Pepco —
—
—
DPL —
—
—
ACE —
—
—
PHISCO 3
(9 ) —

~~Investments in Nuclear Decommissioning Trust Funds.~~ ~~Exelon, Generation~~“Credit Matters and ~~CENG maintain trust funds, as required by the NRC, to fund certain costs of decommissioning nuclear plants.~~Cash Requirements” section below for additional information. The ~~mix of securities in the trust funds is designed to provide returns~~Registrants expect cash flows to be ~~used~~sufficient to ~~fund decommissioning~~meet operating expenses, financing costs, and ~~to offset inflationary increases in decommissioning costs. Generation actively monitors the investment performance of the trust funds and periodically reviews asset allocations in accordance with~~

~~Generation’s NDT fund investment policy. Generation’s and CENG's investment policies establish limits on the concentration of holdings in any one company and also in any one industry.~~capital expenditure requirements. See Note 1516 — ~~Asset Retirement Obligations~~Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for ~~further~~additional information ~~regarding~~on the ~~trust funds,~~Registrants’ debt and credit agreements.

Cash flows related to Generation have not been presented as discontinued operations and are included in the ~~NRC’s minimum funding~~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.

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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 ~~related liquidity ramifications.~~the Registrants' Consolidated Statements of Cash Flows for additional information on income taxes.

~~Shelf Registration Statements.~~ ~~Exelon, Generation,~~•Changes in regulatory assets and liabilities, net, are due to the timing of cash payments for costs recoverable, or cash receipts for costs recovered, under our regulatory mechanisms differs from the recovery period of those costs. Included within the changes is energy efficiency spend for ComEd ~~PECO,~~of $394 million and $343 million for the years ended December 31, 2022 and 2021, respectively. Also included within the changes is energy efficiency and demand response programs spend for BGE, Pepco, DPL, and ACE ~~have~~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 ~~currently effective combined shelf registration statement unlimited in amount, filed with~~regulatory asset for the SEC, that will expire in August 2019. 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 timeyears ended December 31, 2022 and 2021. See Note 3 — Regulatory Matters of the ~~proposed sale, including~~Combined Notes to Consolidated Financial Statements for additional information.

•Changes in working capital and other ~~required regulatory approvals,~~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

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dependent upon whether the participating nuclear-powered generating facilities owe money to ComEd as ~~applicable, the current financial condition~~a result of the ~~Registrant, its securities ratings~~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 ~~market conditions.~~accrued expenses.

~~Regulatory Authorizations.~~ ~~ComEd, PECO, BGE, Pepco, DPL~~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 ~~ACE are required to obtain short-term~~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 ~~long-term financing authority from Federal and State Commissions~~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)

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Short-term Financing Authority^(a)

Long-term Financing Authority^(a)
Commission Expiration Date Amount Commission
Expiration Date ^(c)
Amount
ComEd^(b)
FERC December 31, 2019 $ 2,500
ICC 2019 $ 1,383
PECO FERC December 31, 2019 1,500
PAPUC December 31, 2018 1,275
BGE FERC December 31, 2019 700
MDPSC N/A 700
Pepco FERC December 31, 2019 500
MDPSC September 25, 2017 —
DCPSC December 31, 2020 600
DPL FERC December 31, 2019 500
MDPSC December 31, 2017 —
DPSC December 31, 2020 350
ACE NJBPU December 31, 2019 350
NJBPU December 31, 2019 350
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.


~~(a)~~	~~Generation currently has blanket financing authority it received from FERC in connection with its market-based rate authority.~~


~~(b)~~	ComEd had $1,140 million available in long-term debt refinancing authority and $243 million available in new money long term debt financing authority from the ICC as of December 31, 2017 and has an expiration date of June 1, 2019 and March 1, 2019, respectively.


~~(c)~~	~~Pepco and DPL are currently in the process of renewing their long-term financing authority with the MDPSC.~~

•Long-term debt, net, varies due to debt issuances and redemptions each year. Refer to the debt issuances and redemptions tables below for additional information for the Registrants.

•Changes inintercompany money pool are driven by short-term borrowing needs. Refer below for more information regarding the intercompany money pool.

•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. The Federal Power Act declares it to be unlawful for any officer or director of any public utility “to participate in the making or paying of any dividends of such public utility from any funds properly included in capital account.” In addition, under Illinois law, ComEd may not pay any dividend on its stock, unless, among other things, its earnings and earned surplus are sufficient to declare and pay a dividend after provision is made for reasonable and proper reserves, or unless ComEd has specific authorization from the ICC. BGE is subject to certain dividend restrictions established by the MDPSC. First, BGE was prohibited from paying a dividend on its common shares through the end of 2014. Second, BGE is prohibited 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. Finally, BGE must notify the MDPSC that it intends to declare a dividend on its common shares at least 30 days before such a dividend is paid. Pepco, DPL and ACE are subject to certain dividend restrictions established by settlements approved in NJ, DE, MD and the DC. Pepco, DPL and ACE are prohibited from paying a dividend on their common shares if (a) after the dividend payment, Pepco’s, DPL’s or ACE’s equity ratio would be below 48% as equity levels are calculated under the ratemaking precedents of the Commissions

and the Board or (b) Pepco’s, DPL’s or ACE’s senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. At December 31, 2017, Exelon had retained earnings of $13,503 million, including Generation’s undistributed earnings of $4,310 million, ComEd’s retained earnings of $1,132 million consisting of retained earnings appropriated for future dividends of $2,771 million partially offset by $1,639 million of unappropriated retained deficit, PECO’s retained earnings of $1,087 million and BGE’s retained earnings $1,536 million. At December 31, 2017, Pepco had retained earnings of $1,063 million, DPL had retained earnings of $571 million and ACE had retained earnings of $131 million. See Note 2318 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information ~~regarding fund~~ 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 ~~restrictions.~~of cash, restricted cash, and cash equivalents to Constellation related to the separation.

~~Contractual Obligations and Off-Balance Sheet Arrangements~~

~~The following tables summarize~~•Other financing activities primarily consists of debt issuance costs. See debt issuances table below for additional information on the Registrants’ ~~future estimated cash payments as~~debt issuances.

Table of ~~December 31, 2017 under existing contractual obligations, including payments due by period. See Note 23 — Commitments~~Contents

Debt Issuances and Contingencies of the Combined Notes to Consolidated Financial Statements for information regarding the Registrants’ commercial and other commitments, representing commitments potentially triggered by future events.Redemptions

~~Exelon~~

Payment due within
Total 2018
2019 -
2020
2021 -
2022
Due 2023
and beyond
Long-term debt^(a)
$ 33,994
$ 2,057
$ 4,459
$ 4,574
$ 22,904
Interest payments on long-term debt^(b)
15,999
1,346
2,579
2,231
9,843
Capital leases 53
18
25
2
8
Operating leases^(c)
1,512
188
276
261
787
Purchase power obligations^(d)
1,153
358
498
103
194
Fuel purchase agreements^(e)
7,270
1,229
2,241
1,385
2,415
Electric supply procurement^(e)
3,417
2,213
1,204
—
—
AEC purchase commitments^(e)
3
1
2
—
—
Curtailment services commitments^(e)
119
52
54
13
—
Long-term renewable energy and REC commitments^(f)
1,666
111
224
235
1,096
Other purchase obligations^(g)
7,765
4,844
1,585
561
775
DC PLUG obligation^(h)
188
28
60
60
40
Construction commitments⁽ⁱ⁾
57
56
1
—
—
PJM regional transmission expansion commitments^(j)
569
179
270
120
—
SNF obligation^(k)
1,147
—
—
—
1,147
Pension contributions^(l)
1,393
301
493
386
213
Total contractual obligations $ 76,305
$ 12,981

$ 13,971

$ 9,931

$ 39,422

~~__________~~


~~(a)~~	~~Includes $390 million due after 2023 to ComEd and PECO financing trusts.~~


~~(b)~~	Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2017 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, 2017. Includes estimated interest payments due to ComEd, PECO, BGE, PHI, Pepco, DPL and ACE financing trusts.


~~(c)~~	Excludes Generation's contingent operating lease payments associated with contracted generation agreements. These amounts are included within purchase power obligations. Includes estimated cash payments for service fees related to PECO’s meter reading operating lease.

~~(d)~~

Purchase power obligations include contingent operating lease payments associated with contracted generation agreements. Amounts presented represent Generation’s expected payments under these arrangements at December 31, 2017, including those related to CENG. Expected payments include certain fixed capacity charges which may be reduced based on plant availability. Expected payments exclude renewable PPA contracts that are contingent in nature. Contained within Purchase power obligations are Net Capacity Purchases of $106 million, $99 million, $40 million, $31 million, $19 million and $171 million for 2018, 2019, 2020, 2021, 2022 and thereafter, respectively.


~~(e)~~	Represents commitments to purchase nuclear fuel, natural gas and related transportation, storage capacity and services, procure electric renewable energy and RECs, procure electric supply, and purchase AECs and curtailment services.

~~(f)~~

Primarily related to ComEd 20-year contracts for renewable energy and RECs beginning in June 2012. ComEd is permitted to recover its renewable energy and REC costs from retail customers with no mark-up. The commitments represent the earliest and maximum settlements with suppliers for renewable energy and RECs under the existing contract terms. See Note 3—Regulatory Matters of Combined Notes to Consolidated Financial Statements for additional information.

~~(g)~~

Represents the future estimated value at December 31, 2017 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between the Registrants and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.


~~(h)~~	Related to DC PLUG project costs for assets funded by the District of Columbia for which the District of Columbia has assessed a charge on Pepco. Pepco will recover this charge from customers through a volumetric distribution rider. See Note 3 — Regulatory Matters of Combined Notes to Consolidated Financial Statements for additional information.


~~(i)~~	~~Represents commitments for Generation's ongoing investments in new natural gas and biomass generation construction.~~

~~(j)~~

Under their operating agreements with PJM, ComEd, PECO, BGE, Pepco, DPL and ACE are committed to the construction of transmission facilities to maintain system reliability. These amounts represent ComEd, PECO, BGE, Pepco, DPL and ACE’s expected portion of the costs to pay for the completion of the required construction projects. See Note 3 — Regulatory Matters of Combined Notes to Consolidated Financial Statements for additional information.


~~(k)~~	~~See Note 23 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for further information regarding SNF obligations.~~

~~(l)~~

These amounts represent Exelon’s expected contributions to its qualified pension plans. The projected contributions reflect a funding strategy of contributing the greater of $300 million (which has been updated for the inclusion of PHI) until the qualified plans are fully funded on an accumulated benefit obligation basis, and the minimum amounts under ERISA to avoid benefit restrictions and at-risk status thereafter. The remaining qualified pension plans’ contributions are generally based on the estimated minimum pension contributions required under ERISA and the Pension Protection Act of 2006, as well as contributions necessary to avoid benefit restrictions and at-risk status. These amounts represent estimates that are based on assumptions that are subject to change. Qualified pension contributions for years after 2023 are not included. See Note 16 — ~~Retirement Benefits of the Combined Notes to Consolidated Financial Statements for further information regarding estimated future pension benefit payments.~~

~~Generation~~

Payment due within
Total 2018
2019 -
2020

2021 -
2022
Due 2023
and beyond
Long-term debt $ 8,937
$ 341
$ 2,747
$ 1,023
$ 4,826
Interest payments on long-term debt^(a)
4,808
391
705
530
3,182
Capital leases 18
5
11
2
—
Operating leases^(b)
817
74
76
94
573
Purchase power obligations^(c)
1,153
358
498
103
194
Fuel purchase agreements^(d)
6,147
1,000
1,909
1,184
2,054
Other purchase obligations^(e)
1,456
398
249
181
628
Construction commitments^(f)
57
56
1
—
—
SNF obligation^(g)
1,147
—
—
—
1,147
Total contractual obligations $ 24,540
$ 2,623

$ 6,196

$ 3,117

$ 12,604

~~__________~~


~~(a)~~	Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2017 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, 2017.


~~(b)~~	~~Excludes Generation's contingent operating lease payments associated with contracted generation agreements. These amounts are included within purchase power obligations.~~


~~(c)~~	Purchase power obligations include contingent operating lease payments associated with contracted generation agreements. Amounts presented represent Generation’s expected payments under these arrangements at December 31, 2017. Expected

payments include certain fixed capacity charges which may be reduced based on plant availability. Expected payments exclude renewable PPA contracts that are contingent in nature. Contained within Purchase power obligations are Net Capacity Purchases of ~~$106 million, $99 million, $40 million, $31 million, $19 million and $171 million for~~ ~~2018~~, ~~2019~~, ~~2020~~, ~~2021~~, ~~2022~~ ~~and thereafter, respectively.~~


~~(d)~~	~~Represents commitments to purchase fuel supplies for nuclear and fossil generation, including those related to CENG.~~

~~(e)~~


~~(f)~~	Represents commitments for Generation's ongoing investments in new natural gas generation construction. As of December 31, 2017, the commitments relate to the construction of a new dual fuel, natural peaking facility in Massachusetts. Achievement of commercial operation related to this project is expected in 2018.


~~(g)~~	~~See Note 23 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for further information regarding SNF obligations.~~

~~ComEd~~

Payment due within
Total 2018
2019 -
2020

2021 -
2022
Due 2023
and beyond
Long-term debt^(a)
$ 7,874
$ 840
$ 800
$ 350
$ 5,884
Interest payments on long-term debt^(b)
4,937
269
517
469
3,682
Capital leases 8
—
—
—
8
Operating leases^(c)
23
7
10
6
—
Electric supply procurement 741
476
265
—
—
Long-term renewable energy and REC commitments^(d)
1,321
82
166
177
896
Other purchase obligations^(e)
1,035
927
82
16
10
PJM regional transmission expansion commitments^(f)
164
36
104
24
—
Total contractual obligations $ 16,103
$ 2,637

$ 1,944

$ 1,042

$ 10,480

~~__________~~


~~(a)~~	~~Includes $206 million due after 2023 to a ComEd financing trust.~~


~~(b)~~	Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2017 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, 2017. Includes estimated interest payments due to the ComEd financing trust.


~~(c)~~	Amounts related to certain real estate leases and railroad licenses effectively have indefinite payment periods. As a result, ComEd, has excluded these payments from the remaining years as such amounts would not be meaningful. ComEd’s average annual obligation for these arrangements, included in each of the years 2018-2022, was $2 million.

~~(d)~~

Primarily related to ComEd 20-year contracts for renewable energy and RECs beginning in June 2012. ComEd is permitted to recover its renewable energy and REC costs from retail customers with no mark-up. The commitments represent the maximum and earliest settlements with suppliers for renewable energy and RECs under the existing contract terms. See Note 3—Regulatory Matters of Combined Notes to Consolidated Financial Statements for additional information.

~~(e)~~


~~(f)~~	Under its operating agreement with PJM, ComEd is committed to the construction of transmission facilities to maintain system reliability. These amounts represent ComEd’s expected portion of the costs to pay for the completion of the required construction projects. See Note 3 — Regulatory Matters of Combined Notes to Consolidated Financial Statements for additional information.

In January 2018, ComEd entered into 10-year ZEC procurement contracts with Generation. The following table summarizes ComEd’s future estimated cash payments under the executed contract. See Note 3 — Regulatory Matters and Note 28 — Subsequent Events of the Combined Notes to Consolidated Financial Statements for more information.

Payment due within
Total 2018
2019 -
2020

2021 -
2022
Due 2023
and beyond
ZEC commitments^(a)
$ 1,589
$ 271
$ 327
$ 314
$ 677

~~__________~~


~~(a)~~	Annual ZEC commitment amounts will be published by the IPA each May prior to the start of the subsequent planning year. Amounts presented in the table represent management's estimate of ComEd's obligation based on forward energy prices and load forecasts. ComEd is permitted to recover its ZEC costs from retail customers with no mark-up.

~~PECO~~

Payment due within
Total 2018
2019 -
2020

2021 -
2022
Due 2023
and beyond
Long-term debt^(a)
$ 3,109
$ 500
$ —
$ 650
$ 1,959
Interest payments on long-term debt^(b)
1,916
105
210
202
1,399
Operating leases^(c)
25
5
10
10
—
Fuel purchase agreements^(d)
339
113
151
35
40
Electric supply procurement^(d)
526
420
106
—
—
AEC purchase commitments^(d)
6
2
4
—
—
Other purchase obligations^(e)
465
257
157
46
5
PJM regional transmission expansion commitments^(f)
53
16
29
8
—
Total contractual obligations $ 6,439
$ 1,418

$ 667

$ 951

$ 3,403

~~__________~~


~~(a)~~	~~Includes $184 million due after 2023 to PECO financing trusts.~~


~~(b)~~	Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2017 and do not reflect anticipated future refinancing, early redemptions or debt issuances.

~~(c)~~

Includes estimated cash payments for service fees related to PECO’s meter reading operating lease. Amounts related to certain real estate leases and railroad licenses effectively have indefinite payment periods. As a result, PECO has excluded these payments from the remaining years as such amounts would not be meaningful. PECO’s average annual obligation for these arrangements, included in each of the years 2018-2022, was $5 million.


~~(d)~~	~~Represents commitments to purchase natural gas and related transportation, storage capacity and services, procure electric supply, and purchase AECs.~~

~~(e)~~


~~(f)~~	Under its operating agreement with PJM, PECO is committed to the construction of transmission facilities to maintain system reliability. These amounts represent PECO’s expected portion of the costs to pay for the completion of the required construction projects. See Note 3 — Regulatory Matters of Combined Notes to Consolidated Financial Statements for additional information.

~~BGE~~

Payment due within
Total 2018
2019 -
2020

2021 -
2022
Due 2023
and beyond
Long-term debt $ 2,600
$ —
$ —
$ 550
$ 2,050
Interest payments on long-term debt^(a)
1,689
101
201
186
1,201
Operating leases^(b)(c)(d)
170
34
68
49
19
Fuel purchase agreements^(e)
514
86
121
106
201
Electric supply procurement^(e)
1,026
645
381
—
—
Curtailment services commitments^(e)
50
22
21
7
—
Other purchase obligations^(f)
453
394
50
4
5
PJM regional transmission expansion commitments^(g)
118
35
70
13
—
Total contractual obligations $ 6,620
$ 1,317

$ 912

$ 915

$ 3,476

~~__________~~


~~(a)~~	Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2017 and do not reflect anticipated future refinancing, early redemptions or debt issuances.


~~(b)~~	Amounts related to certain real estate leases and railroad licenses effectively have indefinite payment periods. As a result, BGE has excluded these payments from the remaining years as such amounts would not be meaningful. BGE’s average annual obligation for these arrangements, included in each of the years 2018—2022, was $1 million, respectively.


~~(c)~~	~~Includes all future lease payments on a 99-year real estate lease that expires in 2106.~~


~~(d)~~	The BGE column above includes minimum future lease payments associated with a 6-year lease for the Baltimore City conduit system that became effective during the fourth quarter of 2016. BGE's total commitments under the lease agreement are $25 million, $26 million, $28 million , $28 million and $14 million related to years 2018, 2019, 2020, 2021and 2022, respectively.


~~(e)~~	~~Represents commitments to purchase natural gas and related transportation, storage capacity and services, procure electric supply, and curtailment services.~~

~~(f)~~

Represents the future estimated value at December 31, 2017 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between the 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.


~~(g)~~	Under its operating agreement with PJM, BGE is committed to the construction of transmission facilities to maintain system reliability. These amounts represent BGE’s expected portion of the costs to pay for the completion of the required construction projects. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements.

~~PHI~~

Payment due within
Total 2018
2019 -
2020

2021 -
2022
Due 2023
and beyond
Long-term debt $ 5,162
$ 370
$ 12
$ 551
$ 4,229
Interest payments on long-term debt^(a)
1,328
231
461
433
203
Capital leases 27
13
14
—
—
Operating leases 415
56
86
79
194
Fuel purchase agreements^(b)
270
30
60
60
120
Long-term renewable energy and REC commitments^(b)
345
29
58
58
200
Electric supply procurement^(b)
1,720
1,060
660
—
—
Curtailment services commitments^(b)
69
30
33
6
—
Other purchase obligations^(c)
3,434
2,368
822
196
48
DC PLUG obligation^(d)
188
28
60
60
40
PJM regional transmission expansion commitments^(e)
234
92
67
75
—
Total contractual obligations $ 13,192
$ 4,307
$ 2,333
$ 1,518
$ 5,034

~~__________~~


~~(a)~~	Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2017 and do not reflect anticipated future refinancing, early redemptions or debt issuances.


~~(b)~~	~~Represents commitments to purchase natural gas and related transportation, storage capacity and services, procure electric renewable energy and RECs, procure electric supply, and curtailment services.~~

~~(c)~~


~~(d)~~	Related to DC PLUG project costs for assets funded by the District of Columbia for which the District of Columbia has assessed a charge on Pepco. Pepco will recover this charge from customers through a volumetric distribution rider. See Note 3 — Regulatory Matters of Combined Notes to Consolidated Financial Statements for additional information.


~~(e)~~	Under its operating agreement with PJM, PHI is committed to the construction of transmission facilities to maintain system reliability. These amounts represent PHI’s expected portion of the costs to pay for the completion of the required construction projects. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements.

~~Pepco~~

Payment due within
Total 2018
2019 -
2020

2021 -
2022
Due 2023
and beyond
Long-term debt $ 2,543
$ 6
$ —
$ 312
$ 2,225
Interest payments on long-term debt^(a)
755
129
259
251
116
Capital leases 27
13
14
—
—
Operating leases 38
8
13
9
8
Electric supply procurement^(b)
675
433
242
—
—
Curtailment services commitments^(b)
26
13
10
3
—
Other purchase obligations^(c)
1,676
995
497
146
38
DC PLUG obligation^(d)
188
28
60
60
40
PJM regional transmission expansion commitments^(e)
86
5
38
43
—
Total contractual obligations $ 6,014
$ 1,630
$ 1,133
$ 824
$ 2,427

~~__________~~


~~(a)~~	Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2017 and do not reflect anticipated future refinancing, early redemptions or debt issuances.


~~(b)~~	~~Represents commitments to purchase procure electric supply and curtailment services.~~

~~(c)~~


~~(d)~~	Related to DC PLUG project costs for assets funded by the District of Columbia for which the District of Columbia has assessed a charge on Pepco. Pepco will recover this charge from customers through a volumetric distribution rider. See Note 3 — Regulatory Matters of Combined Notes to Consolidated Financial Statements for additional information.


~~(e)~~	Under its operating agreement with PJM, Pepco is committed to the construction of transmission facilities to maintain system reliability. These amounts represent Pepco’s expected portion of the costs to pay for the completion of the required construction projects. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements.

~~DPL~~

Payment due within
Total 2018
2019 -
2020

2021 -
2022
Due 2023
and beyond
Long-term debt $ 1,309
$ 83
$ 12
$ —
$ 1,214
Interest payments on long-term debt^(a)
288
49
97
96
46
Operating leases^(b)
121
20
23
24
54
Fuel purchase agreements^(c)
270
30
60
60
120
Long-term renewable energy and associated REC commitments^(c)
345
29
58
58
200
Electric supply procurement^(c)
504
312
192
—
—
Curtailment services commitments^(c)
36
14
19
3
—
Other purchase obligations^(d)
963
776
152
32
3
PJM regional transmission expansion commitments^(e)
27
19
3
5
—
Total contractual obligations $ 3,863
$ 1,332
$ 616
$ 278
$ 1,637

~~__________~~


~~(a)~~	Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2017 and do not reflect anticipated future refinancing, early redemptions or debt issuances.


~~(b)~~	Amounts related to certain real estate leases and railroad licenses effectively have indefinite payment periods. As a result, DPL has excluded these payments from the remaining years as such amounts would not be meaningful. DPL's average annual obligation for these arrangements, included in each of the years 2018-2022, was $2 million.


~~(c)~~	~~Represents commitments to purchase natural gas and related transportation, storage capacity and services, procure electric renewable energy and RECs, procure electric supply, and curtailment services.~~

~~(d)~~


~~(e)~~	Under its operating agreement with PJM, DPL is committed to the construction of transmission facilities to maintain system reliability. These amounts represent DPL’s expected portion of the costs to pay for the completion of the required construction projects. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements.

~~ACE~~

Payment due within
Total 2018
2019 -
2020

2021 -
2022
Due 2023
and beyond
Long-term debt $ 1,127
$ 281
$ —
$ 239
$ 607
Interest payments on long-term debt ^(a)
201
39
77
58
27
Operating leases 57
9
16
13
19
Electric supply procurement ^(b)
541
315
226
—
—
Curtailment services commitments ^(b)
7
3
4
—
—
Other purchase obligations ^(c)
581
439
124
15
3
PJM regional transmission expansion commitments ^(d)
121
68
26
27
—
Total contractual obligations $ 2,635
$ 1,154
$ 473
$ 352
$ 656

~~__________~~


~~(a)~~	Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2017 and do not reflect anticipated future refinancing, early redemptions or debt issuances.


~~(b)~~	~~Represents commitments to procure electric supply and curtailment services.~~

~~(c)~~


~~(d)~~	Under its operating agreement with PJM, ACE is committed to the construction of transmission facilities to maintain system reliability. These amounts represent ACE’s expected portion of the costs to pay for the completion of the required construction projects. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements.

~~See Note 23~~ — ~~Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for discussion of the Registrants’ other commitments potentially triggered by future events.~~

~~For additional information regarding:~~

~~commercial paper, see Note 13~~ — Debt and Credit Agreements ~~of the Combined Notes to Consolidated Financial Statements.~~

~~long-term debt, see Note 13~~ — ~~Debt and Credit Agreements~~ ~~of the Combined Notes to Consolidated Financial Statements.~~

~~liabilities related to uncertain tax positions, see Note 14~~ — ~~Income Taxes~~ ~~of the Combined Notes to Consolidated Financial Statements.~~

~~capital lease obligations, see Note 13~~ — ~~Debt and Credit Agreements~~ ~~of the Combined Notes to Consolidated Financial Statements.~~

~~operating leases and rate relief commitments, see Note 23~~ — ~~Commitments and Contingencies~~ ~~of the Combined Notes to Consolidated Financial Statements.~~

~~the nuclear decommissioning and SNF obligations, see Notes 15~~ — ~~Asset Retirement Obligations~~ ~~and 23~~ — ~~Commitments and Contingencies~~ ~~of the Combined Notes to Consolidated Financial Statements.~~

~~regulatory commitments, see Note 3~~ — ~~Regulatory Matters~~ ~~of the Combined Notes to Consolidated Financial Statements.~~

~~variable interest entities, see Note 2~~ — ~~Variable Interest Entities~~ ~~of the Combined Notes to Consolidated Financial Statements.~~

~~nuclear insurance, see Note 23~~ — ~~Commitments and Contingencies~~ ~~of the Combined Notes to Consolidated Financial Statements.~~

~~new accounting pronouncements, see Note 1~~ — ~~Significant Accounting Policies~~ ~~of the Combined Notes to Consolidated Financial Statements.~~



~~ITEM 7A.~~	~~QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK~~

The Registrants are exposed to market risks associated with adverse changes in commodity prices, counterparty credit, interest rates and equity prices. Exelon’s RMC approves risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of risk exposures. The RMC is chaired by the chief executive officer and includes the chief risk officer, chief strategy officer, chief executive officer of Exelon Utilities, chief commercial officer, chief financial officer and chief executive officer of Constellation. The RMC reports to the Finance and Risk Committee of the Exelon Board of Directors on the scope of the risk management activities.

~~Commodity Price Risk (All Registrants)~~

Commodity price risk is associated with price movements resulting from changes in supply and demand, fuel costs, market liquidity, weather conditions, governmental regulatory and environmental policies and other factors. To the extent the total amount of energy Exelon generates and purchases differs from the amount of energy it has contracted to sell, Exelon is exposed to market fluctuations in commodity prices. Exelon seeks to mitigate its commodity price risk through the sale and purchase of electricity, fossil fuel and other commodities.

~~Generation~~

Electricity available from Generation’s owned or contracted generation supply in excess of Generation’s obligations to customers, including portions of the Utility Registrants' retail load, is sold into the wholesale markets. To reduce commodity price risk caused by market fluctuations, Generation enters into non-derivative contracts as well as derivative contracts, including swaps, futures, forwards and options, with approved counterparties to hedge anticipated exposures. Generation uses derivative instruments as economic hedges to mitigate exposure to fluctuations in commodity prices. Generation expects the settlement of the majority of its economic hedges will occur during 2018 through 2020.

In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on Generation’s owned and contracted generation positions which have not been hedged. Exelon's hedging program involves the hedging of commodity price risk for Exelon's expected generation, typically on a ratable basis over three-year periods. As of December 31, 2017, the percentage of expected generation hedged is 85%-88%, 55%-58% and 26%-29% for 2018, 2019 and 2020,

respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation. Expected generation is the volume of energy that best represents our commodity position in energy markets from owned or contracted generating facilities based upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products and options. Equivalent sales represent all hedging products, which include economic hedges and certain non-derivative contracts, including Generation’s sales to ComEd, PECO and BGE to serve their retail load.

A portion of Generation’s hedging strategy may be accomplished with fuel products based on assumed correlations between power and fuel prices, which routinely change in the market. Market price risk exposure is the risk of a change in the value of unhedged positions. The forecasted market price risk exposure for Generation’s entire economic hedge portfolio associated with a $5 reduction in the annual average around-the-clock energy price based on December 31, 2017 market conditions and hedged position would be decreases in pre-tax net income of approximately $110 million, $400 million and $630 million, respectively, for 2018, 2019 and 2020. Power price sensitivities are derived by adjusting power price assumptions while keeping all other price inputs constant. Generation actively manages its portfolio to mitigate market price risk exposure for its unhedged position. Actual results could differ depending on the specific timing of, and markets affected by, price changes, as well as future changes in Generation’s portfolio. See Note 12 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional ~~information.~~

~~Proprietary Trading Activities~~

~~Proprietary trading portfolio~~information of the Registrants’ long-term debt. Debt activity for ~~the year ended December 31, 2017, resulted in pre-tax gains of $18 million due to net mark-to-market gains of $5 million~~2022 and ~~realized gains of $13 million. Generation has not segregated proprietary trading activity within~~2021 by Registrant was as follows:

During 2022, the following ~~discussion because~~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

Procurement of software licenses

Exelon

Long-Term Software License Agreements

3.70%

August 9, 2025

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

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 ~~relative size~~Notes, Exelon entered into a Registration Rights Agreement with the representatives of the ~~proprietary trading portfolio in comparison to Generation’s total Revenue net of purchased power and fuel expense. See Note 12 — Derivative Financial Instruments~~initial purchasers of the ~~Combined~~ Notes ~~to Consolidated Financial Statements for additional information.~~

~~Fuel Procurement~~

~~Generation procures natural gas through long-term~~ and short-term contracts, and spot-market purchases. Nuclear fuel assemblies are obtained predominantly through long-term uranium concentrate supply contracts, contracted conversion services, contracted enrichment services, or a combination thereof, and contracted fuel fabrication services. The supply markets for uranium concentrates and certain nuclear fuel services are subject to price fluctuations and availability restrictions. Supply market conditions may make Generation’s procurement contracts subject to credit risk relatedother parties. Pursuant to the ~~potential non-performance~~Registration Rights Agreement,

Table of ~~counterparties~~Contents

Exelon filed a registration statement on August 3, 2022, with respect to ~~deliver~~an offer to exchange the ~~contracted commodity or service at~~Notes for substantially similar notes of Exelon that are registered under the ~~contracted prices. Approximately 59%~~Securities Act. An exchange offer of ~~Generation’s uranium concentrate requirements from 2018 through 2022 are supplied by three producers. In~~registered notes for the ~~event of non-performance by these or other suppliers, Generation believes that replacement uranium concentrates can be obtained, although at prices that may be unfavorable when compared~~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 ~~prices~~Notes, except that their issuance was registered under the ~~current supply agreements. Non-performance by these counterparties could have a material adverse impact on Exelon’s and Generation’s results of operations, cash flows and financial positions.~~Securities Act.

~~ComEd~~

(c)On January 3, 2023, ComEd entered into ~~20-year contracts for renewable energy~~a purchase agreement of First Mortgage Bonds of $400 million and ~~RECs beginning in June 2012. ComEd is permitted to recover its renewable energy~~$575 million at 4.90% and ~~REC costs from retail customers with no mark-up.~~5.30% due on February 1, 2033 and February 1, 2053, respectively. The annual commitments represent the maximum settlements with suppliers for renewable energy and RECs under the existing contract terms. Pursuant to the ICC’s Order on December 19, 2012, ComEd’s commitments under the existing long-term contracts were reduced for the June 2013 through May 2014 procurement period. In addition, the ICC’s December 18, 2013 Order approved the reduction

~~of ComEd’s commitments under those contracts for the June 2014 through May 2015 procurement period, and the amount~~closing date of the ~~reduction~~issuance occurred on January 10, 2023.

During 2021, the following long-term debt was ~~approved by~~issued:

Company

Type

Interest Rate

Maturity

Amount

Use of Proceeds

Exelon

Long-Term Software License Agreements

3.62%

December 1, 2025

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

Repay existing indebtedness and for general corporate purposes.

During 2022, the ~~ICC~~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

Exelon

Long-Term Software License Agreement

2.30%

December 1, 2025

Exelon

Long-Term Software License Agreement

3.70%

August 9, 2025

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 ~~March 2014.~~

~~ComEd has block energy contracts~~connection with the separation, on January 31, 2022, Exelon Corporate received cash from Generation of $258 million to ~~procure electric supply~~settle an intercompany loan that ~~are executed through a competitive procurement process, which is further discussed in Note 3 — Regulatory Matters~~mirrored the terms and amounts of the ~~Combined Notes to Consolidated Financial Statements.~~third-party debt obligations. The ~~block energy contracts are considered derivatives and qualify for the normal purchases and normal sales scope exception under current derivative authoritative guidance, and~~loan agreements were entered into as a result are accounted for on an accrual basis of accounting. ComEd does not execute derivatives for speculative or proprietary trading purposes. For additional information on these contracts, see Note 12 — Derivative Financial Instrumentspart of the ~~Combined Notes to Consolidated Financial Statements.~~

~~PECO, BGE, Pepco, DPL and ACE~~

PECO, BGE, Pepco, DPL and ACE have contracts to procure electric supply that are executed through a competitive procurement process, which are further discussed in Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements. PECO, BGE, Pepco, DPL and ACE have certain full requirements contracts, which are considered derivatives and qualify for the normal purchases and normal sales scope exception under current derivative authoritative guidance, and as a result are accounted for on an accrual basis of accounting. Other full requirements contracts are not derivatives.

PECO, BGE and DPL have also executed derivative natural gas contracts, which either qualify for the normal purchases and normal sales exception or have no mark-to-market balances because the derivatives are index priced, to hedge their long-term price risk in the natural gas market. The hedging programs for natural gas procurement have no direct impact on their results of operations or financial position.

PECO, BGE, Pepco, DPL and ACE do not execute derivatives for speculative or proprietary trading purposes. For additional information on these contracts, see Note 12 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements.

~~Trading and Non-Trading Marketing Activities~~

The following tables detail Exelon’s, Generation’s, ComEd’s, PHI's and DPL's trading and non-trading marketing activities is included to address the recommended disclosures by the energy industry’s Committee of Chief Risk Officers (CCRO).

The following table provides detail on changes in Exelon’s, Generation’s, ComEd’s, PHI's and DPL's commodity mark-to-market net asset or liability balance sheet position from December 31, 2015 to December 31, 2017. It indicates the drivers behind changes in the balance sheet amounts. This table incorporates the mark-to-market activities that are immediately recorded in earnings. This table excludes all NPNS contracts and does not segregate proprietary trading activity.2012 Constellation merger. See Note 12 16

Table of Contents

— ~~Derivative Financial Instruments~~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

Exelon

Long-Term Software License Agreements

3.62%

December 1, 2025

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

ACE

Transition Bonds

5.55%

October 20, 2021

Dividends

Quarterly dividends declared by the Exelon Board of Directors during the ~~mark-to-market~~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 ~~contract net assets (liabilities) recorded~~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, ~~2017~~2022, and ~~2016.~~

Successor Predecessor

March 24 to
December 31,

January 1 to
March 23,
Exelon Generation ComEd DPL PHI PHI
Total mark-to-market energy contract net assets (liabilities) at December 31, 2015^(a)
$ 1,506

$ 1,753
$ (247 ) $ —
$ —
$ —
Total change in fair value during 2016 of contracts recorded in result of operations 236
236
—
—
—
Reclassification to be realized at settlement of contracts recorded in results of operations (265 ) (265 ) —
—
—
—
Contracts received at acquisition date^(b)
(59 ) (59 ) —
—
—
—
Changes in fair value—recorded through regulatory assets and liabilities^(c)
(8 ) —
(11 ) 4
3
1
Changes in allocated collateral (908 ) (905 ) —
(4 ) (3 ) (1 )
Changes in net option premium paid 66
66
—
—
—
—
Option premium amortization 11
11
—
—
—
—
Upfront payments and amortizations^(d)
140
140
—
—

Total mark-to-market energy contract net assets (liabilities) at December 31, 2016^(a)
$ 719
$ 977
$ (258 ) $ —
$ —
$ —

~~__________~~


~~(a)~~	~~Amounts are shown net of collateral paid to and received from counterparties.~~


~~(b)~~	~~Includes fair value from contracts received at acquisition of ConEdison Solutions of $(59) million.~~

~~(c)~~

For ComEd and DPL, the changes in fair value are recorded as a change in regulatory assets or liabilities. As of December 31, 2016, ComEd recorded a regulatory liability of $258 million, respectively, related to its mark-to-market derivative liabilities with Generation and unaffiliated suppliers. ComEd recorded $29 million of decreases in fair value and an increase for realized losses due to settlements of $18 million in purchased power expense associated with floating-to-fixed energy swap suppliers for the year ended December 31, 2016.


~~(d)~~	~~Includes derivative contracts acquired or sold by Generation through upfront payments or receipts of cash, excluding option premiums, and the associated amortizations.~~

Successor
Exelon Generation ComEd DPL PHI
Total mark-to-market energy contract net assets (liabilities) at December 31, 2016^(a)
$ 719
$ 977
$ (258 ) $ —
$ —
Total change in fair value during 2016 of contracts recorded in result of operations 110
110
—
—
—
Reclassification to be realized at settlement of contracts recorded in results of operations (273 ) (273 ) —
—
—
Changes in fair value—recorded through regulatory assets and liabilities^(c)
(1 ) —
2
(3 ) (3 )
Changes in allocated collateral 140
137
—
3
3
Changes in net option premium received (28 ) (28 ) —
—
—
Option premium amortization (7 ) (7 ) —
—
—
Upfront payments and amortizations^(b)
(24 ) (24 ) —
—
—
Other miscellaneous^(d)
31
31
—
—
—
Total mark-to-market energy contract net assets (liabilities) at December 31, 2017^(a)
$ 667
$ 923
$ (256 ) $ —
$ —

~~__________~~


~~(a)~~	~~Amounts are shown net of collateral paid to and received from counterparties.~~


~~(b)~~	~~Includes derivative contracts acquired or sold by Generation through upfront payments or receipts of cash, excluding option premiums, and the associated amortizations.~~

~~(c)~~

For ComEd and DPL, the changes in fair value are recorded as a change in regulatory assets or liabilities. As of December 31, 2017, ComEd recorded a regulatory liability of $256 million, related to its mark-to-market derivative liabilities with Generation and unaffiliated suppliers. For the year ended December 31, 2017, ComEd also recorded $18 million of decreases in fair value and 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, 2017.


~~(d)~~	~~As a result of the bankruptcy filing for EGTP on November 7, 2017, the net mark-to-market commodity contracts were deconsolidated from Exelon’s and Generation consolidated financial statements.~~

~~Fair Values~~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 ~~following tables present maturity~~Registrants believe their cash flow from operating activities, access to credit markets, and ~~source~~their credit facilities provide sufficient liquidity to support the estimated future cash requirements discussed below.

Table of ~~fair value for~~Contents

On August 4, 2022, Exelon ~~Generation~~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 ComEd mark-to-market commodity contract net assets (liabilities). The tables provide two fundamental pieces of information. First, the tables provide the source of fair value used in determining the carrying amountNote 16 — Debt and Credit Agreements of the ~~Registrants’ total mark-to-market net assets (liabilities), net~~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 ~~allocated collateral. Second,~~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 ~~tables show~~Equity Distribution Agreement and may at any time suspend or terminate offers and sales under the ~~maturity, by year,~~Equity Distribution Agreement. As of December 31, 2022, Exelon has not issued any shares of common stock under the ~~Registrants’ commodity contract net assets (liabilities) net~~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 ~~allocated collateral, giving an indication of when these mark-to-market amounts will settle and either generate or require cash.~~$1.75 billion to Generation on January 31, 2022. See Note 112 — ~~Fair Value of Financial Assets and Liabilities~~Discontinued Operations of the Combined Notes to Consolidated Financial Statements for additional information ~~regarding fair value measurements and~~on the ~~fair value hierarchy.~~

~~Exelon~~

Maturities Within
Total Fair
Value
2018 2019 2020 2021 2022 2023 and Beyond
Normal Operations, Commodity derivative contracts^(a)(b):

Actively quoted prices (Level 1) $ (32 ) $ (43 ) $ (15 ) $ 2
$ (2 ) $ —
$ (90 )
Prices provided by external sources (Level 2) 462
(6 ) (1 ) 6
—
—
461
Prices based on model or other valuation methods (Level 3)^(c)
315
130
23
(27 ) (58 ) (87 ) 296
Total $ 745
$ 81
$ 7
$ (19 ) $ (60 ) $ (87 ) $ 667

~~__________~~


~~(a)~~	~~Mark-to-market gains and losses on other economic hedge and trading derivative contracts that are recorded in results of operations.~~


~~(b)~~	~~Amounts are shown net of collateral paid to and received from counterparties (and offset against mark-to-market assets and liabilities) of $466 million at December 31, 2017.~~


~~(c)~~	~~Includes ComEd’s net assets (liabilities) associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers.~~

~~Generation~~

Maturities Within
Total Fair
Value
2018 2019 2020 2021 2022 2023 and Beyond
Normal Operations, Commodity derivative contracts^(a)(b):

Actively quoted prices (Level 1) $ (32 ) $ (43 ) $ (15 ) $ 2
$ (2 ) $ —
$ (90 )
Prices provided by external sources (Level 2) 462
(6 ) (1 ) 6
—
—
461
Prices based on model or other valuation methods (Level 3)^(c)
336
152
44
(6 ) (37 ) 63
552
Total $ 766
$ 103
$ 28
$ 2
$ (39 ) $ 63
$ 923

~~__________~~


~~(a)~~	~~Mark-to-market gains and losses on other economic hedge and trading derivative contracts that are recorded in the results of operations.~~


~~(b)~~	~~Amounts are shown net of collateral paid to and received from counterparties (and offset against mark-to-market assets and liabilities) of $466 million at December 31, 2017.~~

~~ComEd~~

Maturities Within
Fair
Value
2018 2019 2020 2021 2022 2023 and Beyond
Prices based on model or other valuation methods (Level 3)^(a)
$ (21 ) $ (22 ) $ (21 ) $ (21 ) $ (21 ) $ (150 ) $ (256 )

~~__________~~


~~(a)~~	~~Represents ComEd’s net liabilities associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers.~~

~~Credit Risk, Collateral and Contingent Related Features (All Registrants)~~separation.

The ~~Registrants~~following table presents the incremental collateral that each Utility Registrant would ~~be exposed~~have been required to ~~credit-related losses~~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 ~~non-performance by counterparties~~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.

Table of ~~derivative contracts, before collateral, is represented~~Contents

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 ~~fair value~~Pension Protection Act of ~~contracts at the reporting date. See Note 12—Derivative Financial Instruments~~2006 (the Act), management of the ~~Combined Notes~~pension obligation, and regulatory implications. The Act requires the attainment of certain funding levels to ~~Consolidated Financial Statements for~~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 ~~detailed discussion~~funding strategy to make annual contributions with the objective of ~~credit risk, collateral,~~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 ~~contingent~~regulatory implications (amounts deemed prudent to meet regulatory expectations and best assure continued rate recovery). The amounts below include benefit payments related ~~features.~~

~~Generation~~to unfunded plans.

The following ~~tables provide information on Generation’s credit exposure for~~table provides all ~~derivative instruments, normal purchases~~Registrants' planned contributions to the qualified pension plans, planned benefit payments to non-qualified pension plans, and ~~normal sales agreements,~~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 ~~applicable payables~~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 ~~receivables, net of collateral~~OPEB plans earn greater than the expected asset returns, annual pension and instruments that are subject to master netting agreements, as of December 31, 2017. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties and an indication of the duration of a company’s credit risk by credit rating of the counterparties. The figuresOPEB contribution requirements in ~~the tables below exclude credit risk exposure from individual retail customers, uranium procurement contracts, and exposure through RTOs, ISOs and commodity exchanges, which are discussed below.~~future years could decrease. Additionally, the figures in the tables below exclude exposures with affiliates, including net receivables with ComEd, PECO, BGE, Pepco, DPL and ACE of $28 million, $22 million, $24 million, $36 million, $12 million and $6 million respectively. expected contributions could change if Exelon changes its pension or OPEB funding strategy.

See Note 2614 — ~~Related Party Transactions~~Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional ~~information.~~information on pension and OPEB contributions.

Cash Requirements for Other Financial Commitments

Rating as of December 31, 2017
Total
Exposure
Before Credit
Collateral

Credit
Collateral ^(a)

Net
Exposure

Number of
Counterparties
Greater than 10%
of Net Exposure

Net Exposure of
Counterparties
Greater than 10%
of Net Exposure
Investment grade $ 738
$ 4
$ 734
1
$ 244
Non-investment grade 90
12
78
—
—
No external ratings
Internally rated—investment grade 253
—
253
—
—
Internally rated—non-investment grade 83
11
72
—
—
Total $ 1,164
$ 27
$ 1,137
1
$ 244

Maturity of Credit Risk Exposure
Rating as of December 31, 2017
Less than
2 Years

2-5
Years

Exposure
Greater than
5 Years

Total Exposure
Before Credit
Collateral
Investment grade $ 657
$ 80
$ 1
$ 738
Non-investment grade 74
16
—
90
No external ratings
Internally rated—investment grade 191
30
32
253
Internally rated—non-investment grade 79
4
—
83
Total $ 1,001
$ 130
$ 33
$ 1,164

Net Credit Exposure by Type of Counterparty As of December 31, 2017
Financial institutions $ 41
Investor-owned utilities, marketers, power producers 558
Energy cooperatives and municipalities 452
Other 86
Total $ 1,137

~~__________~~


~~(a)~~	~~As of December 31, 2017, credit collateral held from counterparties where Generation had credit exposure included $8 million of cash and $19 million of letters of credit.~~

The ~~Utility Registrants~~

~~Credit risk for~~following tables summarize the Utility Registrants is governed by credit and collection policies, which are aligned with state regulatory requirements. The Utility Registrants are currently obligated to provide service to all electric customers within their franchised territories. The Utility Registrants record a provision for uncollectible accounts, based upon historical experience, to provide for the potential loss from nonpayment by these customers. The Utility Registrants will monitor nonpayment from customers and will make any necessary adjustments to the provision for uncollectible accounts. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for the allowance for uncollectible accounts policy. The Utility Registrants did not have any customers representing over 10% of their revenuesRegistrants' future estimated cash payments as of December 31, ~~2017.~~ 2022 under existing financial commitments:

Table of Contents

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.

(d)Represents commitments to purchase natural gas and related transportation, storage capacity, and services.

(f)These amounts represent Exelon’s expected contributions to its qualified pension plans. Qualified pension contributions for years after 2028 are not included.

Table of Contents

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.

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.

Table of Contents

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

__________

(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

__________

(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.

Table of Contents

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

__________

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

__________

(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.

Table of Contents

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

__________

(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.~~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:

~~As of December 31, 2017, ComEd’s net credit exposure to suppliers was approximately $1 million. PECO~~


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 ~~had no net credit exposure to suppliers as~~meet their short-term liquidity requirements primarily through the issuance of ~~December 31, 2017. As~~commercial paper. PECO meets its short-term liquidity requirements primarily through the issuance of ~~December 31, 2017~~commercial paper and borrowings from the Exelon intercompany money pool. Pepco, DPL, and ~~ACE's net~~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 ~~exposures were immaterial.~~ facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit.

See Note 1216 — ~~Derivative Financial Instruments~~Debt and Credit Agreements of the Combined Notes to Consolidated Financial ~~Statements.~~Statements for additional information on the Registrants’ credit facilities and short term borrowing activity.

~~Collateral (All Registrants)~~

Table of Contents

~~Generation~~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	%	—	%

__________

Security Ratings

As part of the normal course of business, ~~Generation routinely enters~~the Registrants enter into ~~physical~~contracts that contain express provisions or ~~financial contracts~~otherwise permit the Registrants and their counterparties to demand adequate assurance of future performance when there are reasonable grounds for ~~the sale and purchase of electricity, natural gas and other commodities.~~doing so. In accordance with the contracts and applicable contracts law, if ~~Generation is~~the Registrants are downgraded by a credit rating agency, ~~especially if such downgrade is to a level below investment grade,~~ it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future ~~performance. Depending on Generation’s net position with a counterparty, the demand~~performance, which could ~~be for~~include the posting of additional collateral. ~~In the absence of expressly agreed-to provisions that specify the collateral that must be provided, collateral requested will be a function of the facts and circumstances of the situation~~

~~at the time of the demand.~~ See Note 12 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for information regarding collateral requirements. See Note 23 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for information regarding the letters of credit supporting the cash collateral.

Generation transacts output through bilateral contracts. The bilateral contracts are subject to credit risk, which relates to the ability of counterparties to meet their contractual payment obligations. Any failure to collect these payments from counterparties could have a material impact on Exelon’s and Generation’s results of operations, cash flows and financial positions. As market prices rise above or fall below contracted price levels, Generation is required to post collateral with purchasers; as market prices fall below contracted price levels, counterparties are required to post collateral with Generation. To post collateral, Generation depends on access to bank credit facilities, which serve as liquidity sources to fund collateral requirements. See ITEM 7.~~Liquidity and Capital Resources — Credit Matters — Exelon Credit Facilities for additional information.~~

~~The Utility Registrants~~

As of December 31, 2017, ComEd held $10 million in collateral from suppliers in association with energy procurement contracts, approximately $2 million in collateral from suppliers for REC contract obligations and approximately $19 million in collateral from suppliers for long-term renewable energy contracts. BGE is not required to post collateral under its electric supply contracts but was holding an immaterial amount of collateral under its electric supply procurement contracts. BGE was not required to post collateral under its natural gas procurement contracts, but was holding an immaterial amount of collateral under its natural gas procurement contracts. PECO, Pepco, DPL and ACE were not required to post collateral under their energy and/or natural gas procurement contracts. See Note 3 — Regulatory Matters and Note 1215 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional ~~information.~~information on collateral provisions.

~~RTOs and ISOs (All Registrants)~~

All Registrants participate in all, or some, of the established, wholesale spot energy markets that are administered by PJM, ISO-NE, ISO-NY, CAISO, MISO, SPP, AESO, OIESO and ERCOT. ERCOT is not subject to regulation by FERC but performs a similar function in Texas to that performed by RTOs in markets regulated by FERC. In these areas, power is traded through bilateral agreements between buyers and sellers and on the spot energy markets that are administered by the RTOs or ISOs, as applicable. In areas where there is no spot energy market, electricity is purchased and sold solely through bilateral agreements. For sales into the spot markets administered by an RTO or ISO, the RTO or ISO maintains financial assurance policies that are established and enforced by those administrators. The credit ~~policies of the RTOs~~ratings for ComEd, PECO, BGE, and ISOs may, under certain circumstances, require that losses arising from the default of one member on spot energy market transactions be shared by the remaining participants. Non-performance or non-payment by a major counterparty could result in a material adverse impact on the Registrants’ results of operations, cash flows and financial positions.

~~Exchange Traded Transactions (Exelon, Generation, PHI and DPL)~~

~~Generation enters into commodity transactions on NYMEX, ICE, NASDAQ, NGX and the Nodal exchange ("the Exchanges").~~ DPL enters into commodity transactions on ICE. The Exchange clearinghouses act as the counterparty to each trade. Transactions on the Exchanges must adhere to comprehensive collateral and margining requirements. As a result, transactions on Exchanges are significantly collateralized and have limited counterparty credit risk.

~~Interest Rate and Foreign Exchange Risk (All Registrants)~~

The Registrants use a combination of fixed-rate and variable-rate debt to manage interest rate exposure. The Registrants may also utilize fixed-to-floating interest rate swaps, which are typically designated as fair value hedges, to manage their interest rate exposure. In addition, the Registrants may utilize interest rate derivatives to lock in rate levels, which are typically designated as cash flow hedges. These strategies are employed to manage interest rate risks. At December 31, 2017, Exelon had $800 million of notional amounts of fixed-to-floating hedges outstanding and Exelon and Generation had $636 million of notional amounts of floating-to-fixed hedges outstanding. Assuming the fair value and cash flow interest rate hedges are 100% effective, a hypothetical 50 basis point increase in the interest rates associated with unhedged variable-rate debt (excluding Commercial Paper) and fixed-to-floating swaps would result in approximately a $6 million decrease in Exelon Consolidated pre-tax incomedid not change for the year ended December 31, 2017. To manage foreign exchange rate exposure associated with international energy purchases in currencies other than U.S. dollars, Generation utilizes foreign currency derivatives, which are typically designated as economic hedges. See Note 12—Derivative Financial Instruments2022. On January 14, 2022, Fitch lowered Exelon Corporate's long-term and senior unsecured ratings from BBB+ to BBB and affirmed the short-term rating of ~~the Combined Notes~~F2. In addition, Fitch upgraded Pepco, ACE, and PHI's long-term rating from BBB to ~~Consolidated Financial Statements for additional information.~~

~~Equity Price Risk (Exelon~~BBB+ and ~~Generation)~~

~~Exelon~~upgraded Pepco and ~~Generation maintain trust funds, as required by the NRC,~~ACE's senior secured rating from A- to fund certain costs of decommissioning its nuclear plants. As of December 31, 2017, Generation’s decommissioning trust funds are reflected at fair value on its Consolidated Balance Sheets. The mix of securities in the trust funds is designed to provide returns to be used to fund decommissioning and to compensate Generation for inflationary increases in decommissioning costs; however, the equity securities in the trust funds are exposed to price fluctuations in equity markets, and the value of fixed-rate, fixed-income securities are exposed to changes in interest rates. Generation actively monitors the investment performance of the trust funds and periodically reviews asset allocation in accordance with Generation’s NDT fund investment policy. A hypothetical 10% increase in interest rates and decrease in equity prices would result in a $662 million reduction in the fair value of the trust assets. This calculation holds all other variables constant and assumes only the discussed changes in interest rates and equity prices. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS for further discussion of equity price risk as a result of the current capital and credit market conditions.



~~ITEM 7.~~	~~MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

~~Generation~~

~~General~~

~~Generation’s integrated business consists~~Table of the generation, physical delivery and marketing of power across multiple geographical regions through its customer-facing business, Constellation, which sells electricity and natural gas to both wholesale and retail customers. Generation also sells renewable energy and other energy-related products and services. Generation has six reportable segments consisting of the Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Power Regions. These segments are discussed in further detail in ITEM 1. BUSINESS — Exelon Generation Company, LLC of this Form 10-K.

~~Executive Overview~~

A discussion of items pertinent to Generation’s executive overview is set forth under ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Exelon Corporation — Executive Overview of this Form 10-K.

~~Results of Operations~~

~~Year Ended December 31, 2017 Compared to Year Ended December 31, 2016 and Year Ended December 31, 2016 Compared to Year Ended December 31, 2015~~

A discussion of Generation’s results of operations for 2017 compared to 2016 and 2016 compared to 2015 is set forth under Results of Operations—Generation in EXELON CORPORATION — Results of Operations of this Form 10-K.

~~Liquidity and Capital Resources~~

Generation’s business is capital intensive and requires considerable capital resources. Generation’s capital resources are primarily provided by internally generated cash flows from operations and, to the extent necessary, external financing, including the issuance of long-term debt, commercial paper, participation in the intercompany money pool or capital contributions from Exelon. Generation’s access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of the utility industry in general. If these conditions deteriorate to where Generation no longer has access to the capital markets at reasonable terms, Generation has access to credit facilities in the aggregate of $5.8 billion that Generation currently utilizes to support its commercial paper program and to issue letters of credit.

See EXELON CORPORATION — Liquidity and Capital Resources and Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements of this Form 10-K for further discussion.

Capital resources are used primarily to fund Generation’s capital requirements, including construction, retirement of debt, the payment of distributions to Exelon, contributions to Exelon’s pension plans and investments in new and existing ventures. Future acquisitions could require external financing or borrowings or capital contributions from Exelon.

~~Cash Flows from Operating Activities~~

A discussion of items pertinent to Generation’s cash flows from operating activities is set forth under Cash Flows from Operating Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.

~~Cash Flows from Investing Activities~~

A discussion of items pertinent to Generation’s cash flows from investing activities is set forth under Cash Flows from Investing Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.

~~Cash Flows from Financing Activities~~

A discussion of items pertinent to Generation’s cash flows from financing activities is set forth under Cash Flows from Financing Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.

~~Credit Matters~~

~~A discussion of credit matters pertinent to Generation is set forth under Credit Matters in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.~~

~~Contractual Obligations and Off-Balance Sheet Arrangements~~

A discussion of Generation’s contractual obligations, commercial commitments and off-balance sheet arrangements is set forth under Contractual Obligations and Off-Balance Sheet Arrangements in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.

~~Critical Accounting Policies and Estimates~~

~~See All Registrants — Critical Accounting Policies and Estimates above for a discussion of Generation’s critical accounting policies and estimates.~~

~~New Accounting Pronouncements~~

~~See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for information regarding new accounting pronouncements.~~

Contents



~~ITEM 7A.~~	~~QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK~~

~~Generation~~

Generation is exposed to market risks associated with commodity price, credit, interest rates and equity price. These risks are described above under Quantitative and Qualitative Disclosures about Market Risk — Exelon.



~~ITEM 7.~~	~~MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

~~ComEd~~

~~General~~

ComEd operates in a single business segment and its operations consist of the purchase and regulated retail sale of electricity and the provision of distribution and transmission services to retail customers in northern Illinois, including the City of Chicago. This segment is discussed in further detail in ITEM 1. BUSINESS—ComEd of this Form 10-K.

~~Executive Overview~~

~~A discussion of items pertinent to ComEd’s executive overview is set forth under EXELON CORPORATION—Executive Overview of this Form 10-K.~~

~~Results of Operations~~

~~Year Ended December 31, 2017 Compared to Year Ended December 31, 2016 and Year Ended December 31, 2016 Compared to Year Ended December 31, 2015~~

A discussion of ComEd’s results of operations for 2017 compared to 2016 and for 2016 compared to 2015 is set forth under Results of Operations—ComEd in EXELON CORPORATION — Results of Operations of this Form 10-K.

~~Liquidity and Capital Resources~~

ComEd’s business is capital intensive and requires considerable capital resources. ComEd’s capital resources are primarily provided by internally generated cash flows from operations and, to the extent necessary, external financing, including the issuance of long-term debt, commercial paper or credit facility borrowings. ComEd’s access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of the utility industry in general. At December 31, 2017, ComEd had access to a revolving credit facility with aggregate bank commitments of $1 billion.

Capital resources are used primarily to fund ComEd’s capital requirements, including construction, retirement of debt, and contributions to Exelon’s pension plans. Additionally, ComEd operates in rate-regulated environments in which the amount of new investment recovery may be limited and where such recovery takes place over an extended period of time.

~~Cash Flows from Operating Activities~~

A discussion of items pertinent to ComEd’s cash flows from operating activities is set forth under Cash Flows from Operating Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.

~~Cash Flows from Investing Activities~~

A discussion of items pertinent to ComEd’s cash flows from investing activities is set forth under Cash Flows from Investing Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.

~~Cash Flows from Financing Activities~~

A discussion of items pertinent to ComEd’s cash flows from financing activities is set forth under Cash Flows from Financing Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.

~~Credit Matters~~

~~A discussion of credit matters pertinent to ComEd is set forth under Credit Matters in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.~~

~~Contractual Obligations and Off-Balance Sheet Arrangements~~

A discussion of ComEd’s contractual obligations, commercial commitments and off-balance sheet arrangements is set forth under Contractual Obligations and Off-Balance Sheet Arrangements in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.

~~Critical Accounting Policies and Estimates~~

~~See All Registrants — Critical Accounting Policies and Estimates above for a discussion of ComEd’s critical accounting policies and estimates.~~

~~New Accounting Pronouncements~~

~~See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for information regarding new accounting pronouncements.~~



~~ITEM 7A.~~	~~QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK~~

~~ComEd~~

~~ComEd is exposed to market risks associated with commodity price, credit and interest rates. These risks are described above under Quantitative and Qualitative Disclosures about Market Risk— Exelon.~~



~~ITEM 7.~~	~~MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

~~PECO~~

~~General~~

PECO operates in a single business segment and its operations consist of the purchase and regulated retail sale of electricity and the provision of distribution and transmission services in southeastern Pennsylvania including the City of Philadelphia, and the purchase and regulated retail sale of natural gas and the provision of distribution service in Pennsylvania in the counties surrounding the City of Philadelphia. This segment is discussed in further detail in ITEM 1. BUSINESS—PECO of this Form 10-K.

~~Executive Overview~~

~~A discussion of items pertinent to PECO’s executive overview is set forth under EXELON CORPORATION—Executive Overview of this Form 10-K.~~

~~Results of Operations~~

~~Year Ended December 31, 2017 Compared to Year Ended December 31, 2016 and Year Ended December 31, 2016 Compared to Year Ended December 31, 2015~~

A discussion of PECO’s results of operations for 2017 compared to 2016 and for 2016 compared to 2015 is set forth under Results of Operations—PECO in EXELON CORPORATION — Results of Operations of this Form 10-K.

~~Liquidity and Capital Resources~~

PECO’s business is capital intensive and requires considerable capital resources. PECO’s capital resources are primarily provided by internally generated cash flows from operations and, to the extent necessary, external financing, including the issuance of long-term debt, commercial paper or participation in the intercompany money pool. PECO’s access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of the utility industry in general. If these conditions deteriorate to where PECO no longer has access to the capital markets at reasonable terms, PECO has access to a revolving credit facility. At December 31, 2017, PECO had access to a revolving credit facility with aggregate bank commitments of $600 million.

Capital resources are used primarily to fund PECO’s capital requirements, including construction, retirement of debt, the payment of dividends and contributions to Exelon’s pension plans. Additionally, PECO operates in a rate-regulated environment in which the amount of new investment recovery may be limited and where such recovery takes place over an extended period of time.

~~Cash Flows from Operating Activities~~

A discussion of items pertinent to PECO’s cash flows from operating activities is set forth under Cash Flows from Operating Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.

~~Cash Flows from Investing Activities~~

A discussion of items pertinent to PECO’s cash flows from investing activities is set forth under Cash Flows from Investing Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.

~~Cash Flows from Financing Activities~~

A discussion of items pertinent to PECO’s cash flows from financing activities is set forth under Cash Flows from Financing Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.

~~Credit Matters~~

~~A discussion of credit matters pertinent to PECO is set forth under Credit Matters in “EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.~~

~~Contractual Obligations and Off-Balance Sheet Arrangements~~

A discussion of PECO’s contractual obligations, commercial commitments and off-balance sheet arrangements is set forth under Contractual Obligations and Off-Balance Sheet Arrangements in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.

~~Critical Accounting Policies and Estimates~~

~~See All Registrants — Critical Accounting Policies and Estimates above for a discussion of PECO’s critical accounting policies and estimates.~~

~~New Accounting Pronouncements~~

~~See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for information regarding new accounting pronouncements.~~



~~ITEM 7A.~~	~~QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK~~

~~PECO~~

~~PECO is exposed to market risks associated with credit and interest rates. These risks are described above under Quantitative and Qualitative Disclosures about Market Risk—Exelon.~~



~~ITEM 7.~~	~~MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

~~BGE~~

~~General~~

BGE operates in a single business segment and its operations consist of the purchase and regulated retail sale of electricity and the provision of distribution and transmission services in central Maryland, including the City of Baltimore, and the purchase and regulated retail sale of natural gas and the provision of distribution service in central Maryland, including the City of Baltimore. This segment is discussed in further detail in ITEM 1. BUSINESS—BGE of this Form 10-K.

~~Executive Overview~~

~~A discussion of items pertinent to BGE’s executive overview is set forth under EXELON CORPORATION — Executive Overview of this Form 10-K.~~

~~Results of Operations~~

~~Year Ended December 31, 2017 Compared to Year Ended December 31, 2016 and Year Ended December 31, 2016 Compared to Year Ended December 31, 2015~~

A discussion of BGE’s results of operations for 2017 compared to 2016 and for 2016 compared to 2015 is set forth under Results of Operations—BGE in EXELON CORPORATION — Results of Operations of this Form 10-K.

Liquidity and Capital Resources

~~BGE’s business is capital intensive~~All results included throughout the liquidity and ~~requires considerable capital resources. BGE’s~~ capital resources section are ~~primarily~~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 ~~extent necessary, external financing, including~~Utility Registrants operate in rate-regulated environments in which the ~~issuance~~amount of ~~long-term debt~~new investment recovery may be delayed or ~~commercial paper. BGE’s~~limited and where such recovery takes place over an extended period of time. Each Registrant’s access to external financing aton reasonable terms ~~is dependent~~depends on its credit ratings and ~~general~~current overall capital market business conditions, ~~as well as~~including that of the utility industry in general. If these conditions deteriorate to ~~where BGE~~the extent that the Registrants no longer ~~has~~have access to the capital markets at reasonable terms, ~~BGE has~~the Registrants have access to ~~a revolving~~ credit ~~facility. At December 31, 2017, BGE had access to a revolving credit facility~~facilities with aggregate bank commitments of ~~$600 million.~~

$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 ~~EXELON CORPORATION — Liquidity~~the “Credit Matters and ~~Capital Resources~~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 1316 — 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 ~~this Form 10-K~~Cash Flows for ~~further discussion.~~

~~Capital resources are used primarily to fund BGE’s capital requirements, including construction, retirement~~all periods presented. The Exelon Consolidated Statement of ~~debt,~~Cash Flows for the ~~payment~~year ended December 31, 2022 includes one month of ~~dividends and contributions to Exelon’s pension plans. Additionally, BGE operates~~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 ~~a rate-regulated environment~~cash flows as shown in ~~which~~ the ~~amount of new investment recovery may be limited and where such recovery takes place over an extended period of time.~~tables unless otherwise noted below.

Cash Flows from Operating Activities

~~A discussion of items pertinent to BGE’s~~The Utility Registrants' cash flows from operating activities ~~is set forth under Cash Flows~~primarily result from ~~Operating Activities~~the transmission and distribution of electricity and, in ~~EXELON CORPORATION — Liquidity~~the case of PECO, BGE, and ~~Capital Resources~~DPL, gas distribution services. The Utility Registrants' distribution services are provided to an established and diverse base of ~~this Form 10-K.~~

~~Cash Flows from Investing Activities~~

~~A discussion of items pertinent to BGE’s~~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 ~~investing activities~~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 ~~set forth under “Cash Flows~~established through a competitive bidding process. ComEd will provide net payments to, or collect net payments from, ~~Investing Activities” in EXELON CORPORATION — Liquidity~~customers for the difference between customer credits issued and ~~Capital Resources of this Form 10-K.~~

~~Cash Flows~~the credit to be received from ~~Financing Activities~~

~~A discussion of items pertinent to BGE’s~~the participating nuclear-powered generating facilities. ComEd’s cash flows ~~from financing activities is set forth under “Cash Flows from Financing Activities” in EXELON CORPORATION — Liquidity~~are affected by the establishment of CMC prices and ~~Capital Resources~~the timing of ~~this Form 10-K.~~

~~Credit Matters~~

~~A discussion of credit matters pertinent to BGE is set forth under Credit Matters in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.~~

~~Contractual Obligations and Off-Balance Sheet Arrangements~~

A discussion of BGE’s contractual obligations, commercial commitments and off-balance sheet arrangements is set forth under Contractual Obligations and Off-Balance Sheet Arrangements in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.

~~Critical Accounting Policies and Estimates~~

~~See All Registrants — Critical Accounting Policies and Estimates above for a discussion of BGE’s critical accounting policies and estimates.~~

~~New Accounting Pronouncements~~recovering costs through the CMC regulatory asset.

See Note 13 — ~~Significant Accounting Policies~~Regulatory Matters and Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information ~~regarding new accounting pronouncements.~~on regulatory and legal proceedings and proposed legislation.

Table of Contents



~~ITEM 7A.~~	~~QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK~~

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:

~~BGE~~


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

~~BGE~~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 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.



~~ITEM 7.~~	~~MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

~~PHI~~

~~General~~

~~PHI has three reportable segments~~2021, respectively. Also included within the changes is energy efficiency and demand response programs spend for BGE, Pepco, DPL, and ~~ACE. Its operations consist~~ACE of ~~the purchase~~$113 million, $71 million, $28 million, and regulated retail sale of electricity and the provision of distribution and transmission services, and to a lesser extent, the purchase and regulated retail sale and supply of natural gas in Delaware. This segment is discussed in further detail in ITEM 1. BUSINESS — PHI of this Form 10-K.

~~Executive Overview~~

~~A discussion of items pertinent to PHI’s executive overview is set forth under EXELON CORPORATION — Executive Overview of this Form 10-K.~~

~~Results of Operations~~

Successor Period Year Ended December 31, 2017, Successor Period of March 24, 2016 to December 31, 2016 and Predecessor Period of January 1, 2016 to March 23, 2016, Predecessor Period Year Ended December 31, 2015

~~A discussion of PHI’s results of operations~~$11 million for ~~2017 compared to 2016, March 24, 2016 to December 31, 2016 and January 1, 2016 to March 23, 2016, and~~ the year ended December 31, ~~2015~~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 ~~set forth under Results~~dependent upon the normal course of ~~Operations—PHI~~operations for all Registrants. For ComEd, it is also

Table of Contents

~~Liquidity and Capital Resources~~

~~PHI’s business~~a receivable from nuclear-powered generating facilities, which is ~~capital intensive and requires considerable capital resources. PHI’s capital resources are primarily provided by internally generated~~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 ~~extent necessary, external financing, including~~timing of cash expenditures for capital projects. See the ~~issuance of long-term debt or commercial paper, borrowings from~~"Credit Matters and Cash Requirements" section below for additional information on projected capital expenditure spending for the ~~Exelon money pool or capital contributions from Exelon. PHI’s access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that~~Utility Registrants. See Note 2 — Discontinued Operations of the ~~utility industry~~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 ~~general.~~April 2020. Generation received $400 million of additional funding related to the DPP in February and March of 2021.

~~See EXELON CORPORATION — Liquidity~~•Proceeds from sales of assets and ~~Capital Resources~~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)

Table of Contents

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 1316 — 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 ~~this Form 10-K~~$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 ~~further discussion.~~additional information for the Registrants.

~~Capital resources~~•Changes inintercompany money pool are ~~used primarily~~driven by short-term borrowing needs. Refer below for more information regarding the intercompany money pool.

•Issuance of common stock relates to ~~fund PHI’s capital requirements, including construction, retirement~~the August 2022 underwritten public offering of debt, the payment of dividends and contributions to Exelon’s pension plans. Additionally, PHI operates in a rate-regulated environment in which the amount of new investment recovery may be limited and where such recovery takes place over an extended period of time.

~~Cash Flows from Operating Activities~~

A discussion of items pertinent to PHI’s cash flows from operating activities is set forth under Cash Flows from Operating Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.

~~Cash Flows from Investing Activities~~

A discussion of items pertinent to PHI’s cash flows from investing activities is set forth under “Cash Flows from Investing Activities” in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.

~~Cash Flows from Financing Activities~~

A discussion of items pertinent to PHI’s cash flows from financing activities is set forth under “Cash Flows from Financing Activities” in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.

~~Credit Matters~~

~~A discussion of credit matters pertinent to PHI is set forth under Credit Matters in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.~~

~~Contractual Obligations and Off-Balance Sheet Arrangements~~

A discussion of PHI’s contractual obligations, commercial commitments and off-balance sheet arrangements is set forth under Contractual Obligations and Off-Balance Sheet Arrangements in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.

~~Critical Accounting Policies and Estimates~~

~~See All Registrants — Critical Accounting Policies and Estimates above for a discussion of PHI’s critical accounting policies and estimates.~~

~~New Accounting Pronouncements~~

Exelon common stock. See Note 119 — ~~Significant Accounting Policies~~Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for ~~information regarding new accounting pronouncements.~~additional information.



~~ITEM 7A.~~	~~QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK~~

~~PHI~~

~~PHI is exposed~~•Exelon’s ability to ~~market risks associated with commodity price, credit and interest rates. These risks are described above under Quantitative and Qualitative Disclosures about Market Risk — Exelon.~~



~~ITEM 7.~~	~~MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

~~Pepco~~

~~General~~

~~Pepco operates~~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 a single business segment and its operations consist of the purchase and regulated retail sale of electricity and the provision of distribution and transmission services to retail customers in District of Columbia and major portions of Prince George’s County and Montgomery County in Maryland. This segment is discussed in further detail in ITEM 1. BUSINESS — Pepco of this Form 10-K.

~~Executive Overview~~

~~A discussion of items pertinent to Pepco’s executive overview is set forth under EXELON CORPORATION — Executive Overview of this Form 10-K.~~

~~Results of Operations~~

~~Year Ended December 31, 2017 Compared to Year Ended December 31, 2016 and Year Ended December 31, 2016 Compared to Year Ended December 31, 2015~~

~~A discussion of Pepco’s~~turn depend on their results of operations ~~for 2017 compared to 2016~~ and ~~for 2016 compared to 2015 is set forth under Results of Operations—Pepco in EXELON CORPORATION — Results of Operations of this Form 10-K.~~

~~Liquidity and Capital Resources~~

~~Pepco’s business is capital intensive and requires considerable capital resources. Pepco’s capital resources are primarily provided by internally generated~~ cash flows ~~from operations~~ and 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 ~~extent necessary, external~~separation.

•Other financing ~~including~~activities primarily consists of debt issuance costs. See debt issuances table below for additional information on the ~~issuance~~Registrants’ debt issuances.

Table of ~~long-term debt, commercial paper or credit facility borrowings. Pepco’s access to external financing at reasonable terms is dependent on its credit ratings~~Contents

Debt Issuances and ~~general business conditions, as well as that of the utility industry in general. At December 31, 2017, Pepco had access to a revolving credit facility with aggregate bank commitments of $300 million.~~Redemptions

See ~~EXELON CORPORATION — Liquidity and Capital Resources and~~ Note 1316 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of ~~this Form 10-K~~the Registrants’ long-term debt. Debt activity for ~~further discussion.~~2022 and 2021 by Registrant was as follows:

~~Capital resources~~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

Procurement of software licenses

Exelon

Long-Term Software License Agreements

3.70%

August 9, 2025

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

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.

__________

Table of Contents

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 ~~used primarily~~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 ~~fund Pepco’s capital requirements, including construction, retirement~~the Notes, except that their issuance was registered under the Securities Act.

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

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

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

Exelon

Long-Term Software License Agreement

2.30%

December 1, 2025

Exelon

Long-Term Software License Agreement

3.70%

August 9, 2025

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 ~~contributions to Exelon’s pension plans. Additionally, Pepco operates in rate-regulated environments in which~~amounts of the ~~amount~~third-party debt obligations. The loan agreements were entered into as part of ~~new investment recovery may be limited and where such recovery takes place over an extended period of time.~~

~~Cash Flows from Operating Activities~~

A discussion of items pertinent to Pepco’s cash flows from operating activities is set forth under Cash Flows from Operating Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.

~~Cash Flows from Investing Activities~~

A discussion of items pertinent to Pepco’s cash flows from investing activities is set forth under Cash Flows from Investing Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.

~~Cash Flows from Financing Activities~~

A discussion of items pertinent to Pepco’s cash flows from financing activities is set forth under Cash Flows from Financing Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.

~~Credit Matters~~

~~A discussion of credit matters pertinent to Pepco is set forth under Credit Matters in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.~~

~~Contractual Obligations and Off-Balance Sheet Arrangements~~

A discussion of Pepco’s contractual obligations, commercial commitments and off-balance sheet arrangements is set forth under Contractual Obligations and Off-Balance Sheet Arrangements in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.

~~Critical Accounting Policies and Estimates~~

~~See All Registrants — Critical Accounting Policies and Estimates above for a discussion of Pepco’s critical accounting policies and estimates.~~

~~New Accounting Pronouncements~~

the 2012 Constellation merger. See Note ~~1 — Significant Accounting Policies~~16

Table of ~~the Combined Notes to Consolidated Financial Statements for information regarding new accounting pronouncements.~~

Contents



~~ITEM 7A.~~	~~QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK~~

~~Pepco~~

~~Pepco is exposed to market risks associated with credit and interest rates. These risks are described above under Quantitative and Qualitative Disclosures about Market Risk— Exelon.~~



~~ITEM 7.~~	~~MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

~~DPL~~

~~General~~

DPL operates in a single business segment and its operations consist of the purchase and regulated retail sale of electricity and the provision of distribution and transmission services in portions of Maryland and Delaware, and the purchase and regulated retail sale and supply of natural gas in New Castle County, Delaware. This segment is discussed in further detail in ITEM 1. BUSINESS — DPL of this Form 10-K.

~~Executive Overview~~

~~A discussion of items pertinent to DPL’s executive overview is set forth under EXELON CORPORATION — Executive Overview of this Form 10-K.~~

~~Results of Operations~~

~~Year Ended December 31, 2017 Compared to Year Ended December 31, 2016 and Year Ended December 31, 2016 Compared to Year Ended December 31, 2015~~

A discussion of DPL’s results of operations for 2017 compared to 2016 and for 2016 compared to 2015 is set forth under Results of Operations—DPL in EXELON CORPORATION — Results of Operations of this Form 10-K.

~~Liquidity and Capital Resources~~

DPL’s business is capital intensive and requires considerable capital resources. DPL’s capital resources are primarily provided by internally generated cash flows from operations and, to the extent necessary, external financing, including the issuance of long-term debt or commercial paper. DPL’s access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of the utility industry in general. If these conditions deteriorate to where DPL no longer has access to the capital markets at reasonable terms, DPL has access to a revolving credit facility. At December 31, 2017, DPL had access to a revolving credit facility with aggregate bank commitments of $300 million.

~~See EXELON CORPORATION — Liquidity and Capital Resources and Note 13~~ — 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

Exelon

Long-Term Software License Agreements

3.62%

December 1, 2025

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

ACE

Transition Bonds

5.55%

October 20, 2021

Dividends

Quarterly dividends declared by the Exelon Board of ~~this Form 10-K~~Directors during the year ended December 31, 2022 and for ~~further discussion.~~the first quarter of 2023 were as follows:

~~Capital resources are used primarily to~~

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 ~~DPL’s~~liquidity needs for capital ~~requirements, including construction, retirement of debt, the payment of dividends~~expenditures, working capital, energy hedging, and contributions to Exelon’s pension plans. Additionally, DPL operates in a rate-regulated environment in which the amount of new investment recovery may be limited and where such recovery takes place over an extended period of time.

~~Cash Flows from Operating Activities~~

~~A discussion of items pertinent to DPL’s~~other financial commitments through cash flows from ~~operating activities is set forth under Cash Flows from Operating Activities~~continuing operations, public debt offerings, commercial paper markets, and large, diversified credit facilities. The credit facilities include $4.0 billion in ~~EXELON CORPORATION — Liquidity~~aggregate total commitments of which $2.1 billion was available to support additional commercial paper as of December 31, 2022, and ~~Capital Resources~~ of ~~this Form 10-K.~~

~~Cash Flows from Investing Activities~~

A discussion of items pertinent to DPL’s cash flows from investing activities is set forth under Cash Flows from Investing Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.

~~Cash Flows from Financing Activities~~

A discussion of items pertinent to DPL’s cash flows from financing activities is set forth under Cash Flows from Financing Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.

~~Credit Matters~~

~~A discussion of credit matters pertinent to DPL is set forth under Credit Matters in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.~~

~~Contractual Obligations and Off-Balance Sheet Arrangements~~

A discussion of DPL’s contractual obligations, commercial commitments and off-balance sheet arrangements is set forth under Contractual Obligations and Off-Balance Sheet Arrangements in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.

~~Critical Accounting Policies and Estimates~~

~~See All Registrants — Critical Accounting Policies and Estimates above for a discussion of DPL’s critical accounting policies and estimates.~~

~~New Accounting Pronouncements~~

~~See Note 1 — Significant Accounting Policies~~which no financial institution has more than 6% of the ~~Combined Notes to Consolidated Financial Statements~~aggregate commitments for ~~information regarding new accounting pronouncements.~~



~~ITEM 7A.~~	~~QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK~~

~~DPL~~

~~DPL is exposed to market risks associated with commodity price, credit and interest rates. These risks are described above under Quantitative and Qualitative Disclosures about Market Risk—Exelon.~~



~~ITEM 7.~~	~~MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

~~ACE~~

~~General~~

~~ACE operates in a single business segment and its operations consist of~~ the ~~purchase and regulated retail sale of electricity~~Registrants. On February 1, 2022, Exelon Corporate and the ~~provision of distribution and transmission services to retail customers in portions of southern New Jersey. This segment is discussed in further detail in ITEM 1. BUSINESS — ACE of this Form 10-K.~~

~~Executive Overview~~

~~A discussion of items pertinent to ACE’s executive overview is set forth under EXELON CORPORATION — Executive Overview of this Form 10-K.~~

~~Results of Operations~~

~~Year Ended December 31, 2017 Compared to Year Ended December 31, 2016 and Year Ended December 31, 2016 Compared to Year Ended December 31, 2015~~

A discussion of ACE’s results of operations for 2017 compared to 2016 and for 2016 compared to 2015 is set forth under Results of Operations—ACE in EXELON CORPORATION — Results of Operations of this Form 10-K.

~~Liquidity and Capital Resources~~

ACE’s business is capital intensive and requires considerable capital resources. ACE’s capital resources are primarily provided by internally generated cash flows from operations and, to the extent necessary, external financing, including the issuance of long-term debt, commercial paper or credit facility borrowings. ACE’s access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of the utility industry in general. At December 31, 2017, ACE had access toUtility Registrants each entered into a new 5-year revolving credit facility ~~with aggregate bank commitments of $300 million.~~

that replaced its existing syndicated revolving credit facility. See ~~EXELON CORPORATION — Liquidity and Capital Resources and~~ Note 1316 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements ~~of this Form 10-K~~ for ~~further discussion.~~

~~Capital resources are used primarily~~additional information. The Registrants had access to the commercial paper markets and had availability under their revolving credit facilities during 2022 to fund ~~ACE’s~~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 ~~requirements, including construction, retirement~~raising, and merger activity. See PART I, ITEM 1A. RISK FACTORS for additional information regarding the effects of ~~debt,~~uncertainty in the capital and contributions to Exelon’s pension plans. Additionally, ACE operates in rate-regulated environments in which the amount of new investment recovery may be limited and where such recovery takes place over an extended period of time.credit markets.

~~Cash Flows from Operating Activities~~

~~A discussion of items pertinent to ACE’s~~The Registrants believe their cash ~~flows~~flow from operating activities, ~~is set forth~~access to credit markets, and their credit facilities provide sufficient liquidity to support the estimated future cash requirements discussed below.

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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 ~~Cash Flows from Operating Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.~~

~~Cash Flows from Investing Activities~~

A discussion of items pertinent to ACE’s cash flows from investing activities is set forth under Cash Flows from Investing Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.

~~Cash Flows from Financing Activities~~

A discussion of items pertinent to ACE’s cash flows from financing activities is set forth under Cash Flows from Financing Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.

~~Credit Matters~~

~~A discussion of~~a $1.15 billion term loan credit ~~matters pertinent to ACE is set forth under Credit Matters in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.~~

~~Contractual Obligations and Off-Balance Sheet Arrangements~~

A discussion of ACE’s contractual obligations, commercial commitments and off-balance sheet arrangements is set forth under Contractual Obligations and Off-Balance Sheet Arrangements in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.

~~Critical Accounting Policies and Estimates~~

~~See All Registrants — Critical Accounting Policies and Estimates above for a discussion of ACE’s critical accounting policies and estimates.~~

~~New Accounting Pronouncements~~

facility. See Note 119 — ~~Significant Accounting Policies~~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.

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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.


	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	—		—		—

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:

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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.

(d)Represents commitments to purchase natural gas and related transportation, storage capacity, and services.

(f)These amounts represent Exelon’s expected contributions to its qualified pension plans. Qualified pension contributions for years after 2028 are not included.

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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.

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.

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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

__________

(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

__________

(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.

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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

__________

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

__________

(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.

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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

__________

(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.

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.

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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	%	—	%

__________

Security Ratings

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.

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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.

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(f)On July 13, 2022, ACE received approval from the NJBPU for $700 million in new long-term debt financing authority with an effective date of July 20, 2022.


ITEM 7A.			QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

~~ACE~~The Registrants hold commodity and financial instruments that are exposed to the following market risks:

~~ACE~~•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 ~~risks~~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

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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		Total Fair Value
Prices based on model or other valuation methods (Level 3)	$	(5)	$	(8)	$	(11)	$	(12)	$	(13)	$	(35)	$	(84)

_________

(a)Represents ComEd's net liabilities associated with ~~credit and interest rates. These risks are described above under Quantitative and Qualitative Disclosures about Market Risk— Exelon.~~

the floating-to-fixed energy swap contracts with unaffiliated suppliers.

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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, ~~2017.~~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, ~~2017,~~2022, Exelon’s internal control over financial reporting was effective.

The effectiveness of Exelon’s internal control over financial reporting as of December 31, ~~2017,~~2022, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.

February 14, 2023

~~February 9, 2018~~

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Management’s Report on Internal Control Over Financial Reporting

The management of Exelon Generation Company, LLC (Generation) is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

Generation’s management conducted an assessment of the effectiveness of Generation’s internal control over financial reporting as of December 31, 2017. In making this assessment, management used the criteria in ~~Internal Control—Integrated Framework (2013)~~ issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, Generation’s management concluded that, as of December 31, 2017, Generation’s internal control over financial reporting was effective.

The effectiveness of Generation’s internal control over financial reporting as of December 31, 2017, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.

~~February 9, 2018~~

~~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.

ComEd’s management conducted an assessment of the effectiveness of ComEd’s internal control over financial reporting as of December 31, ~~2017.~~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, ~~2017,~~2022, ComEd’s internal control over financial reporting was effective.

The effectiveness of ComEd’s internal control over financial reporting as of December 31, 2017, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.

February ~~9, 2018~~14, 2023

Table of Contents

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.

PECO’s management conducted an assessment of the effectiveness of PECO’s internal control over financial reporting as of December 31, ~~2017.~~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, ~~2017,~~2022, PECO’s internal control over financial reporting was effective.

The effectiveness of PECO’s internal control over financial reporting as of December 31, 2017, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.

February ~~9, 2018~~14, 2023

Table of Contents

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.

BGE’s management conducted an assessment of the effectiveness of BGE’s internal control over financial reporting as of December 31, ~~2017.~~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, ~~2017,~~2022, BGE’s internal control over financial reporting was effective.

The effectiveness of BGE’s internal control over financial reporting as of December 31, 2017, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.

February ~~9, 2018~~14, 2023

Table of Contents

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.

PHI’s management conducted an assessment of the effectiveness of PHI’s internal control over financial reporting as of December 31, ~~2017.~~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, ~~2017,~~2022, PHI’s internal control over financial reporting was effective.

The effectiveness of PHI’s internal control over financial reporting as of December 31, 2017, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.

February ~~9, 2018~~14, 2023

Table of Contents

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.

Pepco’s management conducted an assessment of the effectiveness of Pepco’s internal control over financial reporting as of December 31, ~~2017.~~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, ~~2017,~~2022, Pepco’s internal control over financial reporting was effective.

February ~~9, 2018~~14, 2023

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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.

DPL’s management conducted an assessment of the effectiveness of DPL’s internal control over financial reporting as of December 31, ~~2017.~~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, ~~2017,~~2022, DPL’s internal control over financial reporting was effective.

February ~~9, 2018~~14, 2023

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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.

ACE’s management conducted an assessment of the effectiveness of ACE’s internal control over financial reporting as of December 31, ~~2017.~~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, ~~2017,~~2022, ACE’s internal control over financial reporting was effective.

February ~~9, 2018~~14, 2023

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Report of Independent Registered Public Accounting Firm

To theBoard 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)~~(2)~~(1)(ii), ~~of Exelon Corporation and its subsidiaries~~ (collectively referred to as the “consolidated financial statements”).We also have audited the Company's internal control over financial reporting as of December 31, ~~2017,~~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 consolidatedfinancial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, ~~2017~~2022 and ~~2016~~, 2021, and the results of ~~their~~its operations and ~~their~~its cash flows for each of the three years in the period ended December 31, ~~2017~~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, ~~2017,~~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 consolidatedfinancial 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")~~(PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidatedfinancial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audits of the consolidatedfinancial statements included performing procedures to assess the risks of material misstatement of the consolidatedfinancial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidatedfinancial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidatedfinancial statements. 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.

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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 ~~9, 2018~~14, 2023

We have served as the Company’s auditor since 2000.

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Report of Independent Registered Public Accounting Firm

To theBoard of Directors and ~~Member~~Shareholders of ~~Exelon Generation~~Commonwealth Edison Company ~~LLC~~

~~Opinions~~Opinion on the Financial Statements ~~and Internal Control over Financial Reporting~~

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)~~(1)~~(2)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(2)~~, of Exelon Generation Company, LLC and its subsidiaries (collectively referred to as the “consolidated financial statements”).~~ ~~We also have audited the Company's internal control over financial reporting as of December 31, 2017, 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 consolidatedfinancial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016~~, ~~and the results of theiroperations and their~~cash flows for each of the three years in the period ended December 31, 2017 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, 2017, 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 consolidatedfinancial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) ("PCAOB") and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

~~We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidatedfinancial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.~~

~~Our audits of the consolidatedfinancial 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 consolidatedfinancial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidatedfinancial statements. 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~~

~~/s/ PricewaterhouseCoopers LLP~~

~~Baltimore, Maryland~~

~~February 9, 2018~~

~~We have served as the Company’s auditor since 2001.~~

~~Report of Independent Registered Public Accounting Firm~~

~~To theBoard of Directors and Shareholders of Commonwealth Edison Company~~

~~Opinions on the Financial Statements and Internal Control over Financial Reporting~~

We have audited the consolidated financial statements, including the related notes, as listed in the index appearing under Item 15(a)(1), and the financial statement schedule listed in the index appearing under Item 15(a)(2), of Commonwealth Edison Company and its subsidiaries (collectively referred to as the “consolidated financial statements”). ~~We also have audited the Company's internal control over financial reporting as of December 31, 2017, based on criteria established in~~ ~~Internal Control - Integrated Framework(2013)issued by the Committee of Sponsoring Organizations of the Treadway Commission (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 consolidatedfinancial 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.

~~Definition and Limitations of Internal Control over Financial Reporting~~

~~/s/ PricewaterhouseCoopers LLP~~

~~Chicago, Illinois~~

~~February 9, 2018~~

~~We have served as the Company’s auditor since 2000.~~

~~Report of Independent Registered Public Accounting Firm~~

~~To theBoard of Directors and Shareholder of PECO Energy Company~~

~~Opinions on the Financial Statements and Internal Control over Financial Reporting~~

We have audited the consolidated financial statements, including the related notes, as listed in the index appearing under Item 15(a)(1), and the financial statement schedule listed in the index appearing under Item 15(a)(2), of PECO Energy Company and its subsidiaries (collectively referred to as the “consolidated financial statements”).~~We also have audited the Company's internal control over financial reporting as of December 31, 2017, based on criteria established in~~ ~~Internal Control - Integrated Framework(2013)issued by the Committee of Sponsoring Organizations of the Treadway Commission (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 consolidatedfinancial 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.

~~Definition and Limitations of Internal Control over Financial Reporting~~

~~/s/ PricewaterhouseCoopers LLP~~

~~Philadelphia, Pennsylvania~~

~~February 9, 2018~~

~~We have served as the Company’s auditor since 1932.~~

~~Report of Independent Registered Public Accounting Firm~~

~~To theBoard of Directors and Shareholder of Baltimore Gas and Electric Company~~

~~Opinions on the Financial Statements and Internal Control over Financial Reporting~~

We have audited the consolidated financial statements, including the related notes, as listed in the index appearing under Item 15(a)(1), and the financial statement schedule listed in the index appearing under Item 15(a)(2), of Baltimore Gas and Electric Company and its subsidiaries (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2017, based on criteria established in ~~Internal Control - Integrated Framework(2013)issued by the Committee of Sponsoring Organizations of the Treadway Commission (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 consolidatedfinancial 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.

~~Definition and Limitations of Internal Control over Financial Reporting~~

~~/s/ PricewaterhouseCoopers LLP~~

~~Baltimore, Maryland~~

~~February 9, 2018~~

~~We have served as the Company’s auditor since at least 1993. We have not determined the specific year we began serving as auditor of the Company.~~

~~Report of Independent Registered Public Accounting Firm~~

~~To theBoard of Directors and Member of Pepco Holdings LLC~~

~~Opinions on the Financial Statements and Internal Control over Financial Reporting~~

We have audited the consolidated financial statements, including the related notes, as listed in the index appearing under Item 15(a)(1), and the financial statement schedule listed in the index appearing under Item 15(a)(2), of Pepco Holdings LLC and its subsidiaries (Successor) (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2017, 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 consolidatedfinancial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016~~, ~~and the results of theiroperations and their~~cash flows for the year ended December 31, 2017, for the period from March 24, 2016 to December 31, 2016 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, 2017, 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 consolidatedfinancial 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.

~~Definition and Limitations of Internal Control over Financial Reporting~~

~~/s/ PricewaterhouseCoopers LLP~~

~~Washington, D.C.~~

~~February 9, 2018~~

~~We have served as the Company’s auditor since 2001.~~

~~Report of Independent Registered Public Accounting Firm~~

~~To the Board of Directors and Member of Pepco Holdings LLC~~

In our opinion, the financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the results of operations and the cash flows of Pepco Holdings LLC and its subsidiaries (formerly Pepco Holdings, Inc.) (Predecessor) for the period January 1, 2016 to March 23, 2016 and for the year ended December 31, 2015 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related financial statements. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

~~As discussed in Note 1 to the financial statements, the Company changed the manner in which it accounts for interest on uncertain tax positions in 2016.~~

~~/s/ PricewaterhouseCoopers LLP~~

~~Washington, D.C.~~

~~February 13, 2017~~

~~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, as listed in the index appearing under Item 15(a)(1), and the financial statement schedule listed in the index appearing under Item 15(a)(2), of Potomac Electric Power Company (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company~~as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017in 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 audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.

~~Our audits included performing procedures to assess the risks of material misstatement of 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 thefinancial statements. We believe that our audits provide a reasonable basis for our opinion.~~

~~/s/ PricewaterhouseCoopers LLP~~

~~Washington, D.C.~~

~~February 9, 2018~~

~~We have served as the Company's auditor since at least 1993. We have not determined 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, as listed in the index appearing under Item 15(a)(1), and the financial statement schedule listed in the index appearing under Item 15(a)(2), of Delmarva Power & Light Company (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company~~as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017in conformity with accounting principles generally accepted in the United States of America.~~

~~Basis for Opinion~~

~~/s/ PricewaterhouseCoopers LLP~~

~~Washington, D.C.~~

~~February 9, 2018~~

~~We have served as the Company's auditor since at least 1993. We have not determined 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, as listed in the index appearing under Item 15(a)(1), and the financial statement schedule listed in the index appearing under Item 15(a)(2), of Atlantic City Electric Company and its subsidiary (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Companyas of December 31, ~~2017~~2022 and ~~2016,~~2021, and the results of ~~their~~its operations and ~~their~~its cash flows for each of the three years in the period ended December 31, ~~2017~~2022 in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These consolidatedfinancial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) ~~(“PCAOB”)~~(PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits of these consolidatedfinancial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the ~~audit~~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 consolidatedfinancial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidatedfinancial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidatedfinancial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matters

Accounting for the Effects of Rate Regulation

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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.

/s/ PricewaterhouseCoopers LLP

~~Washington, D.C.~~Chicago, Illinois

February ~~9, 2018~~14, 2023

We have served as the Company's auditor since 2000.

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Report of Independent Registered Public Accounting Firm

To theBoard 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

Accounting for the Effects of Rate Regulation

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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.

/s/ PricewaterhouseCoopers LLP

Philadelphia, Pennsylvania

February 14, 2023

We have served as the Company's auditor since 1932.

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Report of Independent Registered Public Accounting Firm

To theBoard 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,

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respectively, in future rates. As of December 31, 2022, there were $704 million of regulatory assets and $863 million of regulatory liabilities.

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.

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Report of Independent Registered Public Accounting Firm

To theBoard of Directors and Member of Pepco Holdings LLC

Opinion on the Financial Statements

We have audited the consolidated financial statements, including the related notes, of Pepco Holdings LLC and its subsidiaries (the “Company”) as listed in the index appearing under Item 15(a)(5)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(5)(ii) (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the 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.

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

Accounting for the Effects of Rate Regulation

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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.

/s/ PricewaterhouseCoopers LLP

Philadelphia, Pennsylvania

February 14, 2023

We have served as the Company's auditor since 2001.

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Report of Independent Registered Public Accounting Firm

Tothe Board of Directors and Shareholder of Potomac Electric Power Company

Opinion on the Financial Statements

We have audited the financial statements, including the related notes, 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

Critical Audit Matters

Accounting for the Effects of Rate Regulation

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respectively, in future rates. As of December 31, 2022, there were $672 million of regulatory assets and $461 million of regulatory liabilities.

/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.

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Report of Independent Registered Public Accounting Firm

Tothe Board of Directors and Shareholder of Delmarva Power & Light Company

Opinion on the Financial Statements

We have audited the financial statements, including the related notes, of Delmarva Power & Light Company (the “Company”) as listed in the index appearing under Item 15(a)(7)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(7)(ii) (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of 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

Critical Audit Matters

Accounting for the Effects of Rate Regulation

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respectively, in future rates. As of December 31, 2022, there were $282 million of regulatory assets and $424 million of regulatory liabilities.

/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.

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Report of Independent Registered Public Accounting Firm

Tothe Board of Directors and Shareholder of Atlantic City Electric Company

Opinion on the Financial Statements

We have audited the consolidated financial statements, including the related notes, of Atlantic City Electric Company and its 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.

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

Accounting for the Effects of Rate Regulation

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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.

/s/ PricewaterhouseCoopers LLP

Philadelphia, Pennsylvania

February 14, 2023

We have served as the Company's auditor since 1998.

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Exelon Corporation and Subsidiary Companies

Consolidated Statements of Operations and Comprehensive Income


	For the Years Ended December 31,										For the Years Ended December 31,
(In millions, except per share data)	2017			2016			2015			(In millions, except per share data)	2022		2021		2020
Operating revenues										Operating revenues
Competitive businesses revenues	$	17,360		$	16,324		$	18,395
Rate-regulated utility revenues	16,171			15,036			11,052
Electric operating revenues										Electric operating revenues	$	16,899	$	16,245	$	15,236
Natural gas operating revenues										Natural gas operating revenues	2,018		1,522		1,421
Revenues from alternative revenue programs										Revenues from alternative revenue programs	161		171		6

Total operating revenues	33,531			31,360			29,447			Total operating revenues	19,078		17,938		16,663
Operating expenses										Operating expenses
Competitive businesses purchased power and fuel	9,668			8,817			10,007
Rate-regulated utility purchased power and fuel	4,367			3,823			3,077
Purchased power										Purchased power	5,380		4,703		4,086
Purchased fuel										Purchased fuel	834		504		426
Purchased power and fuel from affiliates										Purchased power and fuel from affiliates	159		1,178		1,209
Operating and maintenance	10,126			10,048			8,322			Operating and maintenance	4,673		4,547		4,641
Depreciation and amortization	3,828			3,936			2,450			Depreciation and amortization	3,325		3,033		2,891
Taxes other than income	1,731			1,576			1,200
Taxes other than income taxes										Taxes other than income taxes	1,390		1,291		1,232
Total operating expenses	29,720			28,200			25,056			Total operating expenses	15,761		15,256		14,485
Gain (Loss) on sales of assets	3			(48		)	18
Bargain purchase gain	233			—			—
Gain on deconsolidation of business	213			—			—

(Loss) Gain on sales of assets and businesses										(Loss) Gain on sales of assets and businesses	(2)		—		13

Operating income	4,260			3,112			4,409			Operating income	3,315		2,682		2,191
Other income and (deductions)										Other income and (deductions)
Interest expense, net	(1,524		)	(1,495		)	(992		)	Interest expense, net	(1,422)		(1,264)		(1,282)
Interest expense to affiliates	(36		)	(41		)	(41		)	Interest expense to affiliates	(25)		(25)		(25)
Other, net	1,056			413			(46		)	Other, net	535		261		208
Total other income and (deductions)	(504		)	(1,123		)	(1,079		)	Total other income and (deductions)	(912)		(1,028)		(1,099)
Income before income taxes	3,756			1,989			3,330
Income from continuing operations before income taxes										Income from continuing operations before income taxes	2,403		1,654		1,092
Income taxes	(125		)	761			1,073			Income taxes	349		38		(7)
Equity in losses of unconsolidated affiliates	(32		)	(24		)	(7		)
Net income	3,849			1,204			2,250
Net income (loss) attributable to noncontrolling interests and preference stock dividends	79			70			(19		)

Net income from continuing operations after income taxes										Net income from continuing operations after income taxes	2,054		1,616		1,099
Net income from discontinued operations after income taxes (Note 2)										Net income from discontinued operations after income taxes (Note 2)	117		213		855
Net Income										Net Income	2,171		1,829		1,954
Net income (loss) attributable to noncontrolling interests										Net income (loss) attributable to noncontrolling interests	1		123		(9)
Net income attributable to common shareholders	$	3,770		$	1,134		$	2,269		Net income attributable to common shareholders	$	2,170	$	1,706	$	1,963

Amounts attributable to common shareholders:										Amounts attributable to common shareholders:
Net income from continuing operations										Net income from continuing operations	2,054		1,616		1,099
Net income from discontinued operations										Net income from discontinued operations	116		90		864
Net income attributable to common shareholders										Net income attributable to common shareholders	$	2,170	$	1,706	$	1,963

Comprehensive income, net of income taxes										Comprehensive income, net of income taxes
Net income	$	3,849		$	1,204		$	2,250		Net income	$	2,171	$	1,829	$	1,954
Other comprehensive income (loss), net of income taxes										Other comprehensive income (loss), net of income taxes
Pension and non-pension postretirement benefit plans:										Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost	(56		)	(48		)	(46		)	Prior service benefit reclassified to periodic benefit cost	(1)		(4)		(40)
Actuarial loss reclassified to periodic benefit cost	197			184			220			Actuarial loss reclassified to periodic benefit cost	42		223		190

Pension and non-pension postretirement benefit plan valuation adjustment	10			(181		)	(99		)	Pension and non-pension postretirement benefit plan valuation adjustment	46		432		(357)
Unrealized gain on cash flow hedges	3			2			9
Unrealized gain on marketable securities	6			1			—
Unrealized gain (loss) on equity investments	4			(4		)	(3		)
Unrealized gain (loss) on foreign currency translation	7			10			(21		)
Unrealized gain (loss) on cash flow hedges										Unrealized gain (loss) on cash flow hedges	2		(1)		(3)

Unrealized gain on foreign currency translation										Unrealized gain on foreign currency translation	—		—		4

Other comprehensive income (loss)	171			(36		)	60			Other comprehensive income (loss)	89		650		(206)
Comprehensive income	4,020			1,168			2,310			Comprehensive income	2,260		2,479		1,748
Comprehensive income (loss) attributable to noncontrolling interests and preference stock dividends	77			70			(19		)
Comprehensive income (loss) attributable to noncontrolling interests										Comprehensive income (loss) attributable to noncontrolling interests	1		123		(9)
Comprehensive income attributable to common shareholders	$	3,943		$	1,098		$	2,329		Comprehensive income attributable to common shareholders	$	2,259	$	2,356	$	1,757

Average shares of common stock outstanding:										Average shares of common stock outstanding:
Basic	947			924			890			Basic	986		979		976
Diluted	949			927			893
Earnings per average common share:
Assumed exercise and/or distributions of stock-based awards										Assumed exercise and/or distributions of stock-based awards	1		1		1
Diluted(a)										Diluted(a)	987		980		977

Earnings per average common share from continuing operations										Earnings per average common share from continuing operations
Basic	$	3.98		$	1.23		$	2.55		Basic	$	2.08	$	1.65	$	1.13
Diluted	$	3.97		$	1.22		$	2.54		Diluted	$	2.08	$	1.65	$	1.13
Dividends per common share	$	1.31		$	1.26		$	1.24

Earnings per average common share from discontinued operations										Earnings per average common share from discontinued operations
Basic										Basic	$	0.12	$	0.09	$	0.88
Diluted										Diluted	$	0.12	$	0.09	$	0.88

__________

(a)The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect 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

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Exelon Corporation and Subsidiary Companies

Consolidated Statements of Cash Flows


	For the Years Ended December 31,
(In millions)	2022		2021		2020
Cash flows from operating activities
Net income	$	2,171	$	1,829	$	1,954
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization	3,533		7,573		6,527
Asset impairments	48		552		591
Gain on sales of assets and businesses	(8)		(201)		(24)


Deferred income taxes and amortization of investment tax credits	255		18		309
Net fair value changes related to derivatives	(53)		(568)		(268)
Net realized and unrealized gains on NDT funds	205		(586)		(461)
Net unrealized losses (gains) on equity investments	16		160		(186)
Other non-cash operating activities	370		(200)		592
Changes in assets and liabilities:
Accounts receivable	(1,222)		(703)		697
Inventories	(121)		(141)		(85)
Accounts payable and accrued expenses	1,318		440		(129)
Option premiums paid, net	(39)		(338)		(139)
Collateral received (posted), net	1,248		(74)		494
Income taxes	(4)		327		140
Regulatory assets and liabilities, net	(1,326)		(634)		(649)
Pension and non-pension postretirement benefit contributions	(616)		(665)		(601)
Other assets and liabilities	(905)		(3,777)		(4,527)
Net cash flows provided by operating activities	4,870		3,012		4,235
Cash flows from investing activities
Capital expenditures	(7,147)		(7,981)		(8,048)

Proceeds from NDT fund sales	488		6,532		3,341
Investment in NDT funds	(516)		(6,673)		(3,464)
Collection of DPP	169		3,902		3,771

Proceeds from sales of assets and businesses	16		877		46


Other investing activities	—		26		18
Net cash flows used in investing activities	(6,990)		(3,317)		(4,336)
Cash flows from financing activities

Changes in short-term borrowings	986		269		161
Proceeds from short-term borrowings with maturities greater than 90 days	1,300		1,380		500
Repayments on short-term borrowings with maturities greater than 90 days	(1,500)		(350)		—
Issuance of long-term debt	6,309		3,481		7,507
Retirement of long-term debt	(2,073)		(1,640)		(6,440)


Issuance of common stock	563		—		—


Dividends paid on common stock	(1,334)		(1,497)		(1,492)
Acquisition of CENG noncontrolling interest	—		(885)		—
Proceeds from employee stock plans	36		80		45
Transfer of cash, restricted cash, and cash equivalents to Constellation	(2,594)		—		—
Other financing activities	(102)		(80)		(136)
Net cash flows provided by financing activities	1,591		758		145
(Decrease) increase in cash, restricted cash, and cash equivalents	(529)		453		44
Cash, restricted cash, and cash equivalents at beginning of period	1,619		1,166		1,122
Cash, restricted cash, and cash equivalents at end of period	$	1,090	$	1,619	$	1,166

Supplemental cash flow information
Increase in capital expenditures not paid	$	36	$	16	$	194
Increase in DPP	348		3,652		4,441
Increase in PP&E related to ARO update	332		642		850

For the Years Ended December 31,
(In millions) 2017 2016 2015
Cash flows from operating activities
Net income $ 3,849
$ 1,204
$ 2,250
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization 5,427
5,576
3,987
Impairment losses of long-lived assets, intangibles and regulatory assets 573
306
36
Gain on deconsolidation of business
(213 ) —
—
(Gain) Loss on sales of assets (3 ) 48
(18 )
Bargain purchase gain (233 ) —
—
Deferred income taxes and amortization of investment tax credits (361 ) 664
752
Net fair value changes related to derivatives 151
24
(367 )
Net realized and unrealized (gains) losses on nuclear decommissioning trust fund investments (616 ) (229 ) 131
Other non-cash operating activities 721
1,333
1,109
Changes in assets and liabilities:
Accounts receivable (426 ) (432 ) 240
Inventories (72 ) 7
4
Accounts payable and accrued expenses (390 ) 771
(121 )
Option premiums received (paid), net 28
(66 ) 58
Collateral (posted) received, net (158 ) 931
347
Income taxes 299
576
97
Pension and non-pension postretirement benefit contributions (405 ) (397 ) (502 )
Deposit with IRS —
(1,250 ) —
Other assets and liabilities (691 ) (621 ) (387 )
Net cash flows provided by operating activities 7,480

8,445

7,616
Cash flows from investing activities
Capital expenditures (7,584 ) (8,553 ) (7,624 )
Proceeds from termination of direct financing lease investment —
360
—
Proceeds from nuclear decommissioning trust fund sales 7,845
9,496
6,895
Investment in nuclear decommissioning trust funds (8,113 ) (9,738 ) (7,147 )
Acquisitions of businesses, net (208 ) (6,934 ) (40 )
Proceeds from sales of long-lived assets 219
61
147
Change in restricted cash (50 ) (42 ) 66
Other investing activities (43 ) (153 ) (119 )
Net cash flows used in investing activities (7,934 )
(15,503 )
(7,822 )
Cash flows from financing activities
Changes in short-term borrowings (261 ) (353 ) 80
Proceeds from short-term borrowings with maturities greater than 90 days 621
240
—
Repayments on short-term borrowings with maturities greater than 90 days (700 ) (462 ) —
Issuance of long-term debt 3,470
4,716
6,709
Retirement of long-term debt (2,490 ) (1,936 ) (2,687 )
Retirement of long-term debt to financing trust (250 ) —
—
Restricted proceeds from issuance of long-term debt (50 ) —
—
Issuance of common stock —
—
1,868
Common stock issued from treasury stock

1,150
—
—
Redemption of preference stock —
(190 ) —
Dividends paid on common stock (1,236 ) (1,166 ) (1,105 )
Proceeds from employee stock plans 150
55
32
Sale of noncontrolling interests 396
372
32
Other financing activities (83 ) (85 ) (99 )
Net cash flows provided by financing activities 717

1,191

4,830
Increase (Decrease) in cash and cash equivalents 263
(5,867 ) 4,624
Cash and cash equivalents at beginning of period 635
6,502
1,878
Cash and cash equivalents at end of period $ 898

$ 635

$ 6,502

See the Combined Notes to Consolidated Financial Statements

~~268~~120

Table of Contents

Exelon Corporation and Subsidiary Companies

Consolidated Balance Sheets


	December 31,
(In millions)	2022		2021
ASSETS
Current assets
Cash and cash equivalents	$	407	$	672
Restricted cash and cash equivalents	566		321

Accounts receivable
Customer accounts receivable	2,544		2,189
Customer allowance for credit losses	(327)		(320)
Customer accounts receivable, net	2,217		1,869
Other accounts receivable	1,426		1,068
Other allowance for credit losses	(82)		(72)
Other accounts receivable, net	1,344		996


Inventories, net
Fossil fuel	208		105
Materials and supplies	547		476

Regulatory assets	1,641		1,296


Other	406		387
Current assets of discontinued operations	—		7,835
Total current assets	7,336		13,957
Property, plant, and equipment (net of accumulated depreciation and amortization of $15,930 and $14,430 as of December 31, 2022 and 2021, respectively)	69,076		64,558
Deferred debits and other assets
Regulatory assets	8,037		8,224
Goodwill	6,630		6,630
Receivable related to Regulatory Agreement Units	2,897		—
Investments	232		250


Other	1,141		885
Property, plant, and equipment, deferred debits, and other assets of discontinued operations	—		38,509
Total deferred debits and other assets	18,937		54,498
Total assets	$	95,349	$	133,013

December 31,
(In millions) 2017 2016
ASSETS
Current assets
Cash and cash equivalents $ 898
$ 635
Restricted cash and cash equivalents 207
253
Deposit with IRS —
1,250
Accounts receivable, net
Customer 4,401
4,158
Other 1,132
1,201
Mark-to-market derivative assets 976
917
Unamortized energy contract assets 60
88
Inventories, net
Fossil fuel and emission allowances 340
364
Materials and supplies 1,311
1,274
Regulatory assets 1,267
1,342
Other 1,242
930
Total current assets 11,834

12,412
Property, plant and equipment, net 74,202
71,555
Deferred debits and other assets
Regulatory assets 8,021
10,046
Nuclear decommissioning trust funds 13,272
11,061
Investments 640
629
Goodwill 6,677
6,677
Mark-to-market derivative assets 337
492
Unamortized energy contract assets 395
447
Pledged assets for Zion Station decommissioning —
113
Other 1,322
1,472
Total deferred debits and other assets 30,664

30,937
Total assets^(a)
$ 116,700

$ 114,904

See the Combined Notes to Consolidated Financial Statements

~~269~~121


Title of Each Class
COMMONWEALTH EDISON COMPANY:
Common Stock Purchase Warrants (1971 Warrants and Series B Warrants)


~~Title of Each Class~~
~~COMMONWEALTH EDISON COMPANY:~~
~~Common Stock Purchase Warrants, 1971 Warrants and Series B Warrants~~
~~POTOMAC ELECTRIC POWER COMPANY:~~
~~Common Stock, $.01 par value~~
~~DELMARVA POWER & LIGHT COMPANY:~~
~~Common Stock, $2.25 par value~~
~~ATLANTIC CITY ELECTRIC COMPANY:~~
~~Common Stock, $3.00 par value~~



Exelon Corporation Common Stock, without par value		994,126,931		~~965,029,399~~
~~Exelon Generation Company, LLC~~			~~Not applicable~~
Commonwealth Edison Company Common Stock, $12.50 par value	127,021,394	~~127,021,256~~
PECO Energy Company Common Stock, without par value		170,478,507		~~170,478,507~~
Baltimore Gas and Electric Company Common Stock, without par value		1,000		~~1,000~~
Pepco Holdings LLC					Not applicable
Potomac Electric Power Company Common Stock, $0.01 par value		100		~~100~~
Delmarva Power & Light Company Common Stock, $2.25 par value		1,000		~~1,000~~
Atlantic City Electric Company Common Stock, $3.00 par value		8,546,017		~~8,546,017~~


						Page No.
GLOSSARY OF TERMS AND ABBREVIATIONS						1
FILING FORMAT						5
CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION						5
WHERE TO FIND MORE INFORMATION						5

PART I			~~Page No.~~
~~GLOSSARY OF TERMS AND ABBREVIATIONS~~ ITEM 1.			1BUSINESS			6
~~FILING FORMAT~~			General			6
~~CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION~~			6Utility Operations			7
~~WHERE TO FIND MORE INFORMATION~~			6Exelon's Strategy and Outlook			10

~~PART I~~
~~ITEM 1.~~	~~BUSINESS~~	7Employees			11
			~~General~~	7Environmental Matters and Regulation			13
			~~Exelon Generation Company, LLC~~	8
	~~Utility Operations~~	20
	~~Employees~~	24
	~~Environmental Regulation~~	25
	Executive Officers of the Registrants	3018
ITEM 1A.			RISK FACTORS			3622
ITEM 1B.			UNRESOLVED STAFF COMMENTS			6033
ITEM 2.			~~PROPERTIES~~	61PROPERTIES			34
			~~Exelon Generation Company, LLC~~
ITEM 3.			61LEGAL PROCEEDINGS			35
			~~Commonwealth Edison Company~~ ITEM 4.	65MINE SAFETY DISCLOSURES			35
PART II			~~PECO Energy Company~~			65
			~~Baltimore Gas and Electric Company~~ ITEM 5.	66
	~~Potomac Electric Power Company~~	67
	~~Delmarva Power & Light Company~~	68
	~~Atlantic City Electric Company~~	69
~~ITEM 3.~~	~~LEGAL PROCEEDINGS~~	70
~~ITEM 4.~~	~~MINE SAFETY DISCLOSURES~~	70
~~PART II~~
~~ITEM 5.~~	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES	7136
ITEM 6.			~~SELECTED FINANCIAL DATA~~	76[RESERVED]			40
			~~Exelon Corporation~~			76
	~~Exelon Generation Company, LLC~~	77
	~~Commonwealth Edison Company~~	77
	~~PECO Energy Company~~	78
	~~Baltimore Gas and Electric Company~~	79
	~~Pepco Holdings LLC~~	79
	~~Potomac Electric Power Company~~	80
	~~Delmarva Power & Light Company~~	81
	~~Atlantic City Electric Company~~	81



			~~Page No.~~





ITEM 7.			MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		8341
			Exelon Corporation		8341
			Executive Overview		8341
			Financial Results of Operations		8542
			Significant ~~2017~~202 2 Transactions and Recent Developments		9245
			~~Exelon's Strategy and Outlook for 2018 and Beyond~~		99
			~~Liquidity Considerations~~	~~100~~
	Other Key Business Drivers and Management Strategies	~~101~~48
			Critical Accounting Policies and Estimates		~~107~~49
			Results of Operations		~~124~~56
			~~Exelon Generation Company, LLC~~	~~125~~Commonwealth Edison Company		56
			~~Commonwealth Edison Company~~	~~137~~PECO Energy Company		59
			~~PECO Energy Company~~	~~145~~
	Baltimore Gas and Electric Company	~~152~~63
			Pepco Holdings LLC		~~159~~66
			Potomac Electric Power Company		~~162~~67
			Delmarva Power & Light Company		~~169~~70
			Atlantic City Electric Company		~~178~~74
			Liquidity and Capital Resources		~~185~~77
			~~Contractual Obligations and Off-Balance Sheet Arrangements~~		~~208~~
ITEM 7A.			QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		~~216~~93
			~~Exelon Corporation~~		~~216~~
	~~Exelon Generation Company, LLC~~	~~226~~
	~~Commonwealth Edison Company~~	~~228~~
	~~PECO Energy Company~~	~~230~~
	~~Baltimore Gas and Electric Company~~	~~232~~
	~~Pepco Holdings LLC~~	~~234~~
	~~Potomac Electric Power Company~~	~~236~~
	~~Delmarva Power & Light Company~~	~~238~~
	~~Atlantic City Electric Company~~	~~240~~



			~~Page No.~~





ITEM 8.			FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA		~~242~~95
			Exelon Corporation		~~267~~119
			~~Exelon Generation Company, LLC~~	~~272~~Commonwealth Edison Company		124
			~~Commonwealth Edison Company~~	~~277~~
	PECO Energy Company	~~282~~129



ý			☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934



¨			☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934



Exelon Corporation Common Stock, without par value		$~~34,604,071,959~~44,452,390,343
~~Exelon Generation Company, LLC~~	~~Not applicable~~
Commonwealth Edison Company Common Stock, $12.50 par value	No established market
PECO Energy Company Common Stock, without par value		None
Baltimore Gas and Electric Company, without par value		None
Pepco Holdings LLC		Not applicable
Potomac Electric Power Company		None
Delmarva Power & Light Company		None
Atlantic City Electric Company		None


					Page No.
			Baltimore Gas and Electric Company		~~287~~134
			Pepco Holdings LLC		~~292~~139
			Potomac Electric Power Company		~~297~~144
			Delmarva Power & Light Company		~~302~~149
			Atlantic City Electric Company		~~307~~154
			Combined Notes to Consolidated Financial Statements		~~312~~159
			1. Significant Accounting Policies		~~312~~159
			~~2. Variable Interest Entities~~	~~330~~2. Discontinued Operations		166

			3. Regulatory Matters		~~341~~171
			~~4. Mergers, Acquisitions and Dispositions~~	~~376~~4. Revenue from Contracts with Customers		190
			~~5. Accounts Receivable~~	~~387~~5. Segment Information		192
			6. Accounts Receivable		199
			7. Property, Plant, and Equipment		~~388~~201
			~~7. Impairment of Long-Lived Assets and Intangibles~~	~~394~~
	8. ~~Early Nuclear Plant Retirements~~	~~396~~
	9. Jointly Owned Electric Utility Plant	~~400~~203
			~~10. Intangible Assets~~	~~401~~9. Asset Retirement Obligations		203
			10. Leases		204
			11. Asset Impairments		209
			12. Intangible Assets		209
			13. Income Taxes		211
			14. Retirement Benefits		218
			15. Derivative Financial Instruments		230
			16. Debt and Credit Agreements		233
			17. Fair Value of Financial Assets and Liabilities		~~407~~241
			~~12. Derivative Financial Instruments~~	~~431~~18. Commitments and Contingencies		248
			~~13. Debt and Credit Agreements~~
			~~447~~19. Shareholders' Equity		256
			~~14. Income Taxes~~	~~460~~
	~~15. Asset Retirement Obligations~~	~~476~~
	~~16. Retirement Benefits~~	~~484~~
	~~17. Severance~~	~~505~~
	~~18. Mezzanine Equity~~	~~508~~
	~~19. Shareholders' Equity~~	~~509~~
	20. Stock-Based Compensation Plans	~~510~~257
			~~21. Earnings Per Share~~	~~517~~
	~~22.~~21. Changes in Accumulated Other Comprehensive Income	~~518~~261
			~~23. Commitments and Contingencies~~	~~522~~22. Supplemental Financial Information		262
			~~24. Supplemental Financial Information~~	~~539~~23. Related Party Transactions		267
			~~25. Segment Information~~		~~552~~
			~~26. Related Party Transactions~~		~~560~~
			~~27. Quarterly Data~~ ITEM 9.	~~573~~
	~~28. Subsequent Events~~	~~576~~
~~ITEM 9.~~	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	~~578~~271
ITEM 9A.			CONTROLS AND PROCEDURES		~~578~~271
ITEM 9B.			OTHER INFORMATION		~~579~~271

DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS			271


			~~Page No.~~
~~PART III~~


					Page No.
PART III
ITEM 10.			DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE		~~580~~272
ITEM 11.			EXECUTIVE COMPENSATION		~~581~~273
ITEM 12.			SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS		~~582~~274
ITEM 13.			CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE		~~583~~275
ITEM 14.			PRINCIPAL ACCOUNTING FEES AND SERVICES		~~584~~276
PART IV
ITEM 15.			EXHIBITS, FINANCIAL STATEMENT SCHEDULES		~~585~~277
~~ITEM 16.~~	~~FORM 10-K SUMMARY~~	~~641~~
~~SIGNATURES~~ITEM 16.			~~642~~FORM 10-K SUMMARY		319
					~~Exelon Corporation~~ SIGNATURES	~~642~~320
			~~Exelon Generation Company, LLC~~	~~643~~Exelon Corporation		320
			Commonwealth Edison Company		~~644~~321
			PECO Energy Company		~~645~~322
			Baltimore Gas and Electric Company		~~646~~323
			Pepco Holdings LLC		~~647~~324
			Potomac Electric Power Company		~~648~~325
			Delmarva Power & Light Company		~~649~~326
			Atlantic City Electric Company		~~650~~327



GLOSSARY OF TERMS AND ABBREVIATIONS
Exelon Corporation and Related Entities
Exelon			Exelon Corporation
~~Generation~~ComEd			~~Exelon Generation Company, LLC~~
~~ComEd~~	Commonwealth Edison Company
PECO			PECO Energy Company
BGE			Baltimore Gas and Electric Company
Pepco Holdings or PHI			Pepco Holdings LLC (formerly Pepco Holdings, Inc.)
Pepco			Potomac Electric Power Company
DPL			Delmarva Power & Light Company
ACE			Atlantic City Electric Company
Registrants			Exelon, ~~Generation,~~ ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE, collectively
Utility Registrants			ComEd, PECO, BGE, Pepco, DPL, and ACE, collectively
Legacy PHI			PHI, Pepco, DPL, ACE, PES, and PCI, collectively
~~ACE Funding or ATF~~BSC			~~Atlantic City Electric Transition Funding LLC~~
~~Antelope Valley~~	~~Antelope Valley Solar Ranch One~~
~~BondCo~~	~~RSB BondCo LLC~~
~~BSC~~	Exelon Business Services Company, LLC
~~CENG~~EEDC			~~Constellation Energy Nuclear Group, LLC~~
~~ConEdison Solutions~~	~~The competitive retail electricity and natural gas business of Consolidated Edison Solutions, Inc., a subsidiary of Consolidated Edison, Inc~~
~~Constellation~~	~~Constellation Energy Group, Inc.~~
~~EEDC~~	Exelon Energy Delivery Company, LLC
~~EGR IV~~		~~ExGen Renewables IV, LLC~~
~~EGTP~~	~~ExGen Texas Power, LLC~~
~~Entergy~~	~~Entergy Nuclear FitzPatrick, LLC~~
Exelon Corporate		Exelon in its corporate capacity as a holding company
Exelon ~~Transmission Company~~Enterprises			Exelon ~~Transmission~~Enterprises Company, LLC
Exelon ~~Wind~~Foundation			~~Exelon Wind, LLC and Exelon Generation Acquisition Company, LLC~~Independent, non-profit philanthropic organization
~~FitzPatrick~~Exelon InQB8R			~~James A. FitzPatrick nuclear generating station~~Exelon InQB8R, LLC
PCI			Potomac Capital Investment Corporation and its subsidiaries
PEC L.P.			PECO Energy Capital, L.P.
PECO Trust III			PECO Energy Capital Trust III
PECO Trust IV			PECO Energy Capital Trust IV
Pepco Energy Services or PES			Pepco Energy Services, Inc. and its subsidiaries
PHI Corporate			PHI in its corporate capacity as a holding company
PHISCO			PHI Service Company
~~RPG~~UII			~~Renewable Power Generation~~
~~SolGen~~	~~SolGen, LLC~~
~~TMI~~	~~Three Mile Island nuclear facility~~
~~UII~~	Unicom Investments, Inc.


Former Related Entities
Constellation						Constellation Energy Corporation
Generation or CEG						Constellation Energy Generation, LLC (formerly Exelon Generation Company, LLC, a subsidiary of Exelon as of December 31, 2021 prior to separation on February 1, 2022)


CENG						Constellation Energy Nuclear Group, LLC


FitzPatrick						James A. FitzPatrick nuclear generating station
EDF						Electricite de France SA and its subsidiaries


GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
~~AEC~~2021 Form 10-K			The Registrants' Annual Report on Form 10-K for the year ended December 31, 2021 filed with the SEC on February 25, 2022
2021 Recast Form 10-K			The Registrants' Current Report on Form 8-K filed with the SEC on June 30, 2022 to recast Exelon's consolidated financial statements and certain other financial information originally included in the 2021 Form 10-K
Note - of the 2021 Recast Form 10-K			Reference to specific Combined Note to Consolidated Financial Statements in the 2021 Recast Form 10-K
ABO			Accumulated Benefit Obligation
AECs			Alternative Energy ~~Credit~~Credits that isare issued for each megawatt hour of generation from a qualified alternative energy source
~~AESO~~AFUDC			~~Alberta Electric Systems Operator~~
~~AFUDC~~	Allowance for Funds Used During Construction
~~AGE~~AMI			~~Albany Green Energy Project~~
~~AMI~~	Advanced Metering Infrastructure
~~AMP~~AOCI			~~Advanced Metering Program~~
~~AOCI~~	Accumulated Other Comprehensive Income (Loss)
~~ARC~~ARO			~~Asset Retirement Cost~~
~~ARO~~	Asset Retirement Obligation
ARP			Alternative Revenue Program
~~CAISO~~			~~California ISO~~
~~CAP~~BGS			~~Customer Assistance Program~~Basic Generation Service
~~CCGTs~~BSA			~~Combined-Cycle gas turbines~~Bill Stabilization Adjustment
~~CERCLA~~CBAs			Collective Bargaining Agreements
CEJA (formerly Clean Energy Law in the Exelon 2021 Form 10-K)			Climate and Equitable Jobs Act; Illinois Public Act 102-0662 signed into law on September 15, 2021
CERCLA			Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended
~~CES~~CIP			~~Clean Energy Standard~~Conservation Incentive Program
Clean Air Act			Clean Air Act of 1963, as amended
Clean Water Act			Federal Water Pollution Control Amendments of 1972, as amended
~~Conectiv~~CMC			Carbon Mitigation Credit
CODMs			Chief Operating Decision Makers
Conectiv			Conectiv, LLC, a wholly owned subsidiary of PHI and the parent of DPL and ACE during the Predecessor periods
~~Conectiv Energy~~DC PLUG			~~Conectiv Energy Holdings, Inc. and substantially all of its subsidiaries, which were sold to Calpine in July 2010~~
~~CSAPR~~	~~Cross-State Air Pollution Rule~~
~~CTA~~	~~Consolidated tax adjustment~~
~~D.C. Circuit Court~~	~~United States Court of Appeals for the~~ District of Columbia ~~Circuit~~Power Line Undergrounding Initiative
DCPSC			District of Columbia Public Service Commission
~~Default Electricity Supply~~			The supply of electricity by PHI’s electric utility subsidiaries at regulated rates to retail customers who do not elect to purchase electricity from a competitive supplier, and which, depending on the jurisdiction, is also known as Standard Offer Service or BGS
~~DOE~~DEPSC			~~United States Department of Energy~~
~~DOJ~~	~~United States Department of Justice~~
~~DPSC~~	Delaware Public Service Commission
~~DRP~~			~~Direct Stock Purchase and Dividend Reinvestment Plan~~
~~DSP~~DOEE			Department of Energy & Environment

DPA			Deferred Prosecution Agreement
DPP			Deferred Purchase Price

DSIC			Distribution System Improvement Charge
DSP			Default Service Provider
~~DSP Program~~			~~Default Service Provider Program~~
~~EDF~~EIMA			~~Electricite de France SA and its subsidiaries~~
~~EE&C~~	~~Energy Efficiency and Conservation/Demand Response~~
~~EIMA~~	Energy Infrastructure Modernization Act (Illinois Senate Bill 1652 and Illinois House Bill 3036)
~~EmPower Maryland~~EPA			~~A Maryland demand-side management program for Pepco and DPL~~
~~EPA~~	United States Environmental Protection Agency
~~EPSA~~		~~Electric Power Supply Association~~


ERCOT
~~GLOSSARY OF TERMS AND ABBREVIATIONS~~
~~Other Terms and Abbreviations~~
~~ERCOT~~	Electric Reliability Council of Texas
ERISA		Employee Retirement Income Security Act of 1974, as amended
EROA		Expected Rate of Return on Assets
~~ESPP~~		~~Employee Stock Purchase Plan~~
~~FASB~~ERP		~~Financial Accounting Standards Board~~Enterprise Resource Program
~~FEJA~~ETAC		Energy Transition Assistance Charge

FEJA		Illinois Public Act 99-0906 or Future Energy Jobs Act
FERC		Federal Energy Regulatory Commission
~~FRCC~~		~~Florida Reliability Coordinating Council~~
GAAP		Generally Accepted Accounting Principles in the United States
GCR		Gas Cost Rate



~~Type of Capacity~~	MW
~~Owned generation assets~~^(a)(b)
~~Nuclear~~	~~20,310~~
~~Fossil (primarily natural gas and oil)~~	~~11,723~~
~~Renewable~~^(c)	~~3,135~~
~~Owned generation assets~~^(e)	~~35,168~~
~~Long-term power purchase contracts~~^(d)	~~5,285~~
~~Total generating resources~~	~~40,453~~


~~GHG~~			~~Greenhouse Gas~~GLOSSARY OF TERMS AND ABBREVIATIONS
~~GSA~~Other Terms and Abbreviations
GHG		Greenhouse Gas
GSA		Generation Supply Adjustment
~~GWh~~GWhs		Gigawatt ~~hour~~hours
~~IBEW~~ICC		~~International Brotherhood of Electrical Workers~~
~~ICC~~	Illinois Commerce Commission
~~ICE~~		~~Intercontinental Exchange~~
~~Illinois EPA~~IIP		~~Illinois Environmental Protection Agency~~Infrastructure Investment Program
Illinois Settlement Legislation		Legislation enacted in 2007 affecting electric utilities in Illinois
~~Integrys~~IPA		~~Integrys Energy Services, Inc.~~
~~IPA~~	Illinois Power Agency
IRC		Internal Revenue Code
IRS		Internal Revenue Service
~~ISO~~ISOs		Independent System ~~Operator~~Operators
~~ISO-NE~~		~~ISO New England Inc.~~
~~ISO-NY~~	~~ISO New York~~
kV	~~Kilovolt~~
kW	~~Kilowatt~~
~~kWh~~	~~Kilowatt-hour~~
~~LIBOR~~	~~London Interbank Offered Rate~~
~~LLRW~~	~~Low-Level Radioactive Waste~~
~~LT Plan~~	~~Long-Term renewable resources procurement plan~~
~~LTIP~~	~~Long-Term Incentive Plan~~
~~MAPP~~	~~Mid-Atlantic Power Pathway~~
~~MATS~~	~~U.S. EPA Mercury and Air Toxics Rule~~
~~MBR~~	~~Market Based Rates Incentive~~
~~MDE~~	~~Maryland Department of the Environment~~
~~MDPSC~~	~~Maryland Public Service Commission~~
~~MGP~~	~~Manufactured Gas Plant~~
~~MISO~~	~~Midcontinent Independent System Operator, Inc.~~
~~mmcf~~	~~Million Cubic Feet~~
~~Moody’s~~	~~Moody’s Investor Service~~
~~MOPR~~	~~Minimum Offer Price Rule~~



~~GLOSSARY OF TERMS AND ABBREVIATIONS~~LIBOR		London Interbank Offered Rate
~~Other Terms and Abbreviations~~LNG		Liquefied Natural Gas
~~MRV~~		~~Market-Related Value~~
MWLTIP		~~Megawatt~~Long-Term Incentive Plan
~~MWh~~LTRRPP		~~Megawatt hour~~Long-Term Renewable Resources Procurement Plan
~~n.m.~~		~~not meaningful~~
~~NAAQS~~MDPSC		~~National Ambient Air Quality Standards~~Maryland Public Service Commission
~~NAV~~MGP		Manufactured Gas Plant
mmcf		Million Cubic Feet
MRP		Multi-Year Rate Plan
MRV		Market-Related Value
MW		Megawatt
MWh		Megawatt hour
N/A		Not applicable
NAV		Net Asset Value
NDT		Nuclear Decommissioning Trust
~~NEIL~~NERC		~~Nuclear Electric Insurance Limited~~
~~NERC~~	North American Electric Reliability Corporation
~~NGS~~NJBPU		~~Natural Gas Supplier~~
~~NJBPU~~	New Jersey Board of Public Utilities
~~NJDEP~~		~~New Jersey Department of Environmental Protection~~
~~Non-Regulatory Agreements Units~~		~~Nuclear generating units or portions thereof whose decommissioning-related activities are not subject to contractual elimination under regulatory accounting~~
~~NOSA~~NPDES		~~Nuclear Operating Services Agreement~~
~~NPDES~~	National Pollutant Discharge Elimination System
~~NRC~~NPNS		~~Nuclear Regulatory Commission~~Normal Purchase Normal Sale scope exception
~~NSPS~~NPS		~~New Source Performance Standards~~National Park Service
~~NUGs~~NRD		~~Non-utility generators~~Natural Resources Damages
~~NWPA~~OCI		~~Nuclear Waste Policy Act of 1982~~
~~NYMEX~~	~~New York Mercantile Exchange~~
~~NYPSC~~	~~New York Public Service Commission~~
~~OCI~~	Other Comprehensive Income
~~OIESO~~OPEB		~~Ontario Independent Electricity System Operator~~
~~OPC~~	~~Office of People’s Counsel~~
~~OPEB~~	Other Postretirement Employee Benefits
~~PA DEP~~		~~Pennsylvania Department of Environmental Protection~~
PAPUC		Pennsylvania Public Utility Commission
~~PGC~~PCBs		Polychlorinated Biphenyls
PGC		Purchased Gas Cost Clause
PJM		PJM Interconnection, LLC
~~POLR~~PJM Tariff		PJM Open Access Transmission Tariff
POLR		Provider of Last Resort
~~POR~~PPA		Purchase ~~of Receivables~~Power Agreement
~~PPA~~PP&E		~~Power Purchase Agreement~~Property, Plant, and Equipment
~~Price-Anderson Act~~PRPs		~~Price-Anderson Nuclear Industries Indemnity Act of 1957~~
~~Preferred Stock~~	~~Originally issued shares of non-voting, non-convertible and non-transferable Series A preferred stock, par value $0.01 per share~~
~~PRP~~	Potentially Responsible Parties
PSEG		Public Service Enterprise Group Incorporated
PV		~~Photovoltaic~~
RCRA		Resource Conservation and Recovery Act of 1976, as amended
REC		Renewable Energy Credit which is issued for each megawatt hour of generation from a qualified renewable energy source


~~RES~~GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
RES		Retail Electric Suppliers
RFP		Request for Proposal
Rider		Reconcilable Surcharge Recovery Mechanism
RGGI		Regional Greenhouse Gas Initiative
~~RMC~~		~~Risk Management Committee~~
ROE		Return on equity
~~RPM~~ROU		~~PJM Reliability Pricing Model~~Right-of-use
RPS		Renewable Energy Portfolio Standards
~~RSSA~~RTEP		~~Reliability Support Services Agreement~~
~~RTEP~~	Regional Transmission Expansion Plan
RTO		Regional Transmission Organization
S&P		Standard & Poor’s Ratings Services
SEC		United States Securities and Exchange Commission
~~Senate Bill 1~~SOA		~~Maryland Senate Bill 1~~Society of Actuaries
~~SERC~~SOFR		~~SERC Reliability Corporation (formerly Southeast Electric Reliability Council)~~Secured Overnight Financing Rate
~~SGIG~~SOS		~~Smart Grid Investment Grant from DOE~~
~~SILO~~	~~Sale-In, Lease-Out~~
~~SNF~~	~~Spent Nuclear Fuel~~
~~SOS~~	Standard Offer Service
~~SPFPA~~SSA		Social Security ~~Police and Fire Professionals of America~~Administration
~~SPP~~STRIDE		~~Southwest Power Pool~~Maryland Strategic Infrastructure Development and Enhancement Program
TCJA		Tax Cuts and Jobs Act
~~Transition Bond Charge~~		~~Revenue ACE receives, and pays to ACE Funding, to fund the principal and interest payments on Transition Bonds and related taxes, expenses and fees~~
Transition Bonds		Transition Bonds issued by ~~ACE~~Atlantic City Electric Transition Funding LLC
~~Upstream~~U.S. Court of Appeals for the D.C. Circuit		~~Natural gas and oil exploration and production activities~~United States Court of Appeals for the District of Columbia Circuit
~~VIE~~ZEC		~~Variable Interest Entity~~
~~WECC~~	~~Western Electric Coordinating Council~~
~~ZEC~~	Zero Emission Credit
~~ZES~~	~~Zero Emission Standard~~


~~(a)~~	~~See “Fuel” for sources of fuels used in electric generation.~~


~~(c)~~	~~Includes wind, hydroelectric and solar generating assets.~~


~~(d)~~	~~Electric supply procured under site specific agreements.~~


~~(e)~~	Includes EGTP generating assets that were deconsolidated from Generation's consolidated financial statements. See Note 4 — Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information.



Station	Unit	In-Service Date^(a)	Current License Expiration
Braidwood	1	1988	2046
	2	1988	2047
Byron	1	1985	2044
	2	1987	2046
Calvert Cliffs	1	1975	2034
	2	1977	2036
Clinton^(b)	1	1987	2026
Dresden	2	1970	2029
	3	1971	2031
FitzPatrick	1	1974	2034
LaSalle	1	1984	2042
	2	1984	2043
Limerick	1	1986	2044
	2	1990	2049
Nine Mile Point	1	1969	2029
	2	1988	2046
Oyster Creek^(c)	1	1969	2029
Peach Bottom^(d)	2	1974	2033
	3	1974	2034
Quad Cities	1	1973	2032
	2	1973	2032
Ginna	1	1970	2029
Salem	1	1977	2036
	2	1981	2040
Three Mile Island^(e)	1	1974	2034


~~(a)~~	~~Denotes year in which nuclear unit began commercial operations.~~


~~(b)~~	Although timing has been delayed, Generation currently plans to seek license renewal for Clinton and has advised the NRC that any license renewal application would not be filed until the first quarter of 2021.


~~(c)~~	Generation had previously announced and notified the NRC that it will permanently cease generation operations at Oyster Creek by the end of 2019. On February 2, 2018, Exelon announced that Generation will permanently cease generation operations at Oyster Creek at the end of its current operating cycle in October 2018.


~~(d)~~	~~On June 7, 2016, Generation announced that it will submit a second 20-year license renewal application to NRC for Peach Bottom Units 2 and 3 in 2018.~~


~~(e)~~	~~On May 30, 2017, Exelon announced that Generation will permanently cease generation operations at TMI on or about September 30, 2019 and has notified the NRC.~~


	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


			Approval Date
ComEd			January 2008
PECO			December 2019
BGE			April 2006
Pepco			April 2006
DPL			April 2006
ACE			April 2006


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


	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



Region	Number of Agreements	Expiration Dates	Capacity (MW)
Mid-Atlantic	14	2019 - 2032	237
Midwest	4	2019 - 2026	834
New England	7	2018	40
ERCOT	5	2020 - 2031	1,524
Other Power Regions	12	2018 - 2030	2,650
Total	42		5,285

~~GLOSSARY OF TERMS AND ABBREVIATIONS~~

~~Other Terms and Abbreviations~~

Regulatory Agreement Units

Nuclear generating units or portions thereof whose decommissioning-related activities are subject to ~~contractual elimination under~~ regulatory ~~accounting~~agreements with the ICC and PAPUC